2012 Annual Report
On Our Way
Exterran Holdings, Inc.
www.exterran.com
Last year, the people of Exterran focused on driving signifi cant and lasting
performance improvement. Our promising results in 2012, including a return
in the second half of the year to positive earnings per share from continuing
operations, excluding charges, demonstrate that we are on our way.
Directors
Gordon T. Hall
Chairman of the Board
Mark R. Sotir
Executive Vice Chairman
Uriel E. Dutton
William C. Pate
J.W.G. “Will” Honeybourne
Stephen M. Pazuk
Mark A. McCollum
Christopher T. Seaver
18%Increase in EBITDA
EBITDA, as adjusted, increased by 18%
on 7% growth in revenues, supported
by improved gross margins in all four of
our business segments
2.4xTotal Leverage
Exterran Holdings’ covenant total leverage
ratio declined from 4.3x to 2.4x by year
end, as a result of reduced debt levels
and increased EBITDA
Executive Offi cers
D. Bradley Childers
President and Chief Executive Offi cer
William M. Austin
Executive Vice President and
Chief Financial Offi cer
Joseph G. Kishkill
Senior Vice President
President, Eastern Hemisphere
Chris Michel
Senior Vice President,
Global Human Resources
Ronaldo Reimer
Senior Vice President
President, Latin America
Rob Rice
Senior Vice President
President, North America
Daniel K. Schlanger
Senior Vice President,
Operations Services
Donald C. Wayne
Senior Vice President,
General Counsel and Secretary
Kenneth R. Bickett
Vice President
Corporate Controller
Corporate Information
Annual Meeting
The 2013 Annual Meeting of Stockholders will be held April 30,
2013, at 11:30 a.m. central time, at Exterran’s Corporate Offi ce.
Stock Trading
New York Stock Exchange symbol: EXH
Stockholder Information Website
Additional information on Exterran, including securities
fi lings, press releases, Code of Business Conduct, Corporate
Governance Principles and Board Committee Charters, is
available on our website at www.exterran.com.
Transfer Agent-Registrar
American Stock Transfer and Trust Company
59 Maiden Lane
Plaza Level
New York, New York 10038 USA
(800) 937-5449 or (718) 921-8200
Independent Registered Public Accounting Firm
Deloitte & Touche LLP
Houston, Texas USA
Corporate Offi ce
16666 Northchase Drive
Houston, Texas 77060 USA
(281) 836-7000
On the cover: Chance Huron, Senior Emissions Technician
10-K/Investor Contact
Stockholders may obtain a copy, without charge, of Exterran’s 2012
Form 10-K, fi led with the Securities and Exchange Commission, by
visiting our website at www.exterran.com or by requesting a copy
in writing to investor.relations@exterran.com or Exterran’s
Corporate Offi ce, Attention: Investor Relations.
The certifi cations by our Chief Executive Offi cer and Chief Financial
Offi cer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
are fi led as exhibits to our 2012 Form 10-K. We have also fi led with
the New York Stock Exchange the written affi rmation certifying
that we are not aware of any violations by Exterran of NYSE
Corporate Governance Listing Standards.
Contact Board of Directors
To report a concern about Exterran’s accounting, internal controls
or auditing matters, or any other matter, to the Audit Committee
or non-management members of the Board of Directors, send a
detailed note, with relevant documents, to Exterran’s Corporate
Offi ce, Attention: Gordon T. Hall, Chairman of the Board, or leave
a message at 1-800-281-5439 (U.S. and Canada) or 1-832-554-4859
(outside U.S. and Canada), request reverse charges.
Forward-Looking Statements
Certain statements contained in this Annual Report may constitute
forward-looking statements within the meaning of the Private
Securities Litigation Reform Act of 1995. These statements
involve a number of risks, uncertainties and other factors that
could cause actual results to be materially different, as discussed
more fully elsewhere in this Annual Report and in our fi lings
with the Securities and Exchange Commission, including our
2012 Form 10-K fi led on February 26, 2013. Except as required
by law, we expressly disclaim any intention or obligation to revise
or update any forward-looking statements whether as a result of
new information, future events or otherwise.
38%Increase in profitability
Better pricing and cost discipline led to a 38%
increase in gross margin dollars and record
revenues for aftermarket services
45%Increase in backlog
Fabrication bookings were up globally and our
backlog grew by 45%, which included record
U.S. sales for production and processing and
treating equipment
117K
Increase in HP
Contract operations increased working horse-
power by 117,000, a second year of increases
for North America and a return to growth for
International
Exterran Holdings, Inc. is a global market leader in full service natural gas compression
and a premier provider of operations, maintenance, service and equipment for oil and natural
gas production, processing and transportation applications. Exterran serves customers
across the energy spectrum – from producers to transporters to processors to storage
owners. Headquartered in Houston, Texas, Exterran operates in approximately 30 countries.
Exterran Holdings owns an equity interest in Exterran Partners, L.P., a master limited
partnership and the leading provider of natural gas contract operations services to
customers throughout the United States. For more information, visit www.exterran.com.
Financial Highlights
(Dollars in thousands, except per share amounts)
2012
2011
2010
Years Ended December 31,
Revenues:
North America contract operations
International contract operations
Aftermarket services
Fabrication
Total revenues
Gross margin (1)
EBITDA, as adjusted (1)
$ 605,367
$ 588,034
$ 592,055
463,957
385,861
445,059
371,327
465,144
293,757
1,348,417
1,225,459
1,066,227
2,803,602
2,629,879
2,417,183
834,223
464,840
728,427
395,441
797,088
445,385
(101,825)
(2.30)
4,741,536
1,897,147
1,609,448
729,671
Net loss attributable to Exterran stockholders
(39,486)
(340,608)
Loss per share attributable to Exterran stockholders – diluted
(1.68)
(5.28)
Total assets
Total debt
Total Exterran stockholders’ equity
Fabrication backlog
4,254,847
1,564,923
1,478,613
1,065,714
4,360,662
1,773,039
1,437,236
735,268
(1) See the discussion of Non-GAAP Financial Measures beginning on page 40 of our accompanying 2012 Form 10-K for information on gross margin and EBITDA, as adjusted.
2
2
Exterran Holdings 2012 Annual Report
Exterran Holdings 2012 Annual Report
Our Products and Services
Gas Compression
Exterran is a global market leader in natural gas contract compression with 3.9 million
operating horsepower around the world. In addition to contract operations services, we
offer new-build compression packages, used compression packages and components and
air quality management services.
Production Equipment
Our clients use Exterran production equipment in onshore and offshore operations to treat and
process natural gas and oil after it is extracted from the ground. Examples include equipment
used for separation, dehydration, gas conditioning, oil treating and conditioning, filtration and
air emissions control.
Gas Processing
Exterran is a leader in the engineering, manufacturing and installation of modular, skid-mounted
gas processing equipment. This equipment includes natural gas liquids extraction plants,
dewpoint control equipment and gas treatment to remove carbon dioxide and hydrogen sulfide.
Exterran’s vast offerings include standard and flexible engineering designs for refrigeration and
cryogenic, amine, dehydration, sulfur recovery, hydrocarbon recovery and liquid fractionation plants.
Aftermarket Parts and Services
Exterran supplies new, used, remanufactured, OEM and aftermarket parts and equipment for
maintenance, repair and overhaul of oil and gas equipment. Our experienced, factory-trained
technicians work from fully equipped, well-stocked service vehicles and are backed by main-
tenance and fabrication shops capable of engine repairs, engine overhauls and repairing and
fabricating piping and vessels of all types and sizes.
Water Treatment
Exterran offers produced water management solutions for oil and gas production facilities. We
design and supply systems and services for safe, environmentally sound produced water treat-
ment for disposal or re-use. Our products are designed for primary oil-water separation, induced
gas flotation and tertiary filtration.
Air Emissions Services
Exterran offers a full range of air emissions services that include compliance assessment,
permitting, testing, maintenance and records management to ensure compression operations
remain compliant. We provide leak detection and repair services and a proprietary engine
management system to track all data and changes related to gas compression equipment
and emission control equipment installation.
Critical Process Equipment
Exterran provides engineering, procurement and fabrication services related to the manufactur-
ing of critical process equipment for refinery and petrochemical facilities, the fabrication of tank
farms and the fabrication of evaporators and brine heaters for desalination plants.
Project Integration Services
Exterran offers complete turnkey production and processing facilities that incorporate in-house
process design, engineering, procurement, fabrication, installation, operation, maintenance and fi-
nancing. We combine our broad range of pre-engineered, modular, process products and systems
with extensive technical, project and construction management and field service resources.
Exterran Holdings 2012 Annual Report
3
To Our Stakeholders
At Exterran, we are committed to driving the
significant performance improvement that
will create long-term value for our stockhold-
ers and profitable growth for years to come.
During 2012, we made steady progress
toward those goals by delivering on our
plans to increase the operating and capital
Gordon T. Hall
Chairman of the Board
Brad Childers
President and Chief Executive Officer
efficiency of our operations. As a result, both
Exterran Holdings and Exterran Partners generated improved operating results on a year-over-
year basis.
2012 EXTERRAN HOLDINGS HIGHLIGHTS
› We achieved an 18 percent increase in EBITDA, as adjusted, on a 7 percent increase in revenue.1
› Each of our four business segments generated improved revenues and gross margin percent-
age on a year-over-year basis.1
› We returned to positive earnings per share from continuing operations, excluding charges,
during the last two quarters of the year.
› We utilized our EBITDA growth and cash flow generation to lower our debt excluding Exterran
Partners by $343 million, significantly reducing covenant leverage at the Exterran Holdings
level from 4.3x at year-end 2011 to 2.4x at year-end 2012.
We accomplished these results while continuing our focus on excellent customer service and
providing a safe working environment for our employees. Our equipment run times exceeded
our service targets across the globe, and our overall safety performance beat our TRIR target.
2012 EXTERRAN PARTNERS HIGHLIGHTS
Exterran Partners, the master limited partnership in which we own an equity interest, also bene-
fited from the implementation of Exterran’s initiatives to improve operating efficiency and reduce
costs, while generating growth through both organic opportunities and further execution of our
drop-down strategy. During 2012, the Partnership:
› Achieved a 31 percent increase in distributable cash flow, a 26 percent increase in revenue
and a gross margin percentage increase to 53 percent in 2012.2
4
Exterran Holdings 2012 Annual Report
› Completed a drop down of compression and processing assets valued at $183 million.
› Invested $102 million in new units to capitalize on the organic demand for compression in the
United States while further standardizing equipment and improving the fl eet’s competitiveness.
With a leading market position, encouraging energy trends in the United States and ongoing
activities to improve performance, we are optimistic about the long-term outlook for Exterran
Partners. We believe the operating improvements we are making in our North American
contract operations business will reduce and potentially eliminate the need for
operating cost caps provided by Exterran Holdings in the future.
Additionally, our goal is to continue to grow the Partnership through
organic growth related to the strong U.S. market fundamentals and
further acquistitions from Exterran Holdings and third parties.
DRIVING MOMENTUM
Exterran exited 2012 with good momentum. We plan to build on that
energy during the coming year both by capitalizing on the substantial
growth opportunities we see in the markets for our products and
services and by maintaining our focus on improving the profi tability
of our businesses to become more competitive.
We are committed
to driving growth
while focusing
on delivering the
capital effi ciency
and operational
improvements that
will yield improved
performance not
only for 2013, but
for years to come.
We expect the North America markets will continue to have strong
demand for all of our products and services, driven by the growing
need for infrastructure development in the liquids-rich and shale plays. In North American
contract operations, we increased working horsepower by 70,000 in 2012, our second consec-
utive year of growth. In 2013, we plan to add approximately 170,000 horsepower of new fl eet
units in the United States to meet the increasing demand for compression services, including
larger units for gathering applications as well as smaller units used in gas-lift applications. Our
U.S. orders for production equipment and processing and treating products were at record
levels in 2012. To serve that increasing demand, we are adding a production equipment
fabrication facility in northeast Ohio and expanding the capacity of our existing production
equipment and process treating fabrication facilities through increased workforce
productivity and modest capital improvements.
Outside North America, we expect improved demand for our products and services in 2013 in
Latin America, the former Soviet states and the Middle East, signaling the front end of what
we believe is a recovery in international markets. We expect to book new projects in 2013 that
Exterran Holdings 2012 Annual Report
5
will continue to drive growth in our contract operations business. Activity levels in international
fabricated products, traditionally a growth market for Exterran, steadily increased through
2012, a trend we expect to continue during 2013.
Last year, our focus on better pricing and cost discipline in the aftermarket services business
resulted in the segment’s highest levels of revenue and profitability in company history. We
believe this progress will continue to provide benefits in 2013 and hope to grow this segment
of our business in both North America and internationally.
FOCUS ON THE LONG RUN
In 2013, we are implementing major process-driven initiatives to continue to improve the effi-
ciency of both our field service and fabrication operations. These efforts build on the improve-
ments we achieved in 2012 and focus on increasing the standardization of our work and
improving our work processes. While we expect these efforts will deliver continuous improve-
ment and results in 2013, they have the potential to make even more significant contributions
to our performance in 2014 and beyond.
We are confident that the global markets for our products and services will allow us to con-
tinue to grow in 2013. We are proud of the substantial progress we have made in improving
Exterran’s performance, but we are far from finished with this work. We are committed to
driving growth while focusing on delivering the capital efficiency and operational improve-
ments that will yield improved performance not only for 2013, but for years to come.
Day by day, step by step, mile by mile, we are working to make Exterran a better company, a
better partner, a better investment. We thank you for your continued support on this journey.
Sincerely,
Gordon T. Hall
Chairman of the Board
Exterran Holdings, Inc.
March 1, 2013
Brad Childers
President and Chief Executive Officer
Exterran Holdings, Inc.
(1) See the discussion of Non-GAAP Financial Measures beginning on page 40 of our accompanying 2012 Form 10-K for information
on EBITDA, as adjusted, and gross margin.
(2) See the discussion of Non-GAAP Financial Measures within Part II, Item 6 (“Selected Financial Data–Non-GAAP Financial
Measures”) of Exterran Partners, L.P.’s 2012 Form 10-K for information on distributable cash flow and gross margin.
6
Exterran Holdings 2012 Annual Report
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
(cid:3) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
(cid:4) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For fiscal year ended December 31, 2012
or
For the transition period from
to
.
Commission file no. 001-33666
Exterran Holdings, Inc.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
74-3204509
(I.R.S. Employer
Identification No.)
16666 Northchase Drive, Houston, Texas 77060
(Address of principal executive offices, zip code)
(281) 836-7000
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Name of Each Exchange on Which Registered
Common Stock, $0.01 par value
New York Stock Exchange
Securities registered pursuant to 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes (cid:4) No (cid:3)
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes (cid:4) No (cid:3)
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 (cid:3) No (cid:4)
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such
files). Yes (cid:3) No (cid:4)
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. (cid:3)
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 (cid:4)
Smaller reporting company (cid:4)
Accelerated filer (cid:3)
Non-accelerated filer (cid:4)
(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 (cid:4) No (cid:3)
The aggregate market value of the common stock of the registrant held by non-affiliates as of June 30, 2012 was
$295,597,020. For purposes of this disclosure, common stock held by persons who hold more than 5% of the outstanding voting
shares and common stock held by executive officers and directors of the registrant have been excluded in that such persons may
be deemed to be ‘‘affiliates’’ as that term is defined under the rules and regulations promulgated under the Securities Act of
1933, as amended. This determination of affiliate status is not necessarily a conclusive determination for other purposes.
Number of shares of the common stock of the registrant outstanding as of February 19, 2013: 64,918,732 shares.
Portions of the registrant’s definitive proxy statement for the 2013 Meeting of Stockholders, which is expected to be filed
with the Securities and Exchange Commission within 120 days after December 31, 2012, are incorporated by reference into
Part III of this Form 10-K.
DOCUMENTS INCORPORATED BY REFERENCE
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TABLE OF CONTENTS
PART I
Item 1.
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1A. Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 2.
Item 3.
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 4. Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . .
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 Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 14.
Item 15. Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART IV
Page
2
18
32
32
33
33
34
35
42
68
68
68
68
71
71
71
71
72
72
72
80
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PART I
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This report contains ‘‘forward-looking statements’’ intended to qualify for the safe harbors from
liability established by the Private Securities Litigation Reform Act of 1995. All statements other than
statements of historical fact contained in this report are forward-looking statements within the meaning
of Section 21E of the Securities Exchange Act of 1934, as amended (the ‘‘Exchange Act’’), including,
without limitation, statements regarding our business growth strategy and projected costs; future
financial position; the sufficiency of available cash flows to fund continuing operations; the expected
amount of our capital expenditures; anticipated cost savings, future revenue, gross margin and other
financial or operational measures related to our business and our primary business segments; the future
value of our equipment and non-consolidated affiliates; and plans and objectives of our management
for our future operations. You can identify many of these statements by looking for words such as
‘‘believe,’’ ‘‘expect,’’ ‘‘intend,’’ ‘‘project,’’ ‘‘anticipate,’’ ‘‘estimate,’’ ‘‘will continue’’ or similar words or
the negative thereof.
Such forward-looking statements are subject to various risks and uncertainties that could cause
actual results to differ materially from those anticipated as of the date of this report. Although we
believe that the expectations reflected in these forward-looking statements are based on reasonable
assumptions, no assurance can be given that these expectations will prove to be correct. Known
material factors that could cause our actual results to differ from those in these forward-looking
statements are described below, in Part I, Item 1A (‘‘Risk Factors’’) and Part II, Item 7
(‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’) of this
report. Important factors that could cause our actual results to differ materially from the expectations
reflected in these forward-looking statements include, among other things:
(cid:127) conditions in the oil and natural gas industry, including a sustained decrease in the level of
supply or demand for oil or natural gas or a sustained decrease in the price of oil or natural gas,
which could cause a decline in the demand for our natural gas compression and oil and natural
gas production and processing equipment and services;
(cid:127) our reduced profit margins or the loss of market share resulting from competition or the
introduction of competing technologies by other companies;
(cid:127) the success of our subsidiaries, including Exterran Partners, L.P. (along with its subsidiaries, the
‘‘Partnership’’);
(cid:127) changes in economic or political conditions in the countries in which we do business, including
civil uprisings, riots, terrorism, kidnappings, violence associated with drug cartels, legislative
changes and the expropriation, confiscation or nationalization of property without fair
compensation;
(cid:127) changes in currency exchange rates, including the risk of currency devaluations by foreign
governments, and restrictions on currency repatriation;
(cid:127) the inherent risks associated with our operations, such as equipment defects, impairments,
malfunctions and natural disasters;
(cid:127) loss of the Partnership’s status as a partnership for federal income tax purposes;
(cid:127) a decline in the Partnership’s quarterly distribution of cash to us attributable to our ownership
interest in the Partnership;
(cid:127) the risk that counterparties will not perform their obligations under our financial instruments;
(cid:127) the financial condition of our customers;
1
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(cid:127) our ability to timely and cost-effectively obtain components necessary to conduct our business;
(cid:127) employment and workforce factors, including our ability to hire, train and retain key employees;
(cid:127) our ability to implement certain business and financial objectives, such as:
(cid:127) winning profitable new business;
(cid:127) sales of additional United States of America (‘‘U.S.’’) contract operations contracts and
equipment to the Partnership;
(cid:127) timely and cost-effective execution of projects;
(cid:127) enhancing our asset utilization, particularly with respect to our fleet of compressors;
(cid:127) integrating acquired businesses;
(cid:127) generating sufficient cash; and
(cid:127) accessing the capital markets at an acceptable cost;
(cid:127) liability related to the use of our products and services;
(cid:127) changes in governmental safety, health, environmental or other regulations, which could require
us to make significant expenditures; and
(cid:127) our level of indebtedness and ability to fund our business.
All forward-looking statements included in this report are based on information available to us on
the date of this report. Except as required by law, we undertake no obligation to publicly update or
revise any forward-looking statement, whether as a result of new information, future events or
otherwise. All subsequent written and oral forward-looking statements attributable to us or persons
acting on our behalf are expressly qualified in their entirety by the cautionary statements contained
throughout this report.
Item 1. Business
We were incorporated in February 2007 as a wholly-owned subsidiary of Universal Compression
Holdings, Inc. (‘‘Universal’’). On August 20, 2007, Universal and Hanover Compressor Company
(‘‘Hanover’’) merged into our wholly-owned subsidiaries, and we became the parent entity of Universal
and Hanover. Immediately following the completion of the merger, Universal merged with and into us.
References to ‘‘Exterran,’’ ‘‘our,’’ ‘‘we’’ and ‘‘us’’ refer to Exterran Holdings, Inc. and its subsidiaries.
References to ‘‘North America’’ when used in this report refer to the U.S. and Canada. References to
‘‘International’’ and variations thereof when used in this report refer to the world excluding North
America.
General
We are a global market leader in the full-service natural gas compression business and a premier
provider of operations, maintenance, service and equipment for oil and natural gas production,
processing and transportation applications. Our global customer base consists of companies engaged in
all aspects of the oil and natural gas industry, including large integrated oil and natural gas companies,
national oil and natural gas companies, independent producers and natural gas processors, gatherers
and pipelines. We operate in three primary business lines: contract operations, fabrication and
aftermarket services. In our contract operations business line, we own a fleet of natural gas
compression equipment and crude oil and natural gas production and processing equipment that we
utilize to provide operations services to our customers. In our fabrication business line, we fabricate
equipment for sale to our customers and for use in our contract operations services. In addition, our
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fabrication business line provides engineering, procurement and fabrication services primarily related to
the manufacturing of critical process equipment for refinery and petrochemical facilities, the fabrication
of tank farms and the fabrication of evaporators and brine heaters for desalination plants. We offer our
customers, on either a contract operations basis or a sale basis, the engineering, design, project
management, procurement and construction services necessary to incorporate our products into
production, processing and compression facilities, which we refer to as Integrated Projects. In our
aftermarket services business line, we sell parts and components and provide operations, maintenance,
overhaul and reconfiguration services to customers who own compression, production, processing,
treating and other equipment.
Our products and services are essential to the production, processing, transportation and storage of
natural gas and are provided primarily to energy producers and distributors of oil and natural gas. Our
geographic business unit operating structure, technically experienced personnel and high-quality
contract operations fleet allow us to provide reliable and timely customer service.
We have an equity interest in the Partnership, a master limited partnership that provides natural
gas contract operations services to customers throughout the U.S. As of December 31, 2012, public
unitholders held a 69% ownership interest in the Partnership and we owned the remaining equity
interest, including the general partner interest and all incentive distribution rights. The general partner
of the Partnership is our subsidiary and we consolidate the financial position and results of operations
of the Partnership. It is our intention for the Partnership to be the primary vehicle for the growth of
our U.S. contract operations business and for us to continue to contribute U.S. contract operations
customer contracts and equipment to the Partnership over time in exchange for cash, the Partnership’s
assumption of our debt and/or additional interests in the Partnership. As of December 31, 2012, the
Partnership’s fleet included 4,803 compressor units comprising approximately 2,084,000 horsepower, or
62% (by then available horsepower) of our and the Partnership’s combined total U.S. horsepower. The
Partnership fleet included 323 compressor units with an aggregate horsepower of approximately 163,000
leased from our wholly-owned subsidiaries and excluded 24 compressor units with an aggregate
horsepower of approximately 9,000 leased to our wholly-owned subsidiaries as of December 31, 2012.
In March 2012, we sold to the Partnership contract operations customer service agreements with
39 customers and a fleet of 406 compressor units used to provide compression services under those
agreements, comprising approximately 188,000 horsepower, or 5% (by then available horsepower) of
our and the Partnership’s combined U.S. contract operations business. The assets sold also included
139 compressor units, comprising approximately 75,000 horsepower, that we previously leased to the
Partnership and a natural gas processing plant with a capacity of 10 million cubic feet per day used to
provide processing services. Total consideration for the transaction was approximately $182.8 million,
excluding transaction costs, and consisted of the Partnership’s payment of $77.4 million in cash and
assumption of $105.4 million of our long-term debt.
Industry Overview
Natural Gas Compression
Natural gas compression is a mechanical process whereby the pressure of a given volume of
natural gas is increased to a desired higher pressure for transportation from one point to another. It is
essential to the production and transportation of natural gas. Compression is typically required several
times during the natural gas production and transportation cycle, including (i) at the wellhead,
(ii) throughout gathering and distribution systems, (iii) into and out of processing and storage facilities
and (iv) along intrastate and interstate pipelines.
(cid:127) Wellhead and Gathering Systems—Natural gas compression is used to transport natural gas from
the wellhead through the gathering system. At some point during the life of natural gas wells
reservoir pressures typically fall below the line pressure of the natural gas gathering or pipeline
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system used to transport the natural gas to market. At that point, natural gas no longer naturally
flows into the pipeline. Compression equipment is applied in both field and gathering systems to
boost the pressure levels of the natural gas flowing from the well allowing it to be transported to
market. Changes in pressure levels in natural gas fields require periodic changes to the size
and/or type of on-site compression equipment. Additionally, compression is used to reinject
natural gas into producing oil wells to maintain reservoir pressure and help lift liquids to the
surface, which is known as secondary oil recovery or natural gas lift operations. Typically, these
applications require low- to mid-range horsepower compression equipment located at or near
the wellhead. Compression equipment is also used to increase the efficiency of a low-capacity
natural gas field by providing a central compression point from which the natural gas can be
produced and injected into a pipeline for transmission to facilities for further processing.
(cid:127) Pipeline Transportation Systems—Natural gas compression is used during the transportation of
natural gas from the gathering systems to storage or the end user. Natural gas transported
through a pipeline loses pressure over the length of the pipeline. Compression is staged along
the pipeline to increase capacity and boost pressure to overcome the friction and hydrostatic
losses inherent in normal operations. These pipeline applications generally require larger
horsepower compression equipment (1,500 horsepower and higher).
(cid:127) Storage Facilities—Natural gas compression is used in natural gas storage projects for injection
and withdrawals during the normal operational cycles of these facilities.
(cid:127) Processing Applications—Compressors may also be used in combination with natural gas
production and processing equipment and to process natural gas into other marketable energy
sources. In addition, compression services are used for compression applications in refineries and
petrochemical plants.
Many natural gas producers, transporters and processors outsource their compression services due
to the benefits and flexibility of contract compression. Changing well and pipeline pressures and
conditions over the life of a well often require producers to reconfigure or replace their compressor
units to optimize the well production or gathering system efficiency.
We believe outsourcing compression operations to compression service providers such as us offers
customers:
(cid:127) the ability to efficiently meet their changing compression needs over time while limiting the
underutilization of their existing compression equipment;
(cid:127) access to the compression service provider’s specialized personnel and technical skills, including
engineers and field service and maintenance employees, which we believe generally leads to
improved production rates and/or increased throughput;
(cid:127) the ability to increase their profitability by transporting or producing a higher volume of natural
gas through decreased compression downtime and reduced operating, maintenance and
equipment costs by allowing the compression service provider to efficiently manage their
compression needs; and
(cid:127) the flexibility to deploy their capital on projects more directly related to their primary business
by reducing their compression equipment and maintenance capital requirements.
The international compression market is comprised primarily of large horsepower compressors. A
significant portion of this market involves comprehensive projects that require the design, fabrication,
delivery, installation, operation and maintenance of compressors and related natural gas treatment and
processing equipment by the contract operations service provider.
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Production and Processing Equipment
Crude oil and natural gas are generally not marketable as produced at the wellhead and must be
processed or treated before they can be transported to market. Production and processing equipment is
used to separate and treat oil and natural gas as it is produced to achieve a marketable quality of
product. Production processing typically involves the separation of oil and natural gas and the removal
of contaminants. The end result is ‘‘pipeline’’ or ‘‘sales’’ quality oil and natural gas. Further processing
or refining is almost always required before oil or natural gas is suitable for use as fuel or feedstock for
petrochemical production. Production processing normally takes place in the ‘‘upstream’’ and
‘‘midstream’’ markets, while refining and petrochemical processing is referred to as the ‘‘downstream’’
market. Wellhead or upstream production and processing equipment includes a wide and diverse range
of products.
The standard production and processing equipment market tends to be somewhat commoditized,
with sales following general industry trends of oil and natural gas production. We fabricate and stock
standard production equipment based on historical product mix and expected customer purchases. In
addition, we sell custom-engineered, built-to-specification production and processing equipment, which
typically consists of much larger equipment packages than standard equipment, and is generally used in
much larger scale production operations. The custom equipment market is driven by global economic
trends, and the specifications for purchased equipment can vary significantly. Technology, engineering
capabilities, project management, available manufacturing space and quality control standards are the
key drivers in the custom equipment market.
Market Conditions
We believe that the growing global consumption of natural gas and its byproducts is the
predominant force driving the demand for natural gas compression and production and processing
equipment. As more natural gas is consumed, the demand for compression and production and
processing equipment generally increases. Because we expect the demand for natural gas and natural
gas byproducts to increase over the long term, we believe the demand for compression and production
and processing equipment and related services will increase as well.
Natural gas consumption in the U.S. for the twelve months ended November 30, 2012 increased by
approximately 4% over the twelve months ended November 30, 2011, is expected to increase by 1.2%
in 2013, and by an average of 0.5% per year thereafter until 2035, according to the U.S. Energy
Information Administration (‘‘EIA’’).
Natural gas marketed production in the U.S. for the twelve months ended November 30, 2012
increased by approximately 6% over the twelve months ended November 30, 2011. The EIA forecasts
that total U.S. marketed production will grow by 1% in 2013. In 2011, the U.S. accounted for an
estimated annual production of approximately 24 trillion cubic feet of natural gas, or 20% of the
worldwide total of approximately 123 trillion cubic feet. The EIA estimates that the U.S.’s natural gas
production level will be approximately 26 trillion cubic feet in 2035, or 16% of the projected worldwide
total of approximately 169 trillion cubic feet.
We believe the long-term outlook for natural gas compression in the U.S. will continue to benefit
from increased production from unconventional sources and from the aging of producing natural gas
fields that will require more compression to continue producing the same volume of natural gas. In
addition, we see opportunities to provide compression and processing services to producers of natural
gas liquids. However, the supply of U.S. natural gas continued to increase in 2012 and outstripped
demand, which contributed to a low natural gas price environment. This trend of lower natural gas
prices could further decrease natural gas production, particularly in more mature and predominately
dry gas areas, and as a result the demand for our natural gas compression equipment and services
could be adversely affected.
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The EIA reports that natural gas consumption outside of the U.S. grew 48% from 2000 through
2011. Despite this growth in demand, most international energy markets have historically lacked the
infrastructure necessary to either transport natural gas to markets or consume it locally; thus, more
infrastructure is required to utilize this natural gas. Total natural gas consumption worldwide is
projected to increase by an average of 1.6% per year until 2035, according to the EIA, and therefore,
we believe that over the long term, demand for natural gas infrastructure in international markets will
increase. We believe this anticipated increase in demand for infrastructure will be further supported by
recent technology advances, including liquefied natural gas (or LNG) and gas-to-liquids, which make
the transportation of natural gas without pipelines more economical, environmental legislation
prohibiting flaring and the anticipated construction of natural gas-fueled power plants built to meet
international energy demand. Additionally, we believe demand for production and processing
equipment will increase over time to support the anticipated increased infrastructure.
While natural gas compression and production and processing equipment typically must be
engineered to meet unique customer specifications, the fundamental technology of such equipment has
not been subject to significant change.
As energy industry capital spending declined in 2009, our fabrication business segment experienced
a reduction in demand that continued through 2011. However, we began to see an improvement in
market activities in North America in the latter part of 2010 and in 2011. During 2012, our fabrication
backlog increased by approximately 45% from December 31, 2011. We have seen a shift in the regional
mix of our fabrication backlog since the beginning of 2009, when the Eastern Hemisphere and North
America represented approximately 80% and 20%, respectively, of our fabrication backlog. As of
December 31, 2012, North America and Eastern Hemisphere accounted for approximately 58% and
33%, respectively, of our fabrication backlog.
Our critical process equipment fabrication business has also experienced a reduction in backlog
given the longer lead times for the development of projects. In addition, we fabricate evaporators and
brine heaters for desalination plants and tank farms primarily for use in North Africa and the Middle
East. Demand for these products is driven primarily by population growth, improvements in the
standard of living and investment in infrastructure. We expect continued investment in these projects,
and therefore increased demand for the equipment, in the regions we serve over the next few years.
However, the reductions in global economic activity led to a substantial reduction in our fabrication
backlog related to these projects during 2011. During 2012, we experienced a modest increase in
backlog for these products, but as of December 31, 2012 were at just over 50% of our backlog levels as
of the end of 2010.
Operations
Business Segments
Our revenues and income are derived from four business segments:
(cid:127) North America Contract Operations. Our North America contract operations segment primarily
provides natural gas compression and production and processing services to meet specific
customer requirements utilizing Exterran-owned assets within the U.S.
(cid:127) International Contract Operations. Our international contract operations segment provides
substantially the same services as our North America contract operations segment except it
services locations outside the U.S. Services provided in our international contract operations
segment often include engineering, procurement and on-site construction of large natural gas
compression stations and/or crude oil or natural gas production and processing facilities.
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(cid:127) Aftermarket Services. Our aftermarket services segment provides a full range of services to
support the surface production, compression and processing needs of customers, from parts sales
and normal maintenance services to full operation of a customer’s owned assets.
(cid:127) Fabrication. Our fabrication segment provides (i) design, engineering, fabrication, installation
and sale of natural gas compression units and accessories and equipment used in the production,
treating and processing of crude oil and natural gas and (ii) engineering, procurement and
fabrication services primarily related to the manufacturing of critical process equipment for
refinery and petrochemical facilities, the fabrication of tank farms and the fabrication of
evaporators and brine heaters for desalination plants.
For financial data relating to our business segments or geographic regions that accounted for 10%
or more of consolidated revenue in any of the last three fiscal years, see Part II, Item 7
(‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’) and
Note 22 to the Consolidated Financial Statements included in Part IV, Item 15 (‘‘Financial
Statements’’) of this report.
Compressor Fleet
The size and horsepower of our natural gas compressor fleet on December 31, 2012 is summarized
in the following table:
Range of Horsepower Per Unit
Number
of Units
Aggregate
Horsepower
% of
(in thousands) Horsepower
0 - 200 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
201 - 500 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
501 - 800 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
801 - 1,100 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,101 - 1,500 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,501 and over . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,684
2,029
679
491
1,332
468
8,683
405
582
416
471
1,808
959
4,641
9%
12%
9%
10%
39%
21%
100%
Over the last several years, we have undertaken efforts to standardize our compressor fleet around
major components and key suppliers. The standardization of our fleet:
(cid:127) enables us to minimize our fleet operating costs and maintenance capital requirements;
(cid:127) enables us to reduce inventory costs;
(cid:127) facilitates low-cost compressor resizing; and
(cid:127) allows us to develop improved technical proficiency in our maintenance and overhaul operations,
which enables us to achieve high run-time rates while maintaining low operating costs.
As of December 31, 2012, the Partnership’s fleet included 4,803 of these compressor units
comprising approximately 2,084,000 horsepower, or 62% (by then available horsepower) of our and the
Partnership’s combined total U.S. horsepower. The Partnership fleet included 323 compressor units with
an aggregate horsepower of approximately 163,000 leased from our wholly-owned subsidiaries and
excluded 24 compressor units with an aggregate horsepower of approximately 9,000 leased to our
wholly-owned subsidiaries as of December 31, 2012.
Contract Operations—North America and International
We provide comprehensive contract operations services, including the personnel, equipment, tools,
materials and supplies to meet our customers’ natural gas compression, production or processing
service needs. Based on the operating specifications at the customer’s location and the customer’s
unique needs, these services include designing, sourcing, owning, installing, operating, servicing,
repairing and maintaining equipment to provide these services to our customers.
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When providing contract compression services, we work closely with a customer’s field service
personnel so that the compression services can be adjusted to efficiently match changing characteristics
of the reservoir and the natural gas produced. We routinely repackage or reconfigure a portion of our
existing fleet to adapt to our customers’ compression services needs. We utilize both slow and high
speed reciprocating compressors primarily driven by internal natural gas fired combustion engines. We
also utilize rotary screw compressors for specialized applications.
Our equipment is maintained in accordance with established maintenance schedules. These
maintenance procedures are updated as technology changes and as our operations group develops new
techniques and procedures. In addition, because our field technicians provide maintenance on our
contract operations equipment, they are familiar with the condition of our equipment and can readily
identify potential problems. In our experience, these maintenance procedures maximize equipment life
and unit availability, minimize avoidable downtime and lower the overall maintenance expenditures
over the equipment life. Generally, each of our compressor units undergoes a major overhaul once
every three to seven years, depending on the type, size and utilization of the unit.
We also provide contract production and processing services, similar to the contract compression
services described above, utilizing our fleet of oil and natural gas production and processing equipment.
Most of these services are what we call Integrated Projects, in which we provide the engineering,
design, project management, procurement and construction services necessary to incorporate our
products into production, processing and compression facilities.
We believe that our aftermarket services and fabrication businesses, described below, provide
opportunities to cross-sell our contract operations services.
Our customers typically contract for our services on a site-by-site basis for a specific monthly
service rate that is generally reduced if we fail to operate in accordance with the contract requirements.
Following the initial minimum term, which in North America is typically between six and twelve
months, contract operations services generally continue until terminated by either party with 30 days’
advance notice. Our customers generally are required to pay our monthly service fee even during
periods of limited or disrupted natural gas flows, which enhances the stability and predictability of our
cash flows. Additionally, because we do not typically take title to the natural gas we compress, process
or treat and because the natural gas we use as fuel for our compressors and other equipment is
supplied by our customers, we have limited direct exposure to commodity price fluctuations.
We maintain field service locations from which we can service and overhaul our own compressor
fleet to provide contract operations services to our customers. We also use many of these locations to
provide aftermarket services to our customers, as described in more detail below. As of December 31,
2012, our North America contract operations segment provided contract operations services primarily
using a fleet of 7,651 natural gas compression units with an aggregate capacity of approximately
3,376,000 horsepower and production and processing facilities. For the year ended December 31, 2012,
22% of our total revenue and 38% of our total gross margin was generated from North America
contract operations. Gross margin, a non-GAAP financial measure, is reconciled, in total, to net income
(loss), its most directly comparable financial measure calculated and presented in accordance with
GAAP in Part II, Item 6 (‘‘Selected Financial Data—Non-GAAP Financial Measures’’) of this report.
Our international operations are focused on markets that require both large horsepower
compressor applications and full production and processing facilities. Our international contract
operations segment typically engages in longer-term contracts and more comprehensive projects than
our North America contract operations segment. International projects often require us to provide
complete engineering, design and installation services and a greater investment in equipment, facilities
and related installation costs. These larger projects may include several compressor units on one site or
entire facilities designed to process and treat oil or natural gas to make it suitable for end use. As of
December 31, 2012, our international contract operations segment provided contract operations services
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using a fleet of 1,032 natural gas compression units with an aggregate capacity of approximately
1,265,000 horsepower and a fleet of production and processing equipment. For the year ended
December 31, 2012, 16% of our total revenue and 33% of our total gross margin was generated from
international contract operations.
Aftermarket Services
Our aftermarket services segment sells parts and components and provides operation, maintenance,
overhaul and reconfiguration services to customers who own compression, production, treating and
oilfield power generation equipment. We believe that we are particularly well qualified to provide these
services because our highly experienced operating personnel have access to the full range of our
compression services, production and processing equipment and oilfield power generation equipment
and facilities. For the year ended December 31, 2012, 14% of our total revenue and 10% of our total
gross margin was generated from aftermarket services.
Fabrication
Compressor and Accessory Fabrication
We design, engineer, fabricate, install and sell skid-mounted natural gas compression units and
accessories to meet standard or unique customer specifications. We sell this compression equipment
primarily to major and independent oil and natural gas producers as well as national oil and natural
gas companies in the countries where we operate.
Generally, we assemble compressors sold to third parties according to each customer’s
specifications. We purchase components for these compressors from third party suppliers including
several major engine and compressor manufacturers in the industry. We also sell pre-packaged
compressor units designed to our standard specifications. For the year ended December 31, 2012, 16%
of our total revenue and 4% of our total gross margin was generated from our compressor and
accessory fabrication business line.
As of December 31, 2012, our compressor and accessory fabrication backlog was $256.3 million,
compared to $249.7 million at December 31, 2011. At December 31, 2012, all future revenue related to
our compressor and accessory fabrication backlog is expected to be recognized before December 31,
2013.
Production and Processing Equipment Fabrication
We design, engineer, fabricate, install and sell a broad range of oil and natural gas production and
processing equipment designed to heat, separate, dehydrate and condition crude oil and natural gas to
make them suitable for end use. Our products include line heaters, oil and natural gas separators,
glycol dehydration units, condensate stabilizers, dewpoint control plants, water treatment, mechanical
refrigeration and cryogenic plants and skid-mounted production packages designed for both onshore
and offshore production facilities. We sell standard production and processing equipment, which is used
for processing wellhead production from onshore or shallow-water offshore platform production
primarily into U.S. markets. In addition, we sell custom-engineered, built-to-specification production
and processing equipment. Some of these projects are in remote areas and in developing countries with
limited oil and natural gas industry infrastructure. To meet most customers’ rapid response
requirements and minimize customer downtime, we maintain an inventory of standard products and
long delivery components used to manufacture our products to our customers’ specifications. We also
provide engineering, procurement and fabrication services primarily related to the manufacturing of
critical process equipment for refinery and petrochemical facilities, the fabrication of tank farms and
the fabrication of evaporators and brine heaters for desalination plants. For the year ended
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December 31, 2012, 32% of our total revenue and 15% of our total gross margin was generated from
our production and processing equipment fabrication business line.
As of December 31, 2012, our production and processing equipment fabrication backlog was
$563.8 million, compared to $416.0 million at December 31, 2011. Typically, we expect our production
and processing equipment backlog to be produced within a three to 36 month period. At December 31,
2012, $7.7 million of future revenue related to our production and processing equipment backlog was
expected to be recognized after December 31, 2013.
Business Strategy
We intend to continue to capitalize on our competitive strengths to meet our customers’ needs
through the following key strategies:
(cid:127) Grow our North America business. We plan to continue to invest in strategically growing our
North America business. Our North America contract operations business is our largest business
segment based on gross margin, representing 38% of our gross margin in 2012. We see
opportunities to grow this business by continuing to put idle units back to work and adding new
horsepower in key growth areas, including providing compression and processing services to
producers of natural gas from shale plays and natural gas liquids. We intend to utilize the
Partnership as our primary vehicle for the long-term growth of our U.S. contract operations
business. In addition, increased drilling activity in the shale plays and areas focused on the
production of oil and natural gas liquids in North America has led to an increase in our North
America fabrication backlog, which represented 58% of our total world-wide fabrication backlog
at December 31, 2012.
(cid:127) Focus on key international markets. International markets continue to represent a significant
growth opportunity for our business, due in large part to the fact that over 70% of the world’s
natural gas production resides in markets outside North America. We believe that natural gas
production in these regions will grow over the long term at a pace greater than that of North
America. In addition, we typically see higher returns and margins in international markets
relative to North America due to more complex project requirements. We expect to allocate
additional resources toward key areas of our international business and rebuilding our
fabrication backlog in the Eastern Hemisphere.
(cid:127) Lower costs and improve profitability. To enhance our competitive position, we embarked in the
second half of 2011 on a multi-year plan to improve the profitability of our operations. We
expect our profitability initiatives to impact all of our business segments and geographies. As the
largest provider of compression services in the world, we intend to use our scale to achieve cost
savings in our operations. We are also focused on increasing productivity and optimizing our
processes in our core lines of business. By making our systems and processes more efficient, we
intend to lower our internal costs and improve our profitability.
Competitive Strengths
We believe we have the following key competitive strengths:
(cid:127) Breadth and quality of product and service offerings. We provide our customers a broad variety of
products and services, including outsourced compression, production and processing services, as
well as the sale of compression and oil and natural gas production and processing equipment
and installation services. We believe our contract operations services generally allow our
customers that outsource their compression or production and processing needs to achieve
higher production rates than they would achieve with their own operations, resulting in increased
revenue for our customers. In addition, outsourcing allows our customers flexibility for their
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evolving compression and production and processing needs while limiting their capital
requirements. By offering a broad range of services that leverage our core strengths, we believe
that we can provide comprehensive integrated solutions to meet our customers’ needs. In our
Integrated Projects, we can provide the engineering, design, project management and
procurement and construction services necessary to incorporate our products into production,
processing and compression facilities. We believe the breadth and quality of our products and
services, the depth of our customer relationships and our presence in many major oil and
natural gas-producing regions place us in a position to capture additional business on a global
basis.
(cid:127) Focus on providing superior customer service. We believe we operate in a relationship-driven,
service-intensive industry and therefore need to provide superior customer service. We believe
that our regionally-based network, local presence, experience and in-depth knowledge of
customers’ operating needs and growth plans enable us to respond to our customers’ needs and
meet their evolving demands on a timely basis. In addition, we focus on achieving a high level of
mechanical reliability for the services we provide in order to maximize our customers’ production
levels. Our sales efforts concentrate on demonstrating our commitment to enhancing our
customers’ cash flow through superior customer service, product design, fabrication, installation
and after-market support.
(cid:127) Size and geographic scope. We operate in the major onshore and offshore oil and natural gas
producing regions of North America and many international markets. We believe we have
sufficient fleet size, personnel, logistical capabilities, geographic scope, fabrication capabilities
and range of services and product offerings to meet the needs of our customers on a timely and
cost-effective basis. We believe our size, geographic scope and broad customer base provide us
with improved operating expertise and business development opportunities.
(cid:127) Ability to leverage the Partnership. We believe that the Partnership provides us a lower cost of
capital over time relative to our competitors that pay entity-level federal income taxes. We have
completed seven sales to the Partnership, including in connection with the Partnership’s initial
public offering in 2006, of compressor units aggregating approximately 2.0 million horsepower, as
well as gas processing assets. The proceeds from these transactions have provided us significant
capital to reduce our debt and fund our capital expenditures. In addition, we have received
equity interests in these transactions that we believe will allow us to participate in the
Partnership’s future growth.
Oil and Natural Gas Industry Cyclicality and Volatility
Changes in oil and natural gas exploration and production spending normally results in changes in
demand for our products and services; however, we believe our contract operations business is typically
less impacted by commodity prices than certain other energy service products and services because:
(cid:127) compression, production and processing services are necessary for natural gas to be delivered
from the wellhead to end users;
(cid:127) the need for compression services and equipment has grown over time due to the increased
production of natural gas, the natural pressure decline of natural gas producing basins and the
increased percentage of natural gas production from unconventional sources; and
(cid:127) our contract operations businesses are tied primarily to natural gas and oil production and
consumption, which are generally less cyclical in nature than exploration activities.
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Seasonal Fluctuations
Our results of operations have not historically reflected any material seasonal tendencies and we
currently do not believe that seasonal fluctuations will have a material impact on us in the foreseeable
future.
Market and Customers
Our global customer base consists primarily of companies engaged in all aspects of the oil and
natural gas industry, including large integrated oil and natural gas companies, national oil and natural
gas companies, independent producers and natural gas processors, gatherers and pipelines.
We conduct our contract operations and sales activities throughout North America and
internationally, including offshore operations. We currently operate in approximately 30 countries in
major oil and natural gas producing areas including the U.S., Argentina, Brazil, Mexico, Italy and the
United Arab Emirates. We have fabrication facilities in the U.S., Italy, Singapore, the United Arab
Emirates and the United Kingdom.
Sales and Marketing
Our salespeople pursue the market for our products in their respective territories. Each
salesperson is assigned a customer list or territory based on the individual’s experience and personal
relationships and the customers’ service requirements. This customer and relationship-focused strategy
is communicated through frequent direct contact, technical presentations, print literature, print
advertising and direct mail. Additionally, our salespeople coordinate with each other to effectively
pursue customers that operate in multiple regions. Our salespeople work with our operations personnel
to promptly respond to and satisfy customer needs.
Upon receipt of a request for proposal or bid by a customer, we analyze the application and
prepare a quotation, including pricing and delivery date. The quotation is then delivered to the
customer and, if we are selected as the vendor, final terms are agreed upon and a contract or purchase
order is executed. Our engineering and operations personnel also provide assistance on complex
applications, field operations issues and equipment modifications.
Sources and Availability of Raw Materials
We fabricate compression and production and processing equipment to provide contract operations
services and to sell to third parties from components and subassemblies, most of which we acquire from
a wide range of vendors. These components represent a significant portion of the cost of our
compressor and production and processing equipment products. In addition, we fabricate tank farms
and critical process equipment for refinery and petrochemical facilities and other vessels used in
production, processing and treating of crude oil and natural gas. Steel can have wide price fluctuations
and represents a significant portion of the raw materials for these products. Increases in raw material
costs cannot always be offset by increases in our products’ sales prices. While many of our materials
and components are available from multiple suppliers at competitive prices, we obtain some of the
components used in our products from a limited group of suppliers. We occasionally experience long
lead times for components from our suppliers and, therefore, we may at times make purchases in
anticipation of future orders.
Competition
The natural gas compression services and fabrication business is highly competitive. Overall, we
experience considerable competition from companies that may be able to more quickly adapt to
changes within our industry and changes in economic conditions as a whole, more readily take
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advantage of available opportunities and adopt more aggressive pricing policies. We believe we are
competitive with respect to price, equipment availability, customer service and flexibility in meeting
customer needs and quality and reliability of our compressors and related services. We face vigorous
competition in both compression services and compressor fabrication, with some firms competing in
both segments. In our production and processing equipment business, we have different competitors in
the standard and custom-engineered equipment markets. Competitors in the standard equipment
market include several large companies and a large number of small, regional fabricators. Competition
in the standard equipment market is generally based upon price and availability. Our competition in
the custom-engineered market usually consists of larger companies with the ability to provide integrated
projects and product support after the sale. The ability to fabricate these large custom-engineered
systems near the point of end-use is often a competitive advantage.
International Operations
We operate in many geographic markets outside North America. At December 31, 2012,
approximately 17% of our revenue was generated by our operations in Latin America (primarily in
Argentina, Brazil and Mexico) and approximately 18% of our revenue was generated in the Eastern
Hemisphere. Changes in local economic or political conditions could have a material adverse effect on
our business, financial condition, results of operations and cash flows.
Our future plans involve expanding our business in select international markets. The risks inherent
in establishing new business ventures or expanding existing operations, especially in international
markets where local customs, laws and business procedures present special challenges, may affect our
ability to be successful in these ventures or operations or avoid losses which could have a material
adverse effect on our business, financial condition, results of operations and cash flows.
We have significant operations that expose us to currency risk primarily in Argentina, Brazil, Italy
and Mexico.
Additional risks inherent in our international business activities are described in ‘‘Risk Factors.’’
For financial data relating to our geographic concentrations, see Note 22 to the Financial Statements.
Environmental and Other Regulations
Government Regulation
Our operations are subject to stringent and complex U.S. federal, state, local and international
laws and regulations governing the discharge of materials into the environment or otherwise relating to
protection of the environment and to occupational safety and health. Compliance with these
environmental laws and regulations may expose us to significant costs and liabilities and cause us to
incur significant capital expenditures in our operations. Failure to comply with these laws and
regulations may result in the assessment of administrative, civil and criminal penalties, imposition of
investigatory and remedial obligations, and the issuance of injunctions delaying or prohibiting
operations. We believe that our operations are in substantial compliance with applicable environmental
and safety and health laws and regulations and that continued compliance with currently applicable
requirements would not have a material adverse effect on us. However, the clear trend in
environmental regulation is to place more restrictions on activities that may affect the environment, and
thus, any changes in these laws and regulations that result in more stringent and costly waste handling,
storage, transport, disposal, emission or remediation requirements could have a material adverse effect
on our results of operations and financial position.
The primary U.S. federal environmental laws to which our operations are subject include the Clean
Air Act (‘‘CAA’’) and regulations thereunder, which regulate air emissions; the Clean Water Act
(‘‘CWA’’) and regulations thereunder, which regulate the discharge of pollutants in industrial
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wastewater and storm water runoff; the Resource Conservation and Recovery Act (‘‘RCRA’’) and
regulations thereunder, which regulate the management and disposal of hazardous and non-hazardous
solid wastes; and the Comprehensive Environmental Response, Compensation, and Liability Act
(‘‘CERCLA’’) and regulations thereunder, known more commonly as ‘‘Superfund,’’ which imposes
liability for the remediation of releases of hazardous substances in the environment. We are also subject
to regulation under the federal Occupational Safety and Health Act (‘‘OSHA’’) and regulations
thereunder, which regulate the protection of the safety and health of workers. Analogous state, local
and international laws and regulations may also apply.
Air Emissions
The CAA and analogous state laws and their implementing regulations regulate emissions of air
pollutants from various sources, including natural gas compressors, and also impose various monitoring
and reporting requirements. Such laws and regulations may require a facility to obtain pre-approval for
the construction or modification of certain projects or facilities expected to produce air emissions or
result in the increase of existing air emissions, obtain and strictly comply with air permits containing
various emissions and operational limitations, or utilize specific emission control technologies to limit
emissions. Our standard contract operations contract typically provides that the customer will assume
permitting responsibilities and certain environmental risks related to site operations.
On August 20, 2010, the U.S. Environmental Protection Agency (‘‘EPA’’) published new regulations
under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocal
internal combustion engines. The rule would have required us to undertake certain expenditures and
activities, including purchasing and installing emissions control equipment, such as oxidation catalysts or
non-selective catalytic reduction equipment, on a portion of our engines located at certain sources of
hazardous air pollutants and all our engines over a certain size regardless of location, following
prescribed maintenance practices for engines (which are consistent with our existing practices), and
implementing additional emissions testing and monitoring. Following legal challenges to the 2010 rule,
the EPA reconsidered the rule and published revisions to the rule on January 30, 2013. The revised
rule will require management practices for all covered engines but will require catalyst installation only
on larger equipment at sites that are not deemed to be ‘‘remote.’’ Since the rule has just recently been
finalized, we are in the process of determining the amount of our larger equipment at non-remote sites,
and, as a result, we cannot currently accurately predict the cost to comply with the rule’s requirements.
Compliance with the final rule is required by October 2013.
On May 21, 2012, the EPA issued new ozone nonattainment designations for all areas except
Chicago, in relation to the 2008 national ambient air quality standard (‘‘NAAQS’’) for ozone. Among
other things, these new designations add Wise County to the Dallas-Fort Worth (‘‘DFW’’)
nonattainment area. This new designation will require Texas to modify its State Implementation Plan
(‘‘SIP’’) to include a plan for Wise County to come into compliance with the ozone NAAQS. This
modification process typically takes about three to five years. If Texas implements the same control
requirements in Wise County that are already in place in the other counties in the DFW nonattainment
area, we could be required to modify or remove and replace a significant amount of equipment we
currently utilize in Wise County. However, at this point we cannot predict what Texas’ new SIP will
require or what equipment will still be operating in Wise County when it comes into effect and, as a
result, we cannot currently accurately predict the impact or cost to comply.
On August 16, 2012, the EPA published final rules that establish new air emission controls for
natural gas and natural gas liquids production, processing and transportation activities, including New
Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds,
and a separate set of emission standards to address hazardous air pollutants frequently associated with
production and processing activities. Among other things, the rules establish specific requirements
regarding emissions from compressors and controllers at natural gas gathering and boosting stations
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and processing plants together with dehydrators and storage tanks at natural gas processing plants,
compressor stations and gathering and boosting stations. In addition, the rules establish new
requirements for leak detection and repair of leaks at natural gas processing plants that exceed 500
parts per million in concentration.
In addition, in January 2011, the Texas Commission on Environmental Quality (‘‘TCEQ’’) finalized
revisions to certain air permit programs that significantly increase air emissions-related requirements
for new and certain existing oil and gas production and gathering sites in the Barnett Shale production
area. The final rule established new emissions standards for engines, which could impact the operation
of specific categories of engines by requiring the use of alternative engines, compressor packages or the
installation of aftermarket emissions control equipment. The rule became effective for the Barnett
Shale production area in April 2011, and the lower emissions standards will become applicable between
2015 and 2030 depending on the type of engine and the permitting requirements. A number of other
states where our engines are operated have adopted or are considering adopting additional regulations
that could impose new air permitting or pollution control requirements for engines, some of which
could entail material costs to comply. At this point, however, we cannot predict whether any such rules
would require us to incur material costs.
These new regulations and proposals, when finalized, and any other new regulations requiring the
installation of more sophisticated pollution control equipment or the adoption of other environmental
protection measures, could have a material adverse impact on our business, financial condition, results
of operations and cash flows.
Climate change legislation and regulatory initiatives could result in increased compliance costs.
The U.S. Congress has considered legislation to restrict or regulate emissions of greenhouse gases,
such as carbon dioxide and methane. One bill, passed by the House of Representatives, if enacted by
the full Congress, would have required greenhouse gas emissions reductions by covered sources of as
much as 17% from 2005 levels by 2020 and by as much as 83% by 2050. It presently appears unlikely
that comprehensive climate legislation will be passed by either house of Congress in the near future,
although energy legislation and other initiatives continue to be proposed that may be relevant to
greenhouse gas emissions issues. In addition, almost half of the states, either individually or through
multi-state regional initiatives, have begun to address greenhouse gas emissions, primarily through the
planned development of emission inventories or regional greenhouse gas cap and trade programs.
Although most of the state-level initiatives have to date been focused on large sources of greenhouse
gas emissions, such as electric power plants, it is possible that smaller sources such as our gas-fired
compressors could become subject to greenhouse gas-related regulation. Depending on the particular
program, we could be required to control emissions or to purchase and surrender allowances for
greenhouse gas emissions resulting from our operations.
Independent of Congress, the EPA is beginning to adopt regulations controlling greenhouse gas
emissions under its existing CAA authority. The EPA has adopted rules requiring many facilities,
including petroleum and natural gas systems, to inventory and report their greenhouse gas emissions.
These rules triggered reporting obligations for several sites we operated all or most of 2012.
In addition, the EPA in June 2010 published a final rule providing for the tailored applicability of
air permitting requirements for greenhouse gas emissions. The EPA reported that the rulemaking was
necessary because without it certain permitting requirements would apply as of January 2011 at an
emissions level that would have greatly increased the number of required permits and, among other
things, imposed undue costs on small sources and overwhelmed the resources of permitting authorities.
In the rule, the EPA established two initial steps of phase-in to minimize those burdens, excluding
certain smaller sources from greenhouse gas permitting until at least April 30, 2016. On January 2,
2011, the first step of the phase-in applied only to new projects at major sources (as defined under
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those CAA permitting programs) that, among other things, increase net greenhouse gas emissions by
75,000 tons per year. On July 1, 2011, the second step of the phase-in began requiring permitting for
otherwise minor sources of air emissions that have the potential to emit at least 100,000 tons per year
of greenhouse gases. On June 29, 2012, the EPA issued final regulations for ‘‘Phase III’’ of its program,
retaining the permitting thresholds established in Phases I and II. These rules will affect some of our
and our customers’ largest new or modified facilities going forward.
Although it is not currently possible to predict how any proposed or future greenhouse gas
legislation or regulation by Congress, the states or multi-state regions will impact our business, any
legislation or regulation of greenhouse gas emissions that may be imposed in areas in which we conduct
business could result in increased compliance costs or additional operating restrictions or reduced
demand for our services, and could have a material adverse effect on our business, financial condition,
results of operations and cash flows.
Water Discharges
The CWA and analogous state laws and their implementing regulations impose restrictions and
strict controls with respect to the discharge of pollutants into state waters or waters of the U.S. The
discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a
permit issued by the EPA or an analogous state agency. In addition, the CWA regulates storm water
discharges associated with industrial activities depending on a facility’s primary standard industrial
classification. Many of our facilities have applied for and obtained industrial wastewater discharge
permits as well as sought coverage under local wastewater ordinances. In addition, many of those
facilities have filed notices of intent for coverage under statewide storm water general permits and
developed and implemented storm water pollution prevention plans, as required. U.S. federal laws also
require development and implementation of spill prevention, controls, and countermeasure plans,
including appropriate containment berms and similar structures to help prevent the contamination of
navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak at such facilities.
Waste Management and Disposal
The RCRA and analogous state laws and their implementing regulations govern the generation,
transportation, treatment, storage and disposal of hazardous and non-hazardous solid wastes. During
the course of our operations, we generate wastes (including, but not limited to, used oil, antifreeze,
filters, sludges, paints, solvents and abrasive blasting materials) in quantities regulated under RCRA.
The EPA and various state agencies have limited the approved methods of disposal for these types of
wastes. CERCLA and analogous state laws and their implementing regulations impose strict, and under
certain conditions, joint and several liability without regard to fault or the legality of the original
conduct on classes of persons who are considered to be responsible for the release of a hazardous
substance into the environment. These persons include current and past owners and operators of the
facility or disposal site where the release occurred and any company that transported, disposed of, or
arranged for the transport or disposal of the hazardous substances released at the site. Under
CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment, for damages to natural resources
and for the costs of certain health studies. In addition, where contamination may be present, it is not
uncommon for neighboring landowners and other third parties to file claims for personal injury,
property damage and recovery of response costs allegedly caused by hazardous substances or other
pollutants released into the environment.
We currently own or lease, and in the past have owned or leased, a number of properties that have
been used in support of our operations for a number of years. Although we have utilized operating and
disposal practices that were standard in the industry at the time, hydrocarbons, hazardous substances,
or other regulated wastes may have been disposed of or released on or under the properties owned or
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leased by us or on or under other locations where such materials have been taken for disposal by
companies sub-contracted by us. In addition, many of these properties have been previously owned or
operated by third parties whose treatment and disposal or release of hydrocarbons, hazardous
substances or other regulated wastes was not under our control. These properties and the materials
released or disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under such
laws, we could be required to remove or remediate historical property contamination, or to perform
certain operations to prevent future contamination. At certain of such sites, we are currently working
with the prior owners who have undertaken to monitor and clean up contamination that occurred prior
to our acquisition of these sites. We are not currently under any order requiring that we undertake or
pay for any cleanup activities. However, we cannot provide any assurance that we will not receive any
such order in the future.
Occupational Safety and Health
We are subject to the requirements of OSHA and comparable state statutes. These laws and the
implementing regulations strictly govern the protection of the safety and health of employees. The
OSHA hazard communication standard, the EPA community right-to-know regulations under Title III
of CERCLA and similar state statutes require that we organize and/or disclose information about
hazardous materials used or produced in our operations.
International Operations
Our operations outside the U.S. are subject to similar international governmental controls and
restrictions pertaining to the environment and other regulated activities in the countries in which we
operate. We believe our operations are in substantial compliance with existing international
governmental controls and restrictions and that compliance with these international controls and
restrictions has not had a material adverse effect on our operations. We cannot provide any assurance,
however, that we will not incur significant costs to comply with international controls and restrictions in
the future.
Employees
As of December 31, 2012, we had approximately 10,000 employees. We believe that our relations
with our employees are satisfactory.
Available Information
Our website address is www.exterran.com. Our annual reports on Form 10-K, quarterly reports on
Form 10-Q, current reports on Form 8-K and amendments to those reports are available on our
website, without charge, as soon as reasonably practicable after they are filed electronically with the
Securities and Exchange Commission (‘‘SEC’’). Information on our website is not incorporated by
reference in this report or any of our other securities filings. Paper copies of our filings are also
available, without charge, from Exterran Holdings, Inc., 16666 Northchase Drive, Houston, Texas 77060,
Attention: Investor Relations. Alternatively, the public may read and copy any materials we file with
the SEC at its Public Reference Room at 100 F Street, NE, Washington, DC 20549.
Information on the operation of the Public Reference Room may be obtained by calling the SEC
at 1-800-SEC-0330. The SEC also maintains a website that contains reports, proxy and information
statements and other information regarding issuers who file electronically with the SEC. The SEC’s
website address is www.sec.gov.
Additionally, we make available free of charge on our website:
(cid:127) our Code of Business Conduct;
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(cid:127) our Corporate Governance Principles; and
(cid:127) the charters of our audit, compensation, and nominating and corporate governance committees.
Item 1A. Risk Factors
As described in Part I (‘‘Disclosure Regarding Forward-Looking Statements’’), this report contains
forward-looking statements regarding us, our business and our industry. The risk factors described below,
among others, could cause our actual results to differ materially from the expectations reflected in the
forward-looking statements. If any of the following risks actually occurs, our business, financial condition,
results of operations and cash flows could be negatively impacted.
Natural gas prices in North America are at low levels, which could decrease demand for our natural gas
compression and oil and natural gas production and processing equipment and services and, as a result,
adversely affect our business.
Our results of operations depend upon the level of activity in the global energy market, including
natural gas development, production, processing and transportation. Oil and natural gas prices and the
level of drilling and exploration activity can be volatile. For example, oil and natural gas exploration
and development activity and the number of well completions typically decline when there is a
sustained reduction in oil or natural gas prices or significant instability in energy markets. Even the
perception of longer-term lower oil or natural gas prices by oil and natural gas exploration,
development and production companies can result in their decision to cancel, reduce or postpone major
expenditures or to reduce or shut in well production. In April 2012, natural gas prices in North
America fell to their lowest levels in more than a decade at around $2.00 per MMBtu. As a result,
certain companies reduced their natural gas drilling and production activities, particularly in more
mature and predominately dry gas areas in North America where we provide a significant amount of
contract operations services, which led to a decline in our contract operation business in these areas
during 2012. Since then, natural gas prices have improved somewhat to approximately $3.40 per
MMBtu as of December 2012, but still remain at historically low levels, which continues to result in a
reduction of natural gas drilling and production activities in more mature and predominately dry gas
areas. Additionally, in North America, compression services for our customers’ production from
unconventional natural gas sources constitute an increasing percentage of our business. Some of these
unconventional sources are less economic to produce in lower natural gas price environments. If the
current price levels for natural gas continue, the level of production activity and the demand for our
contract operations services and oil and natural gas production and processing equipment could
decrease, which could have a material adverse effect on our business, financial condition, results of
operations and cash flows. A reduction in demand for our products and services could also force us to
reduce our pricing substantially.
In addition, we review our long-lived assets for impairment when events or changes in
circumstances indicate the carrying value may not be recoverable. A decline in demand for oil and
natural gas or prices for those commodities, or instability in the North America or global energy
markets could cause a reduction in demand for our products and services and result in a reduction of
our estimates of future cash flows and growth rates in our business. These events could cause us to
record impairments of long-lived assets. For example, during the year ended December 31, 2011, we
recorded a goodwill impairment of $196.8 million; and during the years ended December 31, 2012,
2011 and 2010, we recorded long-lived asset impairments of $183.4 million, $6.1 million and
$143.9 million, respectively. Included in the impairments recorded in recent years are idle units we
retired from our fleet and expect to either sell these units or to re-utilize their key components. Selling
these compressor units is expected to take several years and, if we are not able to sell these units for
the amount we estimated in our impairment analysis, we could be required to record an additional
impairment. The impairment of our intangible assets or other long-lived assets could have a material
adverse effect on our results of operations.
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We have a substantial amount of debt that could limit our ability to fund future growth and operations and
increase our exposure to risk during adverse economic conditions.
At December 31, 2012, we had approximately $1.6 billion in outstanding debt obligations. Many
factors, including factors beyond our control, may affect our ability to make payments on our
outstanding indebtedness. These factors include those discussed elsewhere in these Risk Factors and
those listed in the Disclosure Regarding Forward-Looking Statements section included in Part I of this
report.
Our substantial debt and associated commitments could have important adverse consequences. For
example, these commitments could:
(cid:127) make it more difficult for us to satisfy our contractual obligations;
(cid:127) increase our vulnerability to general adverse economic and industry conditions;
(cid:127) limit our ability to fund future working capital, capital expenditures, acquisitions or other
corporate requirements;
(cid:127) increase our vulnerability to interest rate fluctuations because the interest payments on a portion
of our debt are based upon variable interest rates and a portion can adjust based upon our
credit statistics;
(cid:127) limit our flexibility in planning for, or reacting to, changes in our business and our industry;
(cid:127) place us at a disadvantage compared to our competitors that have less debt or less restrictive
covenants in such debt; and
(cid:127) limit our ability to refinance our debt in the future or borrow additional funds.
Covenants in our debt agreements may impair our ability to operate our business.
Our senior secured credit facility contains various covenants with which we or certain of our
subsidiaries must comply, including, but not limited to, restrictions on the use of proceeds from
borrowings and limitations on our ability to incur additional indebtedness, enter into transactions with
affiliates, merge or consolidate, sell assets, make certain investments and acquisitions, make loans, grant
liens, repurchase equity and pay dividends and distributions. We are also subject to financial covenants,
including a ratio of Adjusted EBITDA (as defined in the credit agreement) to Total Interest Expense
(as defined in the credit agreement) of not less than 2.25 to 1.0, a ratio of consolidated Total Debt to
Adjusted EBITDA of not greater than 5.0 to 1.0 and a ratio of Senior Secured Debt (as defined in the
credit agreement) to Adjusted EBITDA of not greater than 4.0 to 1.0. As of December 31, 2012, we
maintained a 5.3 to 1.0 Adjusted EBITDA to Total Interest Expense ratio, a 2.4 to 1.0 consolidated
Total Debt to Adjusted EBITDA ratio and a 0.2 to 1.0 Senior Secured Debt to Adjusted EBITDA
ratio. As of December 31, 2012, we were in compliance with all financial covenants under our debt
agreements. If we fail to remain in compliance with our financial covenants we would be in default
under our debt agreements. In addition, if we were to experience a material adverse effect on our
assets, liabilities, financial condition, business or operations that, taken as a whole, impacts our ability
to perform our obligations under our debt agreements, this could lead to a default under our debt
agreements.
The Partnership’s senior secured credit agreement (the ‘‘Partnership Credit Agreement’’) contains
various covenants with which the Partnership must comply, including, but not limited to, restrictions on
the use of proceeds from borrowings and limitations on its ability to incur additional indebtedness,
enter into transactions with affiliates, merge or consolidate, sell assets, make certain investments and
acquisitions, make loans, grant liens, repurchase equity and pay dividends and distributions. It also
contains various covenants requiring mandatory prepayments of the term loans from the net cash
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proceeds of certain future asset transfers. The Partnership must maintain various consolidated financial
ratios, including a ratio of EBITDA (as defined in the Partnership Credit Agreement) to Total Interest
Expense (as defined in the Partnership Credit Agreement) of not less than 3.0 to 1.0 (which will
decrease to 2.75 to 1.0 following the occurrence of certain events specified in the Partnership Credit
Agreement) and a ratio of Total Debt (as defined in the Partnership Credit Agreement) to EBITDA of
not greater than 4.75 to 1.0 (which will increase to 5.25 to 1.0 following the occurrence of certain
events specified in the Partnership Credit Agreement). As of December 31, 2012, the Partnership
maintained an 8.0 to 1.0 EBITDA to Total Interest Expense ratio and a 3.7 to 1.0 Total Debt to
EBITDA ratio. As of December 31, 2012, the Partnership was in compliance with all financial
covenants under the Partnership Credit Agreement.
As of December 31, 2012, the Partnership had undrawn capacity of $219.5 million under its
revolving credit facility. The Partnership Credit Agreement limits its Total Debt (as defined in the
Partnership Credit Agreement) to EBITDA ratio (as defined in the Partnership Credit Agreement) to
not greater than 4.75 to 1.0 (which will increase to 5.25 to 1.0 following the occurrence of certain
events specified in the Partnership Credit Agreement). As a result of this limitation, $199.4 million of
the $219.5 million of undrawn capacity under the Partnership’s revolving credit facility was available for
additional borrowings as of December 31, 2012.
The breach of any of our covenants could result in a default under one or more of our debt
agreements, which could cause our indebtedness under those agreements to become due and payable.
In addition, a default under one or more of our debt agreements, including a default by the
Partnership under its credit facility, would trigger cross-default provisions under certain of our debt
agreements, which would accelerate our obligation to repay our indebtedness under those agreements.
If the repayment obligations on any of our indebtedness were to be so accelerated, we may not be able
to repay the debt or refinance the debt on acceptable terms, and our financial position would be
materially adversely affected.
Failure to timely and cost-effectively execute on larger projects could adversely affect our business.
Some of our projects have a relatively larger size and scope than the majority of our projects,
which can translate into more technically challenging conditions or performance specifications for our
products and services. Contracts with our customers generally specify delivery dates, performance
criteria and penalties for our failure to perform. Any failure to execute such larger projects in a timely
and cost effective manner could have a material adverse effect on our business, financial condition,
results of operations and cash flows.
We may incur losses on fixed-price contracts, which constitute a significant portion of our fabrication
business.
In connection with projects covered by fixed-price contracts, we generally bear the risk of cost
over-runs, operating cost inflation, labor availability and productivity, and supplier and subcontractor
pricing and performance unless they result from customer-requested change orders. Under both our
fixed-price contracts and our cost-reimbursable contracts, we may rely on third parties for many support
services, and we could be subject to liability for their failures. For example, we have experienced losses
on certain large fabrication projects that have negatively impacted our fabrication results. Any failure to
accurately estimate our costs and the time required for a fixed-price fabrication project could have a
material adverse effect on our business, financial condition, results of operations and cash flows.
The erosion of the financial condition of our customers could adversely affect our business.
Many of our customers finance their exploration and development activities through cash flow
from operations, the incurrence of debt or the issuance of equity. During times when the oil or natural
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gas markets weaken, our customers are more likely to experience a downturn in their financial
condition. A reduction in borrowing bases under reserve-based credit facilities and the lack of
availability of debt or equity financing could result in a reduction in our customers’ spending for our
products and services. For example, our customers could seek to preserve capital by canceling
month-to-month contracts, canceling or delaying scheduled maintenance of their existing natural gas
compression and oil and natural gas production and processing equipment or determining not to enter
into any new natural gas compression service contracts or purchase new compression and oil and
natural gas production and processing equipment, thereby reducing demand for our products and
services. Reduced demand for our products and services could adversely affect our business, financial
condition, results of operations and cash flows. In addition, in the event of the financial failure of a
customer, we could experience a loss on all or a portion of our outstanding accounts receivable
associated with that customer.
There are many risks associated with conducting operations in international markets.
We operate in many countries outside the U.S., and these activities accounted for a substantial
amount of our revenue for the year ended December 31, 2012. We are exposed to risks inherent in
doing business in each of the countries where we operate. Our operations are subject to various risks
unique to each country that could have a material adverse effect on our business, financial condition,
results of operations and cash flows. For example, as discussed in Note 2 to the Financial Statements,
in 2009 the Venezuelan state-owned oil company, Petroleos de Venezuela S.A. (‘‘PDVSA’’), assumed
control over substantially all of our assets and operations in Venezuela.
In April 2012, Argentina assumed control over its largest oil and gas producer, Yacimientos
Petroliferos Fiscales (‘‘YPF’’). We had 541,000 horsepower of compression in Argentina as of
December 31, 2012, and we generated $157.6 million of revenue in Argentina, including $63 million of
revenue from YPF, during the year ended December 31, 2012. Recently we have been unable to
exchange Argentine pesos for U.S. dollars and as a result are unable to repatriate earnings from
Argentina, which subjects us to risk of currency devaluation on future earnings in Argentina. We are
unable to predict what effect, if any, the nationalization of YPF will have on our business in Argentina,
or whether Argentina will nationalize additional businesses in the oil and gas industry; however, the
nationalization of YPF, the nationalization of additional businesses or the taking of other actions listed
below by Argentina could have a material adverse effect on our business, financial condition, results of
operations and cash flows.
With respect to any particular country in which we operate, the risks inherent in our activities may
include the following:
(cid:127) difficulties in managing international operations, including our ability to timely and cost
effectively execute projects;
(cid:127) unexpected changes in regulatory requirements, laws or policies by foreign agencies or
governments;
(cid:127) work stoppages;
(cid:127) training and retaining qualified personnel in international markets;
(cid:127) the burden of complying with multiple and potentially conflicting laws and regulations;
(cid:127) tariffs and other trade barriers;
(cid:127) actions by governments or national oil companies that result in the nullification or renegotiation
on less than favorable terms of existing contracts, or otherwise result in the deprivation of
contractual rights, and other difficulties in enforcing contractual obligations;
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(cid:127) governmental actions that result in restricting the movement of property or that impede our
ability to import or export parts or equipment;
(cid:127) foreign currency exchange rate risks, including the risk of currency devaluations by foreign
governments;
(cid:127) difficulty in collecting international accounts receivable;
(cid:127) potentially longer receipt of payment cycles;
(cid:127) changes in political and economic conditions in the countries in which we operate, including
general political unrest, the nationalization of energy related assets, civil uprisings, riots,
kidnappings, violence associated with drug cartels and terrorist acts;
(cid:127) potentially adverse tax consequences or tax law changes;
(cid:127) currency controls or restrictions on repatriation of earnings;
(cid:127) expropriation, confiscation or nationalization of property without fair compensation;
(cid:127) the risk that our international customers may have reduced access to credit because of higher
interest rates, reduced bank lending or a deterioration in our customers’ or their lenders’
financial condition;
(cid:127) complications associated with installing, operating and repairing equipment in remote locations;
(cid:127) limitations on insurance coverage;
(cid:127) inflation;
(cid:127) the geographic, time zone, language and cultural differences among personnel in different areas
of the world; and
(cid:127) difficulties in establishing new international offices and the risks inherent in establishing new
relationships in foreign countries.
In addition, we may plan to expand our business in international markets where we have not
previously conducted business. The risks inherent in establishing new business ventures, especially in
international markets where local customs, laws and business procedures present special challenges,
may affect our ability to be successful in these ventures or avoid losses that could have a material
adverse effect on our business, financial condition, results of operations and cash flows.
We are due to receive a substantial amount in installment payments from the purchaser of our previously
nationalized Venezuelan assets, the nonpayment of which would reduce the anticipated amount of funds
available to us to repay indebtedness and for general corporate purposes.
As discussed in Notes 2 and 7 to the Financial Statements, in March 2012 and August 2012, we
sold our previously-nationalized Venezuelan joint venture assets and Venezuelan subsidiary assets,
respectively, to PDVSA Gas, S.A. (‘‘PDVSA Gas’’) for aggregate consideration of approximately
$550 million. As of December 31, 2012, we have received approximately $245 million of the total
($50 million of which we used to repay insurance proceeds previously collected under the policy we
maintained for the risk of expropriation) and are due to receive the remaining principal amount of
approximately $305 million in installments through the third quarter of 2016. We intend to use these
remaining proceeds, as they are received, for the repayment of indebtedness and for general corporate
purposes. Any failure by PDVSA Gas to pay these installments when due would reduce the amount of
funds available to us in the future for these purposes.
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We could be adversely affected by violations of the U.S. Foreign Corrupt Practices Act and similar worldwide
anti-bribery laws.
Our international operations require us to comply with a number of U.S. and international laws
and regulations, including those involving anti-bribery and anti-corruption. For example, the U.S.
Foreign Corrupt Practices Act (‘‘FCPA’’) and similar international laws and regulations prohibit
improper payments to foreign officials for the purpose of obtaining or retaining business. The scope
and enforcement of anti-corruption laws and regulations may vary.
We operate in many parts of the world that have experienced governmental corruption to some
degree and, in certain circumstances, strict compliance with anti-bribery laws may conflict with local
customs and practices. Our training and compliance program and our internal control policies and
procedures may not always protect us from reckless or negligent acts committed by our employees or
agents. Violations of these laws, or allegations of such violations, could disrupt our business and result
in a material adverse effect on our business and operations. We may be subject to competitive
disadvantages to the extent that our competitors are able to secure business, licenses or other
preferential treatment by making payments to government officials and others in positions of influence
or using other methods that are prohibited by U.S. and international laws and regulations.
To effectively compete in some foreign jurisdictions, we utilize local agents. Although we have
procedures and controls in place to monitor internal and external compliance, if we are found to be
liable for FCPA or other anti-bribery law violations (either due to our own acts or our inadvertence, or
due to the acts or inadvertence of others, including actions taken by our agents), we could suffer from
severe civil and criminal penalties or other sanctions, which could have a material adverse effect on our
business, financial condition, results of operations and cash flows.
We are exposed to exchange rate fluctuations in the international markets in which we operate. A decrease in
the value of any of these currencies relative to the U.S. dollar could reduce profits from international
operations and the value of our international net assets.
We operate in many international countries. We anticipate that there will be instances in which
costs and revenues will not be exactly matched with respect to currency denomination. We generally do
not hedge exchange rate exposures, which exposes us to the risk of exchange rate losses. Gains and
losses from the remeasurement of assets and liabilities that are receivable or payable in currency other
than our subsidiaries’ functional currency are included in our consolidated statements of operations. In
addition, currency fluctuations cause the U.S. dollar value of our international results of operations and
net assets to vary with exchange rate fluctuations. This could have a negative impact on our business,
financial condition or results of operations. In addition, fluctuations in currencies relative to currencies
in which the earnings are generated may make it more difficult to perform period-to-period
comparisons of our reported results of operations. For example, other (income) expense, net, for the
year ended December 31, 2012 includes a foreign currency loss of $8.2 million compared to a loss of
$16.5 million for the year ended December 31, 2011.
To the extent we expand geographically, we expect that increasing portions of our revenues, costs,
assets and liabilities will be subject to fluctuations in foreign currency valuations. We may experience
economic loss and a negative impact on earnings or net assets solely as a result of foreign currency
exchange rate fluctuations. Further, the markets in which we operate could restrict the removal or
conversion of the local or foreign currency, resulting in our inability to hedge against these risks.
We depend on distributions from our subsidiaries, including the Partnership, to meet our capital needs.
To generate the funds necessary to meet our obligations and fund our business, we depend on the
cash flows and distributions from our operating subsidiaries, including cash distributions from the
Partnership to us attributable to our ownership interest in the Partnership. Applicable law and
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contractual restrictions (including restrictions in the Partnership’s debt instruments and partnership
agreement) may negatively impact our ability to obtain such distributions from our subsidiaries,
including the rights of the creditors of the Partnership that would often be superior to our interests in
the Partnership. Furthermore, a decline in the Partnership’s revenues or increases in its expenses,
principal and interest payments under existing and future debt instruments, working capital
requirements or other cash needs would limit the amount of cash the Partnership has available to
distribute to its equity holders, including us, which would reduce the amount of cash available for
payment of our debt and to fund our business requirements, and as a result could have a material
adverse effect on our business, financial condition and results of operations.
We may be vulnerable to interest rate increases due to our floating rate debt obligations.
As of December 31, 2012, after taking into consideration interest rate swaps, we had approximately
$500.5 million of outstanding indebtedness that was effectively subject to floating interest rates.
Changes in economic conditions outside of our control could result in higher interest rates, thereby
increasing our interest expense and reducing the funds available for capital investment, operations or
other purposes. A 1% increase in the effective interest rate on our outstanding debt subject to floating
interest rates would result in an annual increase in our interest expense of approximately $5.0 million.
Many of our North America contract operations services contracts have short initial terms and after the initial
term are cancelable on short notice, and we cannot be sure that such contracts will be extended or renewed
after the end of the initial contractual term. Any such nonrenewal, or renewal at reduced rates, or the loss of
contracts with any significant customer, could adversely impact our result of operations.
The length of our contract operations services contracts with customers varies based on operating
conditions and customer needs. In North America, our initial contract terms typically are not long
enough to enable us to recoup the cost of the equipment we utilize to provide contract operations
services and these contracts are typically cancelable on short notice after the initial term. We cannot be
sure that a substantial number of these contracts will be extended or renewed by our customers or that
any of our customers will continue to contract with us. The inability to negotiate extensions or renew a
substantial portion of our North America contract operations services contracts, the renewal of such
contracts at reduced rates, the inability to contract for additional services with our customers or the
loss of all or a significant portion of our services contracts with any significant customer could lead to a
reduction in revenues and net income and could require us to record additional asset impairments. This
could have a material adverse effect upon our business, financial condition, results of operations and
cash flows.
Many of our international contract operations services contracts are long-term, substantial contracts and the
termination of any of such contracts could have a material impact on our business.
Our international contract operations services contracts are typically longer-term contracts for
more comprehensive projects than our North America contract operations services contracts. As a
result, the termination of any such contract may lead to a reduction in our revenues and net income,
which could have a material adverse effect upon our business, financial condition, results of operations
and cash flows.
We depend on particular suppliers and are vulnerable to product shortages and price increases.
Some of the components used in our products are obtained from a single source or a limited
group of suppliers. Our reliance on these suppliers involves several risks, including price increases,
inferior component quality and a potential inability to obtain an adequate supply of required
components in a timely manner. The partial or complete loss of certain of these sources could have a
negative impact on our results of operations and could damage our customer relationships. Further, a
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significant increase in the price of one or more of these components could have a negative impact on
our results of operations.
We face significant competitive pressures that may cause us to lose market share and harm our financial
performance.
Our businesses are highly competitive and there are low barriers to entry, especially our natural
gas compression services and fabrication business. We experience competition from companies that may
be able to adapt more quickly to technological changes within our industry and changes in economic
and market conditions, more readily take advantage of acquisitions and other opportunities and adopt
more aggressive pricing policies. Our ability to renew or replace existing contract operations service
contracts with our customers at rates sufficient to maintain current revenue and cash flows could be
adversely affected by the activities of our competitors. In our production and processing equipment
business, we have different competitors in the standard and custom-engineered equipment markets.
Competitors in the standard equipment market include several large companies and a large number of
small, regional fabricators. Competition in the standard equipment market is generally based upon
price and availability. Our competition in the custom-engineered market usually consists of larger
companies with the ability to provide integrated projects and product support after the sale. If our
competitors substantially increase the resources they devote to the development and marketing of
competitive products, equipment or services or substantially decrease the price at which they offer their
products, equipment or services, we may not be able to compete effectively.
In addition, we could face significant competition from new entrants into the compression services
and fabrication business. Some of our existing competitors or new entrants may expand or fabricate
new compression units that would create additional competition for the products, equipment or services
we provide to our customers.
We also may not be able to take advantage of certain opportunities or make certain investments
because of our significant leverage and our other obligations. Any of these competitive pressures could
have a material adverse effect on our business, financial condition and results of operations.
Our operations entail inherent risks that may result in substantial liability. We do not insure against all
potential losses and could be seriously harmed by unexpected liabilities.
Our operations entail inherent risks, including equipment defects, malfunctions and failures and
natural disasters, which could result in uncontrollable flows of natural gas or well fluids, fires and
explosions. These risks may expose us, as an equipment operator and fabricator, to liability for personal
injury, wrongful death, property damage, pollution and other environmental damage. The insurance we
carry against many of these risks may not be adequate to cover our claims or losses. We currently have
a minimal amount of insurance on our offshore assets. In addition, we are substantially self-insured for
worker’s compensation, employer’s liability, property, auto liability, general liability and employee group
health claims in view of the relatively high per-incident deductibles we absorb under our insurance
arrangements for these risks. Further, insurance covering the risks we expect to face or in the amounts
we desire may not be available in the future or, if available, the premiums may not be commercially
justifiable. If we were to incur substantial liability and such damages were not covered by insurance or
were in excess of policy limits, or if we were to incur liability at a time when we were not able to
obtain liability insurance, our business, financial condition and results of operations could be negatively
impacted.
Threats of cyber attacks or terrorism could affect our business.
We may be threatened by problems such as cyber attacks, computer viruses or terrorism that may
disrupt our operations and harm our operating results. Our industry requires the continued operation
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of sophisticated information technology systems and network infrastructure. Despite our
implementation of security measures, our technology systems are vulnerable to disability or failures due
to hacking, viruses, acts of war or terrorism and other causes. If our information technology systems
were to fail and we were unable to recover in a timely way, we might be unable to fulfill critical
business functions, which could have a material adverse effect on our business, financial condition and
results of operations.
In addition, our assets may be targets of terrorist activities that could disrupt our ability to service
our customers. We may be required by our regulators or by the future terrorist threat environment to
make investments in security that we cannot currently predict. The implementation of security
guidelines and measures and maintenance of insurance, to the extent available, addressing such
activities could increase costs. These types of events could materially adversely affect our business and
results of operations. In addition, these types of events could require significant management attention
and resources, and could adversely affect our reputation among customers and the public.
The tax treatment of the Partnership depends on its status as a partnership for U.S. federal income tax
purposes, as well as it not being subject to a material amount of entity-level taxation by individual states. The
Partnership could lose its status as a partnership for a number of reasons, including not having enough
‘‘qualifying income.’’ If the Internal Revenue Service treats the Partnership as a corporation or if the
Partnership becomes subject to a material amount of entity-level taxation for state tax purposes, it would
substantially reduce the amount of cash available for distribution to the Partnership’s unitholders and
undermine the cost of capital advantage we believe the Partnership has.
The anticipated after-tax economic benefit of an investment in the Partnership’s common units
depends largely on it being treated as a partnership for U.S. federal income tax purposes. The
Partnership has not received a ruling from the Internal Revenue Service (‘‘IRS’’) on this or any other
tax matter affecting it.
Despite the fact that the Partnership is a limited partnership under Delaware law, a publicly traded
partnership such as the Partnership will be treated as a corporation for federal income tax purposes
unless 90% or more of its gross income from its business activities are ‘‘qualifying income’’ under
Section 7704(d) of the Internal Revenue Code. ‘‘Qualifying income’’ includes income and gains derived
from the exploration, development, production, processing, transportation, storage and marketing of
natural gas and natural gas products or other passive types of income such as interest and dividends.
Although we do not believe based upon its current operations that the Partnership is treated as a
corporation, the Partnership could be treated as a corporation for federal income tax purposes or
otherwise subject to taxation as an entity if its gross income is not properly classified as qualifying
income, there is a change in the Partnership’s business or there is a change in current law.
If the Partnership were treated as a corporation for U.S. federal income tax purposes, it would pay
U.S. federal income tax at the corporate tax rate and would also likely pay state income tax. Treatment
of the Partnership as a corporation for U.S. federal income tax purposes would result in a material
reduction in the anticipated cash flow and after-tax return to its unitholders, likely causing a substantial
reduction in the value of its common units and the amount of distributions that we receive from the
Partnership.
Current law may change so as to cause the Partnership to be treated as a corporation for U.S.
federal income tax purposes or otherwise subject it to entity-level taxation. In addition, because of
widespread state budget deficits and other reasons, several states are evaluating ways to subject
partnerships to entity-level taxation through the imposition of state income, franchise and other forms
of taxation. The Partnership’s partnership agreement provides that if a law is enacted or existing law is
modified or interpreted in a manner that subjects it to taxation as a corporation or otherwise subjects it
to entity-level taxation for U.S. federal, state or local income tax purposes, the minimum quarterly
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distribution amount and the target distribution levels of the Partnership may be adjusted to reflect the
impact of that law on it at the option of its general partner without the consent of its unitholders. If
the Partnership were to be taxed at the entity level, it would lose the comparative cost of capital
advantage we believe it has over time as compared to a corporation.
The tax treatment of publicly traded partnerships or our investment in the Partnership’s common units could
be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a
retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including the
Partnership, or our investment in the Partnership may be modified by administrative, legislative or
judicial interpretation at any time. For example, judicial interpretations of the U.S. federal income tax
laws may have a direct or indirect impact on the Partnership’s status as a partnership and, in some
instances, a court’s conclusions may heighten the risk of a challenge regarding the Partnership’s status
as a partnership. Moreover from time to time, members of Congress may propose and consider
substantive changes to the existing U.S. federal income tax laws that could affect publicly traded
partnerships. One such legislative proposal would have eliminated the qualifying income exception to
the treatment of all publicly traded partnerships as corporations, upon which the Partnership relies for
its treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether
any of these changes, or other proposals, will be reconsidered or will ultimately be enacted. Any
modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied
retroactively and could make it more difficult or impossible to meet the ‘‘qualifying income’’ exception
for the Partnership to be treated as a partnership for U.S. federal income tax purposes. Any such
changes or differing judicial interpretations of existing laws could negatively impact the value of our
investment in the Partnership and the amount of distributions that we receive from the Partnership.
If the Partnership were treated as a corporation for U.S. federal income tax purposes, it would pay
U.S. federal income tax at the corporate tax rate and would also likely pay state income tax. Treatment
of the Partnership as a corporation for U.S. federal income tax purposes would result in a material
reduction in the anticipated cash flow and after-tax return to its unitholders, likely causing a substantial
reduction in the value of its common units and the amount of distributions that we receive from the
Partnership.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in
increased costs and additional delays to our exploration and production customers in drilling and completing
natural gas wells, which could adversely affect demand for our contract operations services and production
and processing equipment.
Hydraulic fracturing is an important and common practice that exploration and production
operators use to stimulate production of hydrocarbons, particularly natural gas, from dense subsurface
rock formations. The process involves the injection of water, sand and chemicals under pressure into
formations to fracture the surrounding rock and stimulate production. The process is typically regulated
by state oil and gas commissions but the EPA recently asserted federal regulatory authority under the
federal Safe Drinking Water Act over hydraulic fracturing involving the use of diesel. In addition, a
number of agencies including EPA, the U.S. Department of Energy, and the U.S. Department of the
Interior, along with Congressional committees, have been pursuing studies and other inquiries into the
potential environmental effects of hydraulic fracturing, the outcome of which could reach conclusions
that could give rise to new legislation or regulations. Legislation has been introduced before Congress
to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to
require disclosure of the chemicals used in the hydraulic fracturing process. The U.S. Bureau of Land
Management is expected to issue proposed regulations that, when finalized, would govern hydraulic
fracturing on public lands. At the state level, some states have adopted and other states are considering
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adopting legal requirements that could impose more stringent permitting, disclosure, and well
construction requirements on hydraulic fracturing activities. Local governments also may seek to adopt
ordinances within their jurisdictions regulating the time, place and manner of drilling activities in
general or hydraulic fracturing activities in particular. In the event that new or more stringent federal,
state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where
our natural gas exploration and production customers operate, those customers could incur potentially
significant added costs to comply with such requirements and experience delays or curtailment in the
pursuit of production or development activities, which could reduce demand for our contract operations
services and oil and natural gas production and processing equipment, and as a result could have a
material adverse effect on our business, financial condition, results of operations and cash flows.
New regulations, proposed regulations and proposed modifications to existing regulations under the CAA, if
implemented, could result in increased compliance costs.
On August 20, 2010, the EPA published new regulations under the CAA to control emissions of
hazardous air pollutants from existing stationary reciprocal internal combustion engines. The rule would
have required us to undertake certain expenditures and activities, including purchasing and installing
emissions control equipment, such as oxidation catalysts or non-selective catalytic reduction equipment,
on a portion of our engines located at certain sources of hazardous air pollutants and all our engines
over a certain size regardless of location, following prescribed maintenance practices for engines (which
are consistent with our existing practices), and implementing additional emissions testing and
monitoring. Following legal challenges to the 2010 rule, the EPA reconsidered the rule and published
revisions to the rule on January 30, 2013. The revised rule will require management practices for all
covered engines but will require catalyst installation only on larger equipment at sites that are not
deemed to be ‘‘remote.’’ Since the rule has just recently been finalized, we are in the process of
determining the amount of our larger equipment at non-remote sites, and, as a result, we cannot
currently accurately predict the cost to comply with the rule’s requirements. Compliance with the final
rule is required by October 2013.
On May 21, 2012, the EPA issued new ozone nonattainment designations for all areas except
Chicago, in relation to the 2008 NAAQS for ozone. Among other things, these new designations add
Wise County to the DFW nonattainment area. This new designation will require Texas to modify its
SIP to include a plan for Wise County to come into compliance with the ozone NAAQS. This
modification process typically takes about three to five years. If Texas implements the same control
requirements in Wise County that are already in place in the other counties in the DFW nonattainment
area, we could be required to modify or remove and replace a significant amount of equipment we
currently utilize in Wise County. However, at this point we cannot predict what Texas’ new SIP will
require or what equipment will still be operating in Wise County when it comes into effect and, as a
result, we cannot currently accurately predict the impact or cost to comply.
On August 16, 2012, the EPA published final rules that establish new air emission controls for
natural gas and natural gas liquids production, processing and transportation activities, including New
Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds,
and a separate set of emission standards to address hazardous air pollutants frequently associated with
production and processing activities. Among other things, the rules establish specific requirements
regarding emissions from compressors and controllers at natural gas gathering and boosting stations
and processing plants together with dehydrators and storage tanks at natural gas processing plants,
compressor stations and gathering and boosting stations. In addition, the rules establish new
requirements for leak detection and repair of leaks at natural gas processing plants that exceed 500
parts per million in concentration.
In addition, in January 2011, the TCEQ finalized revisions to certain air permit programs that
significantly increase air emissions-related requirements for new and certain existing oil and gas
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production and gathering sites in the Barnett Shale production area. The final rule established new
emissions standards for engines, which could impact the operation of specific categories of engines by
requiring the use of alternative engines, compressor packages or the installation of aftermarket
emissions control equipment. The rule became effective for the Barnett Shale production area in April
2011, and the lower emissions standards will become applicable between 2015 and 2030 depending on
the type of engine and the permitting requirements. A number of other states where our engines are
operated have adopted or are considering adopting additional regulations that could impose new air
permitting or pollution control requirements for engines, some of which could entail material costs to
comply. At this point, however, we cannot predict whether any such rules would require us to incur
material costs.
These new regulations and proposals, when finalized, and any other new regulations requiring the
installation of more sophisticated pollution control equipment or the adoption of other environmental
protection measures, could have a material adverse impact on our business, financial condition, results
of operations and cash flows.
We are subject to a variety of governmental regulations; failure to comply with these regulations may result in
administrative, civil and criminal enforcement measures.
We are subject to a variety of U.S. federal, state, local and international laws and regulations
relating to the environment, safety and health, export controls, currency exchange, labor and
employment and taxation. Many of these laws and regulations are complex, change frequently, are
becoming increasingly stringent, and the cost of compliance with these requirements can be expected to
increase over time. Failure to comply with these laws and regulations may result in a variety of
administrative, civil and criminal enforcement measures, including assessment of monetary penalties,
imposition of remedial requirements and issuance of injunctions as to future compliance. From time to
time, as part of our operations, including newly acquired operations, we may be subject to compliance
audits by regulatory authorities in the various countries in which we operate.
Environmental laws and regulations may, in certain circumstances, impose strict liability for
environmental contamination, which may render us liable for remediation costs, natural resource
damages and other damages as a result of our conduct that was lawful at the time it occurred or the
conduct of, or conditions caused by, prior owners or operators or other third parties. In addition, where
contamination may be present, it is not uncommon for neighboring land owners and other third parties
to file claims for personal injury, property damage and recovery of response costs. Remediation costs
and other damages arising as a result of environmental laws and regulations, and costs associated with
new information, changes in existing environmental laws and regulations or the adoption of new
environmental laws and regulations could be substantial and could negatively impact our financial
condition, profitability and results of operations.
We may need to apply for or amend facility permits or licenses from time to time with respect to
storm water or wastewater discharges, waste handling, or air emissions relating to manufacturing
activities or equipment operations, which subjects us to new or revised permitting conditions that may
be onerous or costly to comply with. In addition, certain of our customer service arrangements may
require us to operate, on behalf of a specific customer, petroleum storage units such as underground
tanks or pipelines and other regulated units, all of which may impose additional compliance and
permitting obligations.
We conduct operations at numerous facilities in a wide variety of locations across the continental
U.S. and internationally. The operations at many of these facilities require environmental permits or
other authorizations. Additionally, natural gas compressors at many of our customers’ facilities require
individual air permits or general authorizations to operate under various air regulatory programs
established by rule or regulation. These permits and authorizations frequently contain numerous
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compliance requirements, including monitoring and reporting obligations and operational restrictions,
such as emission limits. Given the large number of facilities in which we operate, and the numerous
environmental permits and other authorizations that are applicable to our operations, we may
occasionally identify or be notified of technical violations of certain requirements existing in various
permits or other authorizations. Occasionally, we have been assessed penalties for our non-compliance,
and we could be subject to such penalties in the future.
We routinely deal with natural gas, oil and other petroleum products. Hydrocarbons or other
hazardous substances or wastes may have been disposed or released on, under or from properties used
by us to provide contract operations services or inactive compression storage or on or under other
locations where such substances or wastes have been taken for disposal. These properties may be
subject to investigatory, remediation and monitoring requirements under environmental laws and
regulations.
The modification or interpretation of existing environmental laws or regulations, the more vigorous
enforcement of existing environmental laws or regulations, or the adoption of new environmental laws
or regulations may also negatively impact oil and natural gas exploration and production, gathering and
pipeline companies, including our customers, which in turn could have a negative impact on us.
Climate change legislation and regulatory initiatives could result in increased compliance costs.
The U.S. Congress has considered legislation to restrict or regulate emissions of greenhouse gases,
such as carbon dioxide and methane. One bill, passed by the House of Representatives, if enacted by
the full Congress, would have required greenhouse gas emissions reductions by covered sources of as
much as 17% from 2005 levels by 2020 and by as much as 83% by 2050. It presently appears unlikely
that comprehensive climate legislation will be passed by either house of Congress in the near future,
although energy legislation and other initiatives continue to be proposed that may be relevant to
greenhouse gas emissions issues. In addition, almost half of the states, either individually or through
multi-state regional initiatives, have begun to address greenhouse gas emissions, primarily through the
planned development of emission inventories or regional greenhouse gas cap and trade programs.
Although most of the state-level initiatives have to date been focused on large sources of greenhouse
gas emissions, such as electric power plants, it is possible that smaller sources such as our gas-fired
compressors could become subject to greenhouse gas-related regulation. Depending on the particular
program, we could be required to control emissions or to purchase and surrender allowances for
greenhouse gas emissions resulting from our operations.
Independent of Congress, the EPA is beginning to adopt regulations controlling greenhouse gas
emissions under its existing CAA authority. The EPA has adopted rules requiring many facilities,
including petroleum and natural gas systems, to inventory and report their greenhouse gas emissions.
These rules triggered reporting obligations for several sites we operated all or most of 2012.
In addition, the EPA in June 2010 published a final rule providing for the tailored applicability of
air permitting requirements for greenhouse gas emissions. The EPA reported that the rulemaking was
necessary because without it certain permitting requirements would apply as of January 2011 at an
emissions level that would have greatly increased the number of required permits and, among other
things, imposed undue costs on small sources and overwhelmed the resources of permitting authorities.
In the rule, the EPA established two initial steps of phase-in to minimize those burdens, excluding
certain smaller sources from greenhouse gas permitting until at least April 30, 2016. On January 2,
2011, the first step of the phase-in applied only to new projects at major sources (as defined under
those CAA permitting programs) that, among other things, increase net greenhouse gas emissions by
75,000 tons per year. On July 1, 2011, the second step of the phase-in began requiring permitting for
otherwise minor sources of air emissions that have the potential to emit at least 100,000 tons per year
of greenhouse gases. On June 29, 2012, the EPA issued final regulations for ‘‘Phase III’’ of its program,
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retaining the permitting thresholds established in Phases I and II. These rules will affect some of our
and our customers’ largest new or modified facilities going forward.
Although it is not currently possible to predict how any proposed or future greenhouse gas
legislation or regulation by Congress, the states or multi-state regions will impact our business, any
legislation or regulation of greenhouse gas emissions that may be imposed in areas in which we conduct
business could result in increased compliance costs or additional operating restrictions or reduced
demand for our services, and could have a material adverse effect on our business, financial condition,
results of operations and cash flows.
The price of our common stock and the Partnership’s common units may be volatile.
Some of the factors that could affect the price of our common stock are quarterly increases or
decreases in revenue or earnings, changes in revenue or earnings estimates by the investment
community and speculation in the press or investment community about our financial condition or
results of operations. General market conditions and North America or international economic factors
and political events unrelated to our performance may also affect our stock price. In addition, the price
of our common stock may be impacted by changes in the value of our investment in the Partnership.
For these reasons, investors should not rely on recent trends in the price of our common stock to
predict the future price of our common stock or our financial results.
We may not be able to consummate additional contributions or sales of portions of our U.S. contract
operations business to the Partnership.
As part of our business strategy, we intend to contribute or sell the remainder of our U.S. contract
operations business to the Partnership, over time, but we are under no obligation to do so. Likewise,
the Partnership is under no obligation to purchase any additional portions of that business. The
consummation of any future sales of additional portions of that business and the timing of such sales
will depend upon, among other things:
(cid:127) our ability to continue to convert our existing U.S. compression agreements to a form of service
agreement;
(cid:127) our agreement with the Partnership regarding the terms of such sales, which will require the
approval of the conflicts committee of the board of directors of the Partnership’s general
partner, which is comprised exclusively of independent directors;
(cid:127) the Partnership’s ability to finance such purchases on acceptable terms, which could be impacted
by general equity and debt market conditions as well as conditions in the markets specific to
master limited partnerships; and
(cid:127) the Partnership’s and our compliance with our respective debt agreements.
The Partnership intends to fund its future acquisitions from us with external sources of capital,
including additional borrowings under its credit facility and/or public or private offerings of equity or
debt. If the Partnership is not able to fund future acquisitions of our U.S. contract operations business,
or if we are otherwise unable to consummate additional contributions or sales of our U.S. contract
operations business to the Partnership, we may not be able to capitalize on what we believe is the
Partnership’s lower cost of capital over time, which could impact our competitive position in the U.S.
Additionally, without the proceeds from future contributions or sales of our U.S. contract operations
business to the Partnership, we will have less capital to invest to grow our business.
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Our charter and bylaws contain provisions that may make it more difficult for a third party to acquire control
of us, even if a change in control would result in the purchase of our stockholders’ shares of common stock at
a premium to the market price or would otherwise be beneficial to our stockholders.
There are provisions in our restated certificate of incorporation and bylaws that may make it more
difficult for a third party to acquire control of us, even if a change in control would result in the
purchase of our stockholders’ shares of common stock at a premium to the market price or would
otherwise be beneficial to our stockholders. For example, our restated certificate of incorporation
authorizes the board of directors to issue preferred stock without stockholder approval. If our board of
directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In
addition, provisions of our restated certificate of incorporation and bylaws, such as limitations on
stockholder actions by written consent and on stockholder proposals at meetings of stockholders, could
make it more difficult for a third party to acquire control of us. Delaware corporation law may also
discourage takeover attempts that have not been approved by the board of directors.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
The following table describes the material facilities we owned or leased as of December 31, 2012:
Location
Status
Square Feet
Uses
Houston, Texas . . . . . . . . . . . . . . . Leased
Oklahoma City, Oklahoma . . . . . . Owned
243,746
41,250
Yukon, Oklahoma . . . . . . . . . . . . . Owned
72,000
Belle Chase, Louisiana . . . . . . . . . Owned
35,000
Casper, Wyoming . . . . . . . . . . . . . Owned
28,390
Davis, Oklahoma . . . . . . . . . . . . . Owned
393,870
Edmonton, Alberta, Canada . . . . . Leased
53,557
Farmington, New Mexico . . . . . . . . Owned
42,097
Houma, Louisiana . . . . . . . . . . . . Owned
60,000
Kilgore, Texas . . . . . . . . . . . . . . . . Owned
32,995
Midland, Texas . . . . . . . . . . . . . . . Owned
53,300
Midland, Texas . . . . . . . . . . . . . . . Owned
22,180
Pampa, Texas . . . . . . . . . . . . . . . . Leased
24,000
Victoria, Texas . . . . . . . . . . . . . . . Owned
59,852
Corporate office
North America contract operations and
aftermarket services
North America contract operations and
aftermarket services
North America contract operations and
aftermarket services
North America contract operations and
aftermarket services
North America contract operations and
aftermarket services
North America contract operations and
aftermarket services
North America contract operations and
aftermarket services
North America contract operations and
aftermarket services
North America contract operations and
aftermarket services
North America contract operations and
aftermarket services
North America contract operations and
aftermarket services
North America contract operations and
aftermarket services
North America contract operations and
aftermarket services
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Location
Status
Square Feet
Uses
Camacari, Brazil . . . . . . . . . . . . . . Owned
86,111
Neuquen, Argentina . . . . . . . . . . . Leased
48,760
Reynosa, Mexico . . . . . . . . . . . . . . Owned
24,347
Comodoro Rivadavia, Argentina . . Owned
26,000
Neuquen, Argentina . . . . . . . . . . . Owned
38,798
Santa Cruz, Bolivia . . . . . . . . . . . . Leased
22,017
Bangkok, Thailand . . . . . . . . . . . . Leased
Port Harcourt, Nigeria . . . . . . . . . Leased
Broussard, Louisiana . . . . . . . . . . . Owned
Houston, Texas . . . . . . . . . . . . . . . Owned
Houston, Texas . . . . . . . . . . . . . . . Owned
Schulenburg, Texas . . . . . . . . . . . . Owned
Broken Arrow, Oklahoma . . . . . . . Owned
Columbus, Texas . . . . . . . . . . . . . . Owned
Aldridge, United Kingdom . . . . . . Owned
Jebel Ali Free Zone, UAE . . . . . . Leased
Hamriyah Free Zone, UAE . . . . . . Leased
Mantova, Italy . . . . . . . . . . . . . . . Owned
Singapore, Singapore . . . . . . . . . . Leased
36,611
32,808
74,402
343,750
244,000
22,675
141,549
219,552
44,700
112,378
212,742
654,397
111,693
International contract operations and
aftermarket services
International contract operations and
aftermarket services
International contract operations and
aftermarket services
International contract operations and
aftermarket services
International contract operations and
aftermarket services
International contract operations and
aftermarket services
Aftermarket services
Aftermarket services
Fabrication, North America contract
operations and aftermarket services
Fabrication
Fabrication
Fabrication
Fabrication
Fabrication
Fabrication
Fabrication
Fabrication
Fabrication
Fabrication
Our executive offices are located at 16666 Northchase Drive, Houston, Texas 77060 and our
telephone number is (281) 836-7000.
Item 3. Legal Proceedings
In the ordinary course of business we are involved in various pending or threatened legal actions.
While management is unable to predict the ultimate outcome of these actions, it believes that any
ultimate liability arising from any of these actions will not have a material adverse effect on our
consolidated financial position, results of operations or cash flows. However, because of the inherent
uncertainty of litigation, we cannot provide assurance that the resolution of any particular claim or
proceeding to which we are a party will not have a material adverse effect on our consolidated financial
position, results of operations or cash flows for the period in which the resolution occurs.
Item 4. Mine Safety Disclosures
Not applicable.
33
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2 C Cs: 15664
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities
Our common stock is traded on the New York Stock Exchange under the symbol ‘‘EXH.’’ The
following table sets forth the range of high and low sale prices for our common stock for the periods
indicated.
Year ended December 31, 2011
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year ended December 31, 2012
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Price
High
Low
$25.43
$24.31
$20.21
$12.61
$15.23
$14.31
$20.47
$22.23
$21.09
$19.37
$ 8.07
$ 8.26
$ 8.79
$10.58
$12.57
$19.09
On February 19, 2013, the closing price of our common stock was $24.85 per share. As of
February 12, 2013, there were approximately 1,434 holders of record of our common stock.
The performance graph below shows the cumulative total stockholder return on our common
stock, compared with the S&P 500 Composite Stock Price Index (the ‘‘S&P 500 Index’’) and the
Oilfield Service Index (the ‘‘OSX’’) over the five-year period beginning on December 31, 2007. The
results are based on an investment of $100 in each of our common stock, the S&P 500 Index and the
OSX. The graph assumes the reinvestment of dividends and adjusts all closing prices and dividends for
stock splits.
34
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2 C Cs: 44640
Comparison of Five Year Cumulative Total Return
s
r
a
l
l
o
D
120
100
80
60
40
20
0
12/31/2007
12/31/2008
12/31/2009
12/31/2010
12/31/2011
12/31/2012
EXH
S&P 500
OSX
27FEB201315481788
The performance graph shall not be deemed incorporated by reference by any general statement
incorporating by reference this Annual Report on Form 10-K into any filing under the Securities Act of 1933
or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate this information
by reference, and shall not otherwise be deemed filed under those Acts.
We have never declared or paid any cash dividends to our stockholders and do not anticipate
paying such dividends in the foreseeable future. The board of directors anticipates that all cash flow
generated from operations in the foreseeable future will be retained and used to pay down debt or
develop and expand our business, except for a portion of the cash flow generated from operations of
the Partnership which is expected to be used to pay distributions on its units. Any future
determinations to pay cash dividends to our stockholders will be at the discretion of the board of
directors and will be dependent upon our financial condition and results of operations, credit and loan
agreements in effect at that time and other factors deemed relevant by the board of directors.
For disclosures regarding securities authorized for issuance under equity compensation plans, see
Part III, Item 12 (‘‘Security Ownership of Certain Beneficial Owners and Management’’) of this report.
Item 6. Selected Financial Data
In the table below we have presented certain selected financial data for Exterran for each of the
five years in the period ended December 31, 2012, which has been derived from our audited
consolidated financial statements. As discussed in Note 2 to the Financial Statements, the results from
continuing operations for all periods presented exclude the results of our Venezuelan contract
operations and aftermarket services businesses and Canadian contract operations and aftermarket
services businesses. Those results are reflected in discontinued operations for all periods presented. The
following information should be read together with Management’s Discussion and Analysis of Financial
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Condition and Results of Operations and the Financial Statements contained in this report (in
thousands, except per share data):
Years Ended December 31,
2012
2011
2010
2009
2008
Statement of Operations Data:
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . $2,803,602 $2,629,879 $2,417,183 $2,663,678 $2,953,802
1,003,571
834,223
Gross margin(1) . . . . . . . . . . . . . . . . . . . . .
347,194
376,359
Selling, general and administrative . . . . . . .
11,384
—
Merger and integration expenses . . . . . . . . .
323,125
350,847
Depreciation and amortization . . . . . . . . . .
24,109
183,445
Long-lived asset impairment(2) . . . . . . . . . .
Restructuring charges(3) . . . . . . . . . . . . . . .
—
6,636
1,148,371
Goodwill impairment(4) . . . . . . . . . . . . . . .
129,784
Interest expense . . . . . . . . . . . . . . . . . . . . .
Equity in (income) loss of non-consolidated
affiliates(5) . . . . . . . . . . . . . . . . . . . . . . .
Other (income) expense, net(6)
. . . . . . . . .
Provision for (benefit from) income taxes . .
Loss from continuing operations . . . . . . . . .
Income (loss) from discontinued operations,
net of tax(7) . . . . . . . . . . . . . . . . . . . . . .
900,505
797,088
333,979
351,998
—
—
344,168
392,153
96,988
143,874
—
13,864
— 150,778
122,845
728,427
352,780
—
356,972
6,068
11,594
— 196,807
149,473
609
(11,413)
(62,302)
(153,980)
471
(5,620)
(10,605)
(329,513)
(51,483)
430
(62,375)
(104,012)
91,154
(51,909)
50,390
(251,752)
(23,974)
719
35,214
(992,355)
(293,711)
(10,105)
134,376
136,149
40,739
66,843
57,279
Net income (loss) attributable to
noncontrolling interest
. . . . . . . . . . . . . .
Net loss attributable to Exterran stockholders
Loss per share from continuing operations:
2,317
(39,486)
990
(340,608)
(11,416)
(101,825)
3,944
(549,407)
12,273
(947,349)
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . $
(1.68) $
(1.68) $
(5.28) $
(5.28) $
(2.30) $
(2.30) $
(4.16) $
(4.16) $
(15.56)
(15.56)
Weighted average common and equivalent
shares outstanding:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . .
63,436
63,436
62,624
62,624
61,995
61,995
61,406
61,406
64,580
64,580
Other Financial Data:
EBITDA, as adjusted(8) . . . . . . . . . . . . . . . $ 464,840 $ 395,441 $ 445,385 $ 589,414 $ 689,386
Capital expenditures:
Contract Operations Equipment:
Growth . . . . . . . . . . . . . . . . . . . . . . . . $ 261,548 $ 132,986 $ 126,650 $ 244,964 $ 253,211
128,181
Maintenance . . . . . . . . . . . . . . . . . . . .
75,416
Other . . . . . . . . . . . . . . . . . . . . . . . . . . .
100,208
66,975
90,477
48,722
69,257
35,700
80,148
36,345
Cash flows provided by (used in):
Operating activities . . . . . . . . . . . . . . . . . $ 389,925 $ 120,443 $ 366,313 $ 479,870 $ 496,356
(582,901)
(205,451)
. . . . . . . . . . . . . . . . .
Investing activities
86,398
(171,290)
Financing activities . . . . . . . . . . . . . . . . .
(102,965)
(298,667)
(301,000)
(224,004)
(239,184)
99,290
Balance Sheet Data:
Cash and cash equivalents . . . . . . . . . . . . . $
Working capital(9) . . . . . . . . . . . . . . . . . . .
Property, plant and equipment, net . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt . . . . . . . . . . . . . . . . . . . . .
Total Exterran stockholder’s equity . . . . . . .
34,601 $
463,429
2,842,031
4,254,847
1,564,923
1,478,613
21,903 $
454,046
2,934,664
4,360,662
1,773,039
1,437,236
44,361 $
402,401
3,014,598
4,741,536
1,897,147
1,609,448
81,552 $ 119,361
777,909
582,128
3,367,291
3,326,067
6,092,627
5,292,948
2,512,429
2,260,936
2,043,786
1,639,997
(1) Gross margin, a non-GAAP financial measure, is defined, reconciled to net income (loss) and discussed
further in Part II, Item 6 (‘‘Selected Financial Data—Non-GAAP Financial Measures’’) of this report.
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(2) For the year ended December 31, 2012: During 2012, we evaluated the future deployment of our
idle fleet and determined to retire and either sell or re-utilize key components of approximately
930 idle compressor units, representing approximately 318,000 horsepower, that we previously used
to provide services in our North America contract operations segment. As a result, we performed
an impairment review and recorded a $97.1 million asset impairment to reduce the book value of
each unit to its estimated fair value. The fair value of each unit was estimated based on the
expected net sale proceeds compared to other fleet units we recently sold, as well as our review of
other units recently offered for sale by third parties, or the estimated component value of the
equipment we plan to use.
In connection with our review of our fleet in 2012, we evaluated for impairment idle units that had
been culled from our fleet in prior years and were available for sale. Based upon that review, we
reduced the expected proceeds from disposition for most of the remaining units and increased the
weighted average disposal period for the units from the assumptions used in prior periods. This
resulted in an additional impairment of $34.8 million to reduce the book value of each unit to its
estimated fair value.
In the fourth quarter of 2012, we committed to a plan to abandon our contract water treatment
business as part of our continued emphasis on simplification and focus on our core businesses. In
conjunction with the planned abandonment, we recorded an impairment of long-lived assets of
$46.8 million, including property, plant and equipment impairment of $17.7 million and intangible
assets impairment of $29.1 million. The fair value of our contract water treatment assets was based
on projected cash flows of active assets currently under contract, which expire in 2013, and
expected net sales proceeds of idle assets that have been culled from our fleet. We expect the
abandonment of our contract water treatment business to be completed by December 31, 2013.
During 2012, we evaluated other long-lived assets for impairment and recorded long-lived asset
impairments of $4.7 million on these assets.
For the year ended December 31, 2011: During 2011, we reviewed the idle compression assets used
in our contract operations segments for units that were not of the type, configuration, make or
model that are cost effective to maintain and operate. Our estimate of the fair value of the
impaired long-lived assets was based on the expected net sale proceeds compared to other fleet
units we recently sold, as well as our review of other units recently offered for sale by third parties,
or the estimated component value of the equipment we plan to use. The net book value of these
assets exceeded the fair value by $5.7 million for the year ended December 31, 2011 and was
recorded as a long-lived asset impairment. In addition, in the fourth quarter of 2011, we recorded
a $0.4 million impairment of other long-lived assets.
For the year ended December 31, 2010: During 2010, we completed an evaluation of our
longer-term strategies and determined to retire and sell approximately 1,800 idle compressor units,
or approximately 600,000 horsepower, that we previously used to provide services in our North
America and international contract operations businesses. As a result, we performed an
impairment review and recorded a $133.0 million asset impairment to reduce the book value of
each unit to its estimated fair value. The fair value of each unit was estimated based on the
expected net sale proceeds compared to other fleet units we recently sold, as well as our review of
other units that were recently for sale by third parties. During 2010, we also reviewed the idle
compression assets used in our contract operations segments for units that were not of the type,
configuration, make or model that are cost effective to maintain and operate and determined to
retire 323 units representing 61,400 horsepower from the fleet in 2010. We performed a cash flow
analysis of the expected proceeds from the salvage value of these units to determine the fair value
of the assets. The net book value of these assets exceeded the fair value by $7.6 million and this
amount was recorded as a long-lived asset impairment. In addition, in the fourth quarter of 2010,
105 fleet units that we previously utilized in our international contract operations segment were
damaged in a flood, resulting in a long-lived asset impairment of $3.3 million.
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For the year ended December 31, 2009: As a result of a decline in market conditions and
operating horsepower in North America during 2009, we reviewed the idle compression assets used
in our contract operations segments for units that were not of the type, configuration, make or
model that were cost effective to maintain and operate and determined that 1,232 units
representing 264,900 horsepower would be retired from the fleet. We performed a cash flow
analysis of the expected proceeds from the salvage value of these units to determine the fair value
of the fleet assets we would no longer utilize in our operations. The net book value of these assets
exceeded the fair value by $91.0 million and this amount was recorded as a long-lived asset
impairment. In addition, during the year ended December 31, 2009, we recorded $6.0 million of
facility impairments.
For the year ended December 31, 2008: During 2008, management identified certain fleet units
that would not be used in our contract operations business in the future and recorded a
$1.5 million impairment at that time. During 2008, we also recorded a $1.0 million impairment
related to the loss sustained on offshore units that were on platforms that capsized during
Hurricane Ike.
We were involved in a project in the Cawthorne Channel in Nigeria (the ‘‘Cawthorne Channel
Project’’) to process natural gas from certain Nigerian oil and natural gas fields. As a result of
operational difficulties and taking into consideration the project’s historical performance and
declines in commodity prices, we undertook an assessment of our estimated future cash flows from
the Cawthorne Channel Project. Based on the analysis, we did not believe that we would recover
all of our remaining investment in the Cawthorne Channel Project. Accordingly, we recorded an
impairment charge of $21.6 million in our 2008 results to reduce the carrying amount of our assets
associated with the Cawthorne Channel Project to their estimated fair value, which is reflected in
Long-lived asset impairment expense in our consolidated statements of operations.
(3) For the years ended December 31, 2012 and 2011: In November 2011, we announced a workforce
cost reduction program across all of our business segments as a first step in a broader overall
profit improvement initiative. These actions were the result of a review of our cost structure aimed
at identifying ways to reduce our on-going operating costs and to adjust the size of our workforce
to be consistent with current and expected activity levels.
For the year ended December 31, 2009: As a result of the reduced level of demand for our
products and services, our management approved a plan in March 2009 to close certain facilities to
consolidate our compression fabrication activities in our fabrication segment. These actions were
the result of significant fabrication capacity stemming from the 2007 merger that created Exterran
and the lack of consolidation of this capacity since that time, as well as the anticipated
continuation of current weaker global economic and energy industry conditions. The consolidation
of those compression fabrication activities was completed in September 2009. In August 2009, we
announced our plan to consolidate certain fabrication operations in Houston, including the closure
of two facilities in Texas. However, due to a subsequent improvement in bookings for certain of
our production and processing equipment products, we ultimately decided to close only one of the
fabrication facilities in Texas. In addition, we implemented cost reduction programs during 2009
primarily related to workforce reductions across all of our segments.
(4) For the year ended December 31, 2011: As a result of the level of decline in our stock price and
corresponding market capitalization in the third quarter of 2011, we performed a goodwill
impairment test of our aftermarket services and fabrication reporting units’ goodwill as of
September 30, 2011. We determined the fair value of these reporting units using the expected
present value of future cash flows. This decline in our market capitalization led us to increase the
estimate of the market’s implied weighted average cost of capital and reduce the present value of
the forecasted cash flows. The test indicated that our aftermarket services and fabrication reporting
units’ goodwill was impaired and therefore we recorded a full impairment of our remaining
goodwill during 2011 of $196.8 million.
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For the year ended December 31, 2009: As discussed in Note 2 to the Financial Statements, in
June 2009 PDVSA assumed control over substantially all of our assets and operations in
Venezuela. As a result, we recorded asset impairments totaling $329.7 million, primarily related to
receivables, inventory, fixed assets and goodwill, during the year ended December 31, 2009, which
is reflected in Income (loss) from discontinued operations. In addition, we determined that this
event could indicate an impairment of our international contract operations and aftermarket
services reporting units’ goodwill and therefore performed a goodwill impairment test for these
reporting units in the second quarter of 2009. Our international contract operations reporting unit
failed the goodwill impairment test, and we recorded an impairment of goodwill in our
international contract operations reporting unit of $150.8 million in the second quarter of 2009.
The $32.6 million of goodwill related to our Venezuela contract operations and aftermarket
services businesses was also written off in the second quarter of 2009 as part of our income (loss)
from discontinued operations. The decrease in value of our international contract operations
reporting unit was primarily caused by the loss of our operations in Venezuela.
For the year ended December 31, 2008: In 2008, there were severe disruptions in the credit and
capital markets and reductions in global economic activity that had significant adverse impacts on
stock markets and oil-and-gas-related commodity prices, both of which we believe contributed to a
significant decline in our company’s stock price and corresponding market capitalization. We
determined that the deepening recession and financial market crisis, along with the continuing
decline in the market value of our common stock, resulted in a $1,148.4 million impairment of all
of the goodwill in our North America contract operations reporting unit.
(5) For the year ended December 31, 2012: As discussed in Note 7 to the Financial Statements, in
March 2012, our Venezuelan joint ventures completed the sale of their assets to PDVSA Gas. We
received an initial payment of $37.6 million in March 2012, and received installment payments
totaling $14.1 million in the year ended December 31, 2012. The remaining principal amount due
to us of approximately $57 million is payable in quarterly cash installments through the first
quarter of 2016. We have not recognized amounts payable to us by PDVSA Gas as a receivable
and will therefore recognize quarterly payments received in the future as equity in (income) loss of
non-consolidated affiliates in our consolidated statements of operations in the periods such
payments are received. In connection with the sale of our Venezuelan joint ventures, assets, the
joint ventures and our joint venture partners have agreed to suspend their previously filed
arbitration proceeding against Venezuela pending payment in full by PDVSA Gas of the purchase
price for the assets.
(6) During the year ended December 31, 2009, we recorded a pre-tax gain of approximately
$20.8 million on the sale of our investment in the subsidiary that owned the barge mounted
processing plant and certain other related assets used on the Cawthorne Channel Project and a
foreign currency gain of $15.2 million. Our foreign currency gains and losses are primarily related
to the remeasurement of our international subsidiaries’ net assets exposed to changes in foreign
currency rates.
(7) For the year ended December 31, 2012: As discussed in Note 2 to the Financial Statements, in
August 2012, our Venezuelan subsidiary completed the sale of its previously nationalized assets to
PDVSA Gas, for a purchase price of approximately $441.7 million. We received an initial payment
of $176.7 million in cash at closing, of which we remitted $50.0 million to the insurance company
from which we had collected $50.0 million in January 2010 under the terms of an insurance policy
we maintained for the risk of expropriation. In December 2012 we received an installment
payment of $16.8 million. The remaining principal amount due to us of approximately $248 million
is payable in quarterly cash installments through the third quarter of 2016. We have not recognized
amounts payable to us by PDVSA Gas as a receivable and will therefore recognize quarterly
payments received in the future as income from discontinued operations in the periods such
payments are received. The proceeds from the sale of assets are not subject to Venezuelan national
taxes due to an exemption allowed under the Venezuelan Reserve Law applicable to expropriation
settlements. In addition, and in connection with the sale, we and the Venezuelan government
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agreed to waive rights to assert certain claims against each other. We therefore recorded a
reduction in previously unrecognized tax benefits, resulting in a $15.5 million benefit reflected in
Income (loss) from discontinued operations, net of tax, in our consolidated statements of
operations during the year ended December 31, 2012.
In June 2012, we committed to a plan to sell our contract operations and aftermarket services
businesses in Canada as part of our continued emphasis on simplification and focus on our core
businesses. We expect this sale to be completed within the next twelve months. Our Canadian
contract operations and aftermarket services businesses are reflected as discontinued operations in
our consolidated financial statements. These operations were previously included in our North
American contract operations and aftermarket services business segments. In conjunction with the
planned disposition, we recorded impairments of long-lived assets, including intangible and other
assets, and inventory, that totaled $80.2 million during the year ended December 31, 2012. The
impairment charges are reflected in Income (loss) from discontinued operations, net of tax.
For the year ended December 31, 2009: As discussed in Note 2 to the Financial Statements, in
June 2009, PDVSA assumed control over substantially all of our assets and operations in
Venezuela. As a result, we recorded asset impairments totaling $329.7 million, primarily related to
receivables, inventory, fixed assets and goodwill, during the year ended December 31, 2009, which
is reflected in Income (loss) from discontinued operations.
(8) EBITDA, as adjusted, a non-GAAP financial measure, is defined, reconciled to net income (loss)
and discussed further in Part II, Item 6 (‘‘Selected Financial Data—Non-GAAP Financial
Measures’’) of this report.
(9) Working capital is defined as current assets minus current liabilities.
NON-GAAP FINANCIAL MEASURES
We define gross margin as total revenue less cost of sales (excluding depreciation and amortization
expense). Gross margin is included as a supplemental disclosure because it is a primary measure used
by our management as it represents the results of revenue and cost of sales (excluding depreciation and
amortization expense), which are key components of our operations. We believe gross margin is
important because it focuses on the current operating performance of our operations and excludes the
impact of the prior historical costs of the assets acquired or constructed that are utilized in those
operations, the indirect costs associated with our SG&A activities, the impact of our financing methods
and income taxes. Depreciation and amortization expense may not accurately reflect the costs required
to maintain and replenish the operational usage of our assets and therefore may not portray the costs
from current operating activity. As an indicator of our operating performance, gross margin should not
be considered an alternative to, or more meaningful than, net income (loss) as determined in
accordance with accounting principles generally accepted in the U.S. (‘‘GAAP’’). Our gross margin may
not be comparable to a similarly titled measure of another company because other entities may not
calculate gross margin in the same manner.
Gross margin has certain material limitations associated with its use as compared to net income
(loss). These limitations are primarily due to the exclusion of interest expense, depreciation and
amortization expense, SG&A expense, impairments and restructuring charges. Each of these excluded
expenses is material to our consolidated results of operations. Because we intend to finance a portion
of our operations through borrowings, interest expense is a necessary element of our costs and our
ability to generate revenue. Additionally, because we use capital assets, depreciation expense is a
necessary element of our costs and our ability to generate revenue, and SG&A expenses are necessary
costs to support our operations and required corporate activities. To compensate for these limitations,
management uses this non-GAAP measure as a supplemental measure to other GAAP results to
provide a more complete understanding of our performance.
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The following table reconciles our net loss to gross margin (in thousands):
Years Ended December 31,
2012
2011
2010
2009
2008
Net loss . . . . . . . . . . . . . . . . . . . . . . . . . .
Selling, general and administrative . . . . .
Merger and integration expenses . . . . . .
Depreciation and amortization . . . . . . .
Long-lived asset impairment . . . . . . . . .
Restructuring charges . . . . . . . . . . . . . .
Goodwill impairment . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . .
Equity in (income) loss of
non-consolidated affiliates . . . . . . . . .
Other (income) expense, net . . . . . . . . .
Provision for (benefit from) income
$ (37,169) $(339,618) $(113,241) $(545,463) $ (935,076)
347,194
351,998
11,384
—
323,125
392,153
24,109
143,874
—
—
1,148,371
—
129,784
136,149
333,979
—
344,168
96,988
13,864
150,778
122,845
352,780
—
356,972
6,068
11,594
196,807
149,473
376,359
—
350,847
183,445
6,636
—
134,376
(51,483)
430
471
(5,620)
609
(11,413)
91,154
(51,909)
(23,974)
719
taxes
. . . . . . . . . . . . . . . . . . . . . . . .
(62,375)
(10,605)
(62,302)
50,390
35,214
(Income) loss from discontinued
operations, net of tax . . . . . . . . . . . .
(66,843)
10,105
(40,739)
293,711
(57,279)
Gross margin . . . . . . . . . . . . . . . . . . . . .
$834,223
$ 728,427
$ 797,088
$ 900,505
$1,003,571
We define EBITDA, as adjusted, as net income (loss) excluding income (loss) from discontinued
operations (net of tax), cumulative effect of accounting changes (net of tax), income taxes, interest
expense (including debt extinguishment costs and gain or loss on termination of interest rate swaps),
depreciation and amortization expense, impairment charges, merger and integration expenses,
restructuring charges, non-cash gains or losses from foreign currency exchange rate changes recorded
on intercompany obligations and other charges. We believe EBITDA, as adjusted, is an important
measure of operating performance because it allows management, investors and others to evaluate and
compare our core operating results from period to period by removing the impact of our capital
structure (interest expense from our outstanding debt), asset base (depreciation and amortization), our
subsidiaries’ capital structure (non-cash gains or losses from foreign currency exchange rate changes on
intercompany obligations), tax consequences, impairment charges, merger and integration expenses,
restructuring charges and other charges. Management uses EBITDA, as adjusted, as a supplemental
measure to review current period operating performance, comparability measures and performance
measures for period to period comparisons. Our EBITDA, as adjusted, may not be comparable to a
similarly titled measure of another company because other entities may not calculate EBITDA in the
same manner.
EBITDA, as adjusted, is not a measure of financial performance under GAAP, and should not be
considered in isolation or as an alternative to net income (loss), cash flows from operating activities
and other measures determined in accordance with GAAP. Items excluded from EBITDA, as adjusted,
are significant and necessary components to the operations of our business, and, therefore, EBITDA, as
adjusted, should only be used as a supplemental measure of our operating performance.
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The following table reconciles our net loss to EBITDA, as adjusted (in thousands):
Net loss . . . . . . . . . . . . . . . . . . . . . . . . . .
$ (37,169) $(339,618) $(113,241) $(545,463) $ (935,076)
Years Ended December 31,
2012
2011
2010
2009
2008
(Income) loss from discontinued
operations, net of tax . . . . . . . . . . . .
Merger and integration expenses . . . . . .
Depreciation and amortization . . . . . . .
Long-lived asset impairment . . . . . . . . .
Restructuring charges . . . . . . . . . . . . . .
Goodwill impairment . . . . . . . . . . . . . .
Investment in non-consolidated affiliates
impairment . . . . . . . . . . . . . . . . . . . .
Proceeds from sale of joint venture
assets . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . .
(Gain) loss on currency exchange rate
remeasurement of intercompany
balances . . . . . . . . . . . . . . . . . . . . . .
Gain on sale of our investment in the
subsidiary that owns the barge
mounted processing plant and other
related assets used on the Cawthorne
Channel Project
. . . . . . . . . . . . . . . .
Provision for (benefit from) income
(66,843)
—
350,847
183,445
6,636
—
10,105
—
356,972
6,068
11,594
196,807
(40,739)
—
392,153
143,874
—
—
293,711
—
344,168
96,988
13,864
150,778
(57,279)
11,384
323,125
24,109
—
1,148,371
224
471
609
96,593
—
(51,707)
134,376
—
149,473
—
136,149
—
122,845
—
129,784
7,406
14,174
(6,255)
(13,654)
9,754
—
—
(4,863)
(20,806)
—
taxes
. . . . . . . . . . . . . . . . . . . . . . . .
(62,375)
(10,605)
(62,302)
50,390
35,214
EBITDA, as adjusted . . . . . . . . . . . . . . . .
$464,840
$ 395,441
$ 445,385
$ 589,414
$ 689,386
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, the notes thereto, and the other financial
information appearing elsewhere in this report. The following discussion includes forward-looking statements
that involve certain risks and uncertainties. See Part I (‘‘Disclosure Regarding Forward-Looking
Statements’’) and Part I, Item 1A (‘‘Risk Factors’’) in this report.
Overview
We are a global market leader in the full-service natural gas compression business and a premier
provider of operations, maintenance, service and equipment for oil and natural gas production,
processing and transportation applications. Our global customer base consists of companies engaged in
all aspects of the oil and natural gas industry, including large integrated oil and natural gas companies,
national oil and natural gas companies, independent producers and natural gas processors, gatherers
and pipelines. We operate in three primary business lines: contract operations, fabrication and
aftermarket services. In our contract operations business line, we own a fleet of natural gas
compression equipment and crude oil and natural gas production and processing equipment that we
utilize to provide operations services to our customers. In our fabrication business line, we fabricate
equipment for sale to our customers and for use in our contract operations services. In addition, our
fabrication business line provides engineering, procurement and fabrication services primarily related to
the manufacturing of critical process equipment for refinery and petrochemical facilities, the fabrication
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of tank farms and the fabrication of evaporators and brine heaters for desalination plants. We offer
customers, on either a contract operations basis or a sale basis, the engineering, design, project
management, procurement and construction services necessary to incorporate our products into
production, processing and compression facilities, which we refer to as Integrated Projects. In our
aftermarket services business line, we sell parts and components and provide operations, maintenance,
overhaul and reconfiguration services to customers who own compression, production, processing,
treating and other equipment.
Industry Conditions and Trends
Our business environment and corresponding operating results are affected by the level of energy
industry spending for the exploration, development and production of oil and natural gas reserves.
Spending by oil and natural gas exploration and production companies is dependent upon these
companies’ forecasts regarding the expected future supply, demand and pricing of, oil and natural gas
products as well as their estimates of risk-adjusted costs to find, develop and produce reserves.
Although we believe our contract operations business is typically less impacted by commodity prices
than certain other energy service products and services, changes in oil and natural gas exploration and
production spending normally results in changes in demand for our products and services.
Natural Gas Consumption and Production. Natural gas consumption in the U.S. for the twelve
months ended November 30, 2012 increased by approximately 4% over the twelve months ended
November 30, 2011, is expected to increase by 1.2% in 2013, and by an average of 0.5% per year
thereafter until 2035 according to the EIA. The EIA projects that natural gas consumption worldwide
will increase by 1.6% per year until 2035.
Natural gas marketed production in the U.S. for the twelve months ended November 30, 2012
increased by approximately 6% over the twelve months ended November 30, 2011. The EIA forecasts
that total U.S. marketed production will grow by 1% in 2013. In 2011, the U.S. accounted for an
estimated annual production of approximately 24 trillion cubic feet of natural gas, or 20% of the
worldwide total of approximately 123 trillion cubic feet. The EIA estimates that the U.S.’s natural gas
production level will be approximately 26 trillion cubic feet in 2035, or 16% of the projected worldwide
total of approximately 169 trillion cubic feet.
Our Performance Trends and Outlook
Our revenue, earnings and financial position are affected by, among other things, market
conditions that impact demand and pricing for natural gas compression and oil and natural gas
production and processing, and our customers’ decisions among using our products and services, using
our competitors’ products and services or owning and operating the equipment themselves.
During 2011 and 2012, we saw robust drilling activity in North America in shale plays and areas
focused on the production of oil and natural gas liquids. This activity led to higher demand and
bookings for our fabricated compression, fabricated production and processing equipment and contract
operations businesses in these markets. This new development activity has increased the overall amount
of compression horsepower in the industry and in our business in North America; however, these
increases continue to be partially offset by horsepower declines in more mature and predominantly dry
gas markets, where we provide a significant amount of contract operations services. In early 2012,
natural gas prices in North America fell to their lowest levels in more than a decade. Since then,
natural gas prices in North America have improved, but still remain at low levels which could limit
natural gas production growth in North America, particularly in dry gas areas. We believe that the low
natural gas price environment, as well as the recent capital investment in new equipment by our
competitors and other third parties, could decrease demand for our natural gas compression and oil
and natural gas production and processing equipment and services in North America. However, given
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current backlog levels for our fabricated products and the level of activity we are generating in North
America, we believe our fabrication revenues in 2013 will be similar to those achieved in 2012.
In international markets, we believe demand for our contract operations and fabricated projects
will continue and we expect to have opportunities to grow our international business through our
contract operations, aftermarket services and fabrication business segments over the long term. In 2011,
we saw decreases in our international backlog in our fabrication business segment due to the longer
lead times for international energy project development. However, our international backlog has
improved since December 31, 2011, increasing by approximately 48% through December 31, 2012.
Our level of capital spending depends on our forecast for the demand for our products and
services and the equipment we require to provide services to our customers. We anticipate investing
more capital in our contract operations fleet in 2013 than we did in 2012 and recent periods prior to
2012.
Based on current market conditions, we expect that net cash provided by operating activities and
availability under our credit facilities will be sufficient to finance our operating expenditures, capital
expenditures and scheduled interest and debt repayments through December 31, 2013; however, to the
extent it is not, we may seek additional debt or equity financing. We may from time to time seek to
retire or purchase our outstanding debt through cash purchases and/or exchanges for equity or other
debt securities, in open market purchases, privately negotiated transactions or otherwise. Such
repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity
requirements, contractual restrictions and other factors.
We intend to continue to contribute over time additional U.S. contract operations customer
contracts and equipment to the Partnership in exchange for cash, the Partnership’s assumption of our
debt and/or our receipt of additional interests in the Partnership. Such transactions depend on, among
other things, market and economic conditions, our ability to agree with the Partnership regarding the
terms of any purchase and the availability to the Partnership of debt and equity capital on reasonable
terms.
Certain Key Challenges and Uncertainties
Market conditions in the natural gas industry, competition in the natural gas compression industry
and the risks inherent in international markets continue to represent key challenges and uncertainties.
In addition to these challenges, we believe the following represent some of the key challenges and
uncertainties we will face in the near future:
North America Market and Natural Gas Pricing. During 2011 and 2012, we saw robust drilling
activity and an increase in order activity and bookings in our fabrication and contract operations
business segments in the North America market in certain shale plays and areas focused on the
production of oil and natural gas liquids. The new development activity has increased the overall
amount of compression horsepower in the industry and our business in North America; however, these
increases were significantly offset by horsepower declines in more mature and predominantly
conventional and dry gas markets. The supply of U.S. natural gas continued to increase in 2012 and
outstripped demand, which contributed to a low natural gas price environment. This trend of lower
natural gas prices could further decrease natural gas production, particularly in more mature and
predominantly dry gas areas, where we provide a significant amount of contract operations services, and
as a result the demand for our natural gas compression services and oil and natural gas production and
processing equipment could be adversely affected. The recent investment of capital in new equipment
by our competitors and other third parties could also create uncertainty in our business outlook. Many
of our North America contract operations agreements with customers have short initial terms and are
typically cancelable on short notice after the initial term, and we cannot be certain that these contracts
will be extended or renewed after the end of the initial contractual term. Any such nonrenewal, or
renewal at a reduced rate, could adversely impact our results of operations.
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Execution on Larger Contract Operations and Fabrication Projects. Some of our projects have a
relatively larger size and scope than the majority of our projects, which can translate into more
technically challenging conditions or performance specifications for our products and services. Contracts
with our customers generally specify delivery dates, performance criteria and penalties for our failure to
perform. Any failure to execute such larger projects in a timely and cost effective manner could have a
material adverse effect on our business, financial condition, results of operations and cash flows.
Personnel, Hiring, Training and Retention. Both in North America and internationally, we believe
our ability to grow will be challenged by our ability to hire, train and retain qualified personnel.
Although we have been able to satisfy our personnel needs thus far, retaining employees in our
industry continues to be a challenge. Our ability to continue our growth will depend in part on our
success in hiring, training and retaining these employees.
Activity in the Global Energy Markets. Our results of operations depend upon the level of activity
in the global energy markets, including natural gas development, production, processing and
transportation. Oil and natural gas prices and the level of drilling and exploration activity can be
volatile. For example, oil and natural gas exploration and development activity and the number of well
completions typically decline when there is a significant reduction in oil or natural gas prices or
significant instability in energy markets. In international projects, some business activity is related to
infrastructure development or regulatory requirements such as regulations to prevent the flaring of
natural gas. The timing and financial impact of these projects is difficult to predict as they typically
have longer lead times and larger scope, which can lead to variations in our results of operations
internationally on a year over year basis.
Summary of Results
As discussed in Note 2 to the Financial Statements, the results from continuing operations for all
periods presented exclude the results of our Venezuelan contract operations and aftermarket services
businesses and Canadian contract operations and aftermarket services businesses. Those results are
reflected in discontinued operations for all periods presented.
Net loss attributable to Exterran stockholders and EBITDA, as adjusted. We recorded a consolidated
net loss attributable to Exterran stockholders of $39.5 million, $340.6 million and $101.8 million for the
years ended December 31, 2012, 2011 and 2010, respectively. We recorded EBITDA, as adjusted, of
$464.8 million, $395.4 million and $445.4 million for the years ended December 31, 2012, 2011 and
2010, respectively. Net loss attributable to Exterran stockholders for the year ended December 31, 2012
was negatively impacted by long-lived asset impairments of $183.4 million and other impairments of
long-lived assets, including intangible and other assets, and inventory, that totaled $80.2 million on
Canadian discontinued operations. These impairments were partially offset by $143.5 million of net
proceeds from the sale of previously nationalized Venezuela assets to PDVSA Gas and equity in
income from non-consolidated affiliates of $51.5 million received from the sale of our Venezuelan joint
ventures’ assets during the year ended December 31, 2012. Net loss attributable to Exterran
stockholders for the year ended December 31, 2011 was negatively impacted by goodwill impairments
of $196.8 million. Net loss attributable to Exterran stockholders for the year ended December 31, 2010
was negatively impacted by long-lived asset impairments of $143.9 million. Net loss attributable to
Exterran stockholders and EBITDA, as adjusted, for the year ended December 31, 2012 benefitted
from higher gross margins from operations compared to the years ended December 31, 2011 and 2010.
For a reconciliation of EBITDA, as adjusted, to net loss, its most directly comparable financial
measure, calculated and presented in accordance with accounting principles generally accepted in the
U.S. (‘‘GAAP’’), please read Part II, Item 6 (‘‘Selected Financial Data—Non-GAAP Financial
Measures’’) of this report.
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Results by Business Segment. The following table summarizes revenue, gross margin and gross
margin percentages for each of our business segments (dollars in thousands):
Years Ended December 31,
2012
2011
2010
Revenue:
North America Contracts Operations . . . . . . . . . . . . . . . . . . .
International Contract Operations . . . . . . . . . . . . . . . . . . . . .
Aftermarket Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fabrication . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 605,367
463,957
385,861
1,348,417
$ 588,034
445,059
371,327
1,225,459
$ 592,055
465,144
293,757
1,066,227
$2,803,602
$2,629,879
$2,417,183
Gross Margin(1):
North America Contracts Operations . . . . . . . . . . . . . . . . . . .
International Contract Operations . . . . . . . . . . . . . . . . . . . . .
Aftermarket Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fabrication . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 316,123
279,349
82,271
156,480
$ 284,984
260,654
59,567
123,222
$ 300,431
289,787
45,365
161,505
$ 834,223
$ 728,427
$ 797,088
Gross Margin percentage(2):
North America Contracts Operations . . . . . . . . . . . . . . . . . . .
International Contract Operations . . . . . . . . . . . . . . . . . . . . .
Aftermarket Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fabrication . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
52%
60%
21%
12%
48%
59%
16%
10%
51%
62%
15%
15%
(1) Defined as revenue less cost of sales, excluding depreciation and amortization expense. Gross
margin, a non-GAAP financial measure, is reconciled, in total, to net income (loss), its most
directly comparable financial measure calculated and presented in accordance with GAAP in
Selected Financial Data—Non-GAAP Financial Measures.
(2) Defined as gross margin divided by revenue.
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Operating Highlights
The following tables summarize our total available horsepower, total operating horsepower,
average operating horsepower, horsepower utilization percentages and fabrication backlog (horsepower
in thousands and dollars in millions):
Years Ended
December 31,
2012
2011
2010
Total Available Horsepower (at period end):
North America . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
International
3,376
1,265
3,545
1,260
3,607
1,200
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4,641
4,805
4,807
Total Operating Horsepower (at period end):
North America . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
International
2,900
1,007
2,830
960
2,779
981
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,907
3,790
3,760
Average Operating Horsepower:
North America . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
International
2,839
991
2,784
978
2,778
1,024
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,830
3,762
3,802
Horsepower Utilization (at period end):
North America . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
International
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
86% 80% 77%
80% 76% 82%
84% 79% 78%
Years Ended December 31,
2012
2011
2010
Compressor and Accessory Fabrication Backlog . . . . . . . . . . . . . . . . . . . .
Production and Processing Equipment Fabrication Backlog . . . . . . . . . . . .
Installation Backlog(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 256.3
563.8
245.6
$249.7
416.0
69.6
$220.2
483.3
26.1
Fabrication Backlog(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,065.7
$735.3
$729.6
(1) In the second quarter of 2012, we began including installation backlog in our total fabrication
backlog, and have updated all prior periods to also include installation backlog.
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2 C Cs: 56896
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011
Summary of Business Segment Results
North America Contract Operations
(dollars in thousands)
Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of sales (excluding depreciation and amortization expense) . . . . .
$605,367
289,244
$588,034
303,050
Gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross margin percentage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$316,123
$284,984
52%
48%
Years Ended
December 31,
2012
2011
Increase
(Decrease)
3%
(5)%
11%
4%
The increase in revenue in the year ended December 31, 2012 compared to the year ended
December 31, 2011 was primarily attributable to a 2% increase in average operating horsepower, an
increase in rates, a $4.0 million increase in revenue from a gas processing plant that began operations
during the fourth quarter of 2011 and a $3.9 million increase in freight revenue, partially offset by a
$7.9 million decrease in revenue from our contract water treatment business. The increases in gross
margin (defined as revenue less cost of sales, excluding depreciation and amortization expense) and
gross margin percentage for the year ended December 31, 2012 compared to the year ended
December 31, 2011 were primarily caused by the revenue increase explained above, better management
of field operating expenses from the implementation of profitability improvement initiatives, a
$7.1 million benefit from ad valorem taxes due to a change in tax law and a $4.4 million decrease in
costs to deploy idle fleet assets on customer contracts, partially offset by an increase in lube oil prices.
Gross margin, a non-GAAP financial measure, is reconciled, in total, to net income (loss), its most
directly comparable financial measure calculated and presented in accordance with GAAP in Selected
Financial Data—Non-GAAP Financial Measures.
International Contract Operations
(dollars in thousands)
Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of sales (excluding depreciation and amortization expense) . . . . .
Gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross margin percentage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Years Ended
December 31,
2012
2011
Increase
(Decrease)
$463,957
184,608
$279,349
60%
$445,059
184,405
4%
0%
$260,654
7%
59% 1%
The increases in revenue and gross margin in the year ended December 31, 2012 compared to the
year ended December 31, 2011 were primarily due to a $15.9 million increase in revenue in Mexico
primarily due to new contracts commencing in 2012, a $10.9 million increase in revenue in Argentina as
a result of inflation rate adjustments, a $5.1 million increase in revenue due to the recognition of
revenue with little incremental cost from the early termination of a project in Nigeria recorded in 2012
and a $9.1 million increase in revenue from a new contract in the Eastern Hemisphere. These increases
were partially offset by a $20.5 million decrease in revenue in Brazil primarily as a result of lower 2012
revenue from four contracts that were terminated in 2011 and settled in 2012 and contract renewals at
lower rates in 2012. Gross margin percentage in the year ended December 31, 2012 increased due to
the recognition of $17.1 million of revenue with little incremental cost from the settlement in 2012 of
the early termination of projects in Brazil and Nigeria and inflation rate adjustments in Argentina.
These increases were partially offset by the impact of contract renewals at lower rates in 2012 in Brazil.
48
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Aftermarket Services
(dollars in thousands)
Years Ended
December 31,
2012
2011
Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of sales (excluding depreciation and amortization expense) . . . . .
$385,861
303,590
$371,327
311,760
Gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross margin percentage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 82,271
$ 59,567
21%
16%
Increase
(Decrease)
4%
(3)%
38%
5%
The increase in revenue in the year ended December 31, 2012 compared to the year ended
December 31, 2011 was primarily due to an increase in revenue in North America of $31.7 million.
This was partially offset by a decrease in revenue in the Eastern Hemisphere and Latin America of
$9.3 million and $7.9 million, respectively. Gross margin and gross margin percentage were favorably
impacted by improved market conditions and the implementation of profitability improvement
initiatives that began in the second half of 2011.
Fabrication
(dollars in thousands)
Years Ended
December 31,
2012
2011
Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of sales (excluding depreciation and amortization expense) . .
$1,348,417
1,191,937
$1,225,459
1,102,237
Gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross margin percentage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 156,480
$ 123,222
12%
10%
Increase
(Decrease)
10%
8%
27%
2%
The increase in revenue for the year ended December 31, 2012 compared to the year ended
December 31, 2011 was primarily due to $315.8 million of higher revenue in North America caused by
improved market conditions, partially offset by a $207.4 million reduction of revenue in the Eastern
Hemisphere. The increases in gross margin and gross margin percentage were primarily caused by
customer price increases in North America as a result of improved market conditions and a reduction
in operating expenses from the implementation of profitability improvement initiatives and lower
margins in 2011 on two projects in the Eastern Hemisphere. This was partially offset by the
continuation of weaker market conditions and increased competition that impacted the results of our
Belleli Energy subsidiary, which provides engineering, procurement and fabrication services primarily
related to the manufacturing of critical process equipment for refinery and petrochemical facilities, the
fabrication of tank farms and the fabrication of evaporators and brine heaters for desalination plants,
and a $15.0 million recovery on a loss contract recorded in the first quarter of 2011. The decreases in
gross margin and gross margin percentage at our Belleli Energy subsidiary were primarily the result of
lower activity levels and an increase in under-absorption caused by such reduced activity.
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2 C Cs: 50965
Costs and Expenses
(dollars in thousands)
Years Ended
December 31,
2012
2011
Selling, general and administrative . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-lived asset impairment
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restructuring charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity in (income) loss of non-consolidated affiliates . . . . . . . . . . . . .
Other (income) expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$376,359
350,847
183,445
6,636
134,376
(51,483)
430
$
$352,780
356,972
6,068
11,594
— 196,807
149,473
471
$ (5,620)
Increase
(Decrease)
7%
(2)%
2,923%
(43)%
(100)%
(10)%
(11,031)%
(108)%
The increase in SG&A expense during the year ended December 31, 2012 was primarily due to a
$15.3 million increase in state and local taxes primarily related to sales tax audits in North America and
a $10.5 million increase in compensation and benefit costs. These increases were partially offset by a
decrease in other SG&A expenses primarily driven by cost reduction efforts. SG&A as a percentage of
revenue was 13% for the years ended December 31, 2012 and 2011.
Depreciation and amortization decreased primarily due to reduced depreciation and amortization
on contract operations projects in Brazil as a result of contracts that terminated in 2011 and the impact
of the $128.5 million impairment recorded in the second quarter of 2012, which decreased depreciation
and amortization expense by $5.9 million in the year ended December 31, 2012. These reductions were
partially offset by increased depreciation and amortization on contract operations projects in Mexico
that commenced in 2012.
During 2012, we evaluated the future deployment of our idle fleet and determined to retire and
either sell or re-utilize key components of approximately 930 idle compressor units, representing
approximately 318,000 horsepower, that we previously used to provide services in our North America
contract operations segment. As a result, we performed an impairment review and recorded a
$97.1 million asset impairment to reduce the book value of each unit to its estimated fair value. The
fair value of each unit was estimated based on the expected net sale proceeds compared to other fleet
units we recently sold, as well as our review of other units recently offered for sale by third parties, or
the estimated component value of the equipment we plan to use. The average age of the impaired idle
units was 24 years.
In connection with our review of our fleet in 2012, we evaluated for impairment idle units that had
been culled from our fleet in prior years and were available for sale. Based upon that review, we
reduced the expected proceeds from disposition for most of the remaining units and increased the
weighted average disposal period for the units from the assumptions used in prior periods. This
resulted in an additional impairment of $34.8 million to reduce the book value of each unit to its
estimated fair value.
In the fourth quarter of 2012, we committed to a plan to abandon our contract water treatment
business as part of our continued emphasis on simplification and focus on our core businesses. In
conjunction with the planned abandonment, we recorded an impairment of long-lived assets of
$46.8 million, including property, plant and equipment impairment of $17.7 million and intangible
assets impairment of $29.1 million. The fair value of our contract water treatment assets was based on
projected cash flows of active assets currently under contract, which expire in 2013, and expected net
sales proceeds of idle assets that have been culled from our fleet. We expect the abandonment of our
contract water treatment business to be completed by December 31, 2013.
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2 C Cs: 61888
During 2012, we evaluated other long-lived assets for impairment and recorded long-lived asset
impairments of $4.7 million on these assets.
During 2011, we reviewed the idle compression assets used in our contract operations segments for
units that were not of the type, configuration, make or model that are cost effective to maintain and
operate. Our estimate of the impaired long-lived assets’ fair value was based on the expected net sale
proceeds compared to other fleet units we had recently sold, as well as our review of other units
recently offered for sale by third parties, or the estimated component value of the equipment we
planned to use. The net book value of these assets exceeded the fair value by $5.7 million for the year
ended December 31, 2011 and was recorded as a long-lived asset impairment. In addition, in the fourth
quarter of 2011, we recorded a $0.4 million impairment of other long-lived assets.
In November 2011, we announced a workforce cost reduction program across all of our business
segments as a first step in a broader overall profit improvement initiative. These actions were the result
of a review of our cost structure aimed at identifying ways to reduce our on-going operating costs and
to adjust the size of our workforce to be consistent with current and expected activity levels. A
significant portion of the workforce cost reduction program was completed in 2011, with the remainder
completed in 2012. During the years ended December 31, 2012 and 2011, we incurred $6.6 and
$11.6 million, respectively, of restructuring charges primarily related to termination benefits and
consulting services. See Note 14 to the Financial Statements for further discussion of these charges.
As a result of the level of decline in our stock price and corresponding market capitalization in the
third quarter of 2011, we performed a goodwill impairment test of our aftermarket services and
fabrication reporting units’ goodwill as of September 30, 2011. This decline in our market capitalization
led us to increase the estimate of the market’s implied weighted average cost of capital and reduce the
present value of the forecasted cash flows. The test indicated that our aftermarket services and
fabrication reporting units’ goodwill was impaired and therefore we recorded a full impairment of our
remaining goodwill during 2011 of $196.8 million. See Note 8 to the Financial Statements for further
discussion of the goodwill impairments.
The decrease in interest expense for the year ended December 31, 2012 compared to the year
ended December 31, 2011 was primarily due to a decrease of $9.6 million in the amortization of
payments to terminate interest rate swaps and a decrease as a result of the expiration of certain
interest rate swaps in the third quarter of 2012. This was partially offset by refinancing a portion of our
outstanding debt at a higher interest rate. The payments to terminate interest rate swap agreements are
being amortized into interest expense over the original terms of the swaps.
The change in equity in (income) loss of non-consolidated affiliates during the year ended
December 31, 2012 relates to net payments of $51.7 million received during the year ended
December 31, 2012 from the sale of our Venezuelan joint ventures’ assets. The remaining principal
amount due to us of approximately $57 million is payable in quarterly net cash installments through the
first quarter of 2016. Payments we receive from the sale will be recognized as equity in (income) loss of
non-consolidated affiliates in our consolidated statements of operations in the periods such payments
are received.
The change in other (income) expense, net, in the year ended December 31, 2012 compared to the
year ended December 31, 2011 was primarily due to a $13.4 million decrease related to non-income tax
based tax receivables in Brazil that we determined were realizable. The change in other (income)
expense, net, was also due to a foreign currency loss of $8.2 million and $16.5 million for the years
ended December 31, 2012 and 2011, respectively. The reduction in our foreign currency loss for 2012
was impacted by a $7.7 million decrease in translation loss related to remeasurement of our Brazil
subsidiary’s U.S. dollar denominated intercompany debt. Our foreign currency gains and losses are
primarily related to the remeasurement of our international subsidiaries’ net assets exposed to changes
in foreign currency rates.
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2 C Cs: 37637
Income Taxes
(dollars in thousands)
Years Ended
December 31,
2012
2011
Increase
(Decrease)
Benefit from income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Effective tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(62,375)
37.5%
$(10,605)
488%
3.1% 34.4%
For 2012 the increase in our effective tax rate was primarily due to $51.5 million equity in income
of non-consolidated affiliates, which is not subject to income tax, and the $183.4 million long-lived asset
impairment charge, which is predominantly tax effected at the U.S. statutory rate. For 2011, our
effective tax rate was decreased due to the goodwill impairment charge of $196.8 million, of which only
$42.6 million was deductible for income tax purposes, and $48.6 million of valuation allowance
recorded against the deferred tax asset for Brazil net operating loss carryforwards.
Discontinued Operations
(dollars in thousands)
Years Ended
December 31,
2012
2011
Increase
(Decrease)
Income (loss) from discontinued operations, net of tax . . . . . . . . . . . . .
$66,843
$(10,105)
761%
Income (loss) from discontinued operations, net of tax, for the years ended December 31, 2012
and 2011 related to our operations in Venezuela that were expropriated in June 2009, including the
costs associated with our arbitration proceeding, and results from and impairment of our Canadian
contract operations and aftermarket services businesses. As discussed in Note 2 to the Financial
Statements, in June 2009, PDVSA assumed control over substantially all of our assets and operations in
Venezuela.
In August 2012, our Venezuelan subsidiary completed the sale of its previously nationalized assets
to PDVSA Gas for a purchase price of approximately $441.7 million. We received an initial payment of
$176.7 million in cash at closing, of which we remitted $50.0 million to the insurance company from
which we collected $50.0 million in January 2010 under the terms of an insurance policy we maintained
for the risk of expropriation. In December 2012 we received an installment payment of $16.8 million.
The remaining principal amount due to us of approximately $248 million is payable in quarterly cash
installments through the third quarter of 2016. We have not recognized amounts payable to us by
PDVSA Gas as a receivable and will therefore recognize quarterly payments received in the future as
income from discontinued operations in the periods such payments are received. The proceeds from
the sale of assets are not subject to Venezuelan national taxes due to an exemption allowed under the
Venezuelan Reserve Law applicable to expropriation settlements. In addition, and in connection with
the sale, we and the Venezuelan government agreed to waive rights to assert certain claims against each
other. We therefore recorded a reduction in previously unrecognized tax benefits, resulting in a
$15.5 million benefit reflected in Income (loss) from discontinued operations, net of tax, in our
consolidated statements of operations during the year ended December 31, 2012.
In June 2012, we committed to a plan to sell our contract operations and aftermarket services
businesses in Canada. The planned disposition meets the criteria established for recognition as
discontinued operations and therefore our Canadian contract operations and aftermarket services
businesses are reflected as discontinued operations in our Financial Statements. In conjunction with the
planned disposition, we recorded impairments of long-lived assets, including intangible and other assets,
and inventory, that totaled $80.2 million during the year ended December 31, 2012.
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Noncontrolling Interest
As of December 31, 2012, noncontrolling interest is comprised of the portion of the Partnership’s
earnings that is applicable to the limited partner interest in the Partnership owned by the public. As of
December 31, 2012, public unitholders held a 69% ownership interest in the Partnership.
Year Ended December 31, 2011 Compared to Year Ended December 31, 2010
Summary of Business Segment Results
North America Contract Operations
(dollars in thousands)
Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of sales (excluding depreciation and amortization expense) . . .
$588,034
303,050
$592,055
291,624
Gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross margin percentage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$284,984
$300,431
48%
51%
Years Ended
December 31,
2011
2010
Increase
(Decrease)
(1)%
4%
(5)%
(3)%
The decrease in revenue was primarily attributable to a $5.9 million reduction of revenue in our
contract water treatment business in the year ended December 31, 2011 compared to the year ended
December 31, 2010. The decrease in revenue was partially offset by an increase in revenue from two
gas processing plants that began operations during 2011 and a 2% increase in average operating
horsepower. The decreases in gross margin (defined as revenue less cost of sales, excluding
depreciation and amortization expense) and gross margin percentage in the year ended December 31,
2011 compared to the year ended December 31, 2010 was primarily due to an increase in lube oil
expense, costs to deploy idle fleet assets on customer contracts and fuel expense.
International Contract Operations
(dollars in thousands)
Years Ended
December 31,
2011
2010
Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of sales (excluding depreciation and amortization expense) . . .
$445,059
184,405
$465,144
175,357
Gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross margin percentage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$260,654
$289,787
59%
62%
Increase
(Decrease)
(4)%
5%
(10)%
(3)%
The decreases in revenue, gross margin and gross margin percentage in the year ended
December 31, 2011 compared to the year ended December 31, 2010 was primarily due to the
recognition of $19.2 million of revenue with little incremental cost from the early termination of a
project in Brazil recorded in the year ended December 31, 2010. Gross margin and gross margin
percentage in the year ended December 31, 2011 were also impacted by higher operating costs in
Argentina and Brazil caused primarily by inflation.
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Aftermarket Services
(dollars in thousands)
Years Ended
December 31,
2011
2010
Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of sales (excluding depreciation and amortization expense) . . . .
$371,327
311,760
$293,757
248,392
Gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross margin percentage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 59,567
$ 45,365
16%
15%
Increase
(Decrease)
26%
26%
31%
1%
The increase in revenue in the year ended December 31, 2011 compared to the year ended
December 31, 2010 was primarily due to increases in Eastern Hemisphere and North America revenue
of $36.9 million and $35.9 million, respectively. Revenue and gross margin in the Eastern Hemisphere
for the year ended December 31, 2011 included $3.9 million from the renegotiation of the rates,
retroactive to April 2010, on an operations and maintenance contract in Gabon.
Fabrication
(dollars in thousands)
Years Ended December 31,
2011
2010
Increase
(Decrease)
Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of sales (excluding depreciation and amortization expense)
$1,225,459
1,102,237
$1,066,227
904,722
Gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross margin percentage . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 123,222
$ 161,505
10%
15%
15%
22%
(24)%
(5)%
The increase in revenue for the year ended December 31, 2011 compared to the year ended
December 31, 2010 was primarily due to $331.8 million of higher revenue in North America caused by
improved market conditions. This increase was partially offset by a $189.6 million reduction of revenue
in the Eastern Hemisphere. The decreases in gross margin and gross margin percentage was primarily
due to reduced margins from our Belleli subsidiary which provides engineering, procurement and
fabrication services primarily related to the manufacturing of critical process equipment for refinery and
petrochemical facilities, the fabrication of tank farms and the fabrication of evaporators and brine
heaters for desalination plants, lower margins in 2011 on two projects in the Eastern Hemisphere and
increased revenue from compression projects in North America, which typically have lower margins
than the margins on our international fabrication projects.
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Costs and Expenses
(dollars in thousands)
Years Ended
December 31,
2011
2010
Increase
(Decrease)
Selling, general and administrative . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-lived asset impairment
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restructuring charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity in (income) loss of non-consolidated affiliates . . . . . . . . . . . . .
Other (income) expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$352,780
356,972
6,068
11,594
196,807
149,473
471
$351,998
392,153
143,874
—
—
136,149
609
$ (5,620) $ (11,413)
0%
(9)%
(96)%
n/a
n/a
10%
(23)%
(51)%
The increase in SG&A expense during the year ended December 31, 2011 was primarily due to a
$13.4 million increase in compensation and benefit costs, partially offset by a $13.0 million reduction in
state and local taxes (primarily in Brazil and North America). SG&A expense as a percentage of
revenue was 13% and 15% for the years ended December 31, 2011 and 2010, respectively.
Depreciation and amortization decreased by $35.2 million, primarily due to the impact of the
$133.0 million long-lived asset impairment recorded in the fourth quarter of 2010, which decreased
depreciation and amortization expense by approximately $18.4 million in the year ended December 31,
2011, and $15.7 million of reduced depreciation and amortization on international contract operations
projects including a project in Brazil that was terminated early in the second quarter of 2010.
During 2011, we reviewed the idle compression assets used in our contract operations segments for
units that were not of the type, configuration, make or model that are cost effective to maintain and
operate. Our estimate of the fair value of the impaired long-lived assets was based on the expected net
sale proceeds compared to other fleet units we recently sold, as well as our review of other units
recently offered for sale by third parties, or the estimated component value of the equipment we plan
to use. The net book value of these assets exceeded the fair value by $5.7 million for the year ended
December 31, 2011 and was recorded as a long-lived asset impairment. In addition, in the fourth
quarter of 2011, we recorded a $0.4 million impairment of other long-lived assets.
During 2010, we completed an evaluation of our longer-term strategies and determined to retire
and sell approximately 1,800 idle compressor units, or approximately 600,000 horsepower, that we
previously used to provide services in our North America and international contract operations
businesses. As a result, we performed an impairment review and recorded a $133.0 million asset
impairment to reduce the book value of each unit to its estimated fair value. The fair value of each
unit was estimated based on the expected net sale proceeds compared to other fleet units we recently
sold, as well as our review of other units that were recently for sale by third parties. Selling these
compressor units is expected to take several years and, if we are not able to sell these units for the
amount we estimated in our impairment analysis, we could be required to record additional
impairments in future periods.
As a result of a decline in market conditions in North America during 2010, we reviewed the idle
compression assets used in our contract operations segments for units that were not of the type,
configuration, make or model that are cost effective to maintain and operate. We performed a cash
flow analysis of the expected proceeds from the salvage value of 323 units, representing approximately
61,400 horsepower for the year ended December 31, 2010. The net book value of these assets exceeded
the fair value by $7.6 million for the year ended December 31, 2010 and this difference was recorded
as a long-lived asset impairment. In addition, in the fourth quarter of 2010, 105 fleet units that we
previously utilized in our international contract operations segment were damaged in a flood, resulting
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in a long-lived asset impairment of $3.3 million. See Note 13 to the Financial Statements for further
discussion of the long-lived asset impairments.
In November 2011, we announced a workforce cost reduction program across all of our business
segments as a first step in a broader overall profit improvement initiative. These actions were the result
of a review of our cost structure aimed at identifying ways to reduce our on-going operating costs and
to adjust the size of our workforce to be consistent with current and expected activity levels. A
significant portion of the workforce cost reduction program was completed in 2011. During the year
ended December 31, 2011, we incurred $11.6 million of restructuring charges that were related to
termination benefits and consulting services. See Note 14 to the Financial Statements for further
discussion of these charges.
As a result of the level of decline in our stock price and corresponding market capitalization in the
third quarter of 2011, we performed a goodwill impairment test of our aftermarket services and
fabrication reporting units’ goodwill as of September 30, 2011. This decline in our market capitalization
led us to increase the estimate of the market’s implied weighted average cost of capital and reduce the
present value of the forecasted cash flows. The test indicated that our aftermarket services and
fabrication reporting units’ goodwill was impaired and therefore we recorded a full impairment of our
remaining goodwill during 2011 of $196.8 million. See Note 8 to the Financial Statements for further
discussion of the goodwill impairments.
The increase in interest expense for the year ended December 31, 2011 compared to the year
ended December 31, 2010 was primarily due to the refinancing of portions of our outstanding debt at
higher interest rates, including our 7.25% senior notes due December 2018, which we issued in
November 2010. In addition, we expensed $1.6 million of unamortized deferred financing costs due to
the refinancing of our senior secured credit facility and $1.4 million of unamortized deferred financing
costs due to the termination of our asset-backed securitization facility in the year ended December 31,
2011. The increase in interest expense was partially offset by a lower average debt balance during the
year ended December 31, 2011 compared to the year ended December 31, 2010.
The change in other (income) expense, net, was primarily due to a foreign currency loss of
$16.5 million for the year ended December 31, 2011 compared to a gain of $4.9 million for the year
ended December 31, 2010. Our foreign currency gains and losses are primarily related to the
remeasurement of our international subsidiaries’ net assets exposed to changes in foreign currency
rates. For the year ended December 31, 2011, foreign currency loss included $12.6 million in translation
losses compared to $4.6 million in translation gains in the year ended December 31, 2010, related to
the re-measurement of our Brazil subsidiary’s U.S. dollar denominated inter-company debt. Other
(income) expense, net, was $14.5 million higher for the year ended December 31, 2011 compared to the
prior year from non-income tax based tax receivables in Brazil that we determined were realizable. The
change in other (income) expense, net, was also impacted by $0.7 million and $5.1 million of
importation penalties in Brazil for the years ended December 31, 2011 and 2010, respectively.
Income Taxes
(dollars in thousands)
Years Ended
December 31,
2011
2010
Increase
(Decrease)
Benefit from income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Effective tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(10,605)
3.1%
$(62,302)
(83)%
28.8% (25.7)%
The decrease in our effective tax rate for the year ended December 31, 2011 compared to the year
ended December 31, 2010 was primarily due to a $48.6 million valuation allowance recorded against
the deferred tax asset for Brazil net operating loss carryforwards. Although the net operating losses
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have an unlimited carryforward period, cumulative losses in recent years and losses expected in the
near term result in it no longer being more likely than not that we will realize the deferred tax asset in
the foreseeable future. Due to annual limitations on the utilization of net operating loss carryforwards,
we would need to generate more than $400 million of taxable income in Brazil to fully realize the
deferred tax asset.
A $196.8 million goodwill impairment charge, of which only $42.6 million is deductible for income
tax purposes, further decreased our effective tax rate for the year ended December 31, 2011. The
decrease was also impacted by a $3.9 million net tax benefit recorded on the sale of loans and interest
in an entity related to a project in Nigeria in the year ended December 31, 2010.
Discontinued Operations
(dollars in thousands)
Years Ended
December 31,
2011
2010
Increase
(Decrease)
Income (loss) from discontinued operations, net of tax . . . . . . . . . . . . .
$(10,105) $40,739
(125)%
Income (loss) from discontinued operations, net of tax for the years ended December 31, 2011 and
2010 related to our operations in Venezuela that were expropriated in June 2009, including the costs
associated with our arbitration proceeding. As discussed in Note 2 to the Financial Statements, in June
2009, PDVSA assumed control over substantially all of our assets and operations in Venezuela. Income
(loss) from discontinued operations, net of tax, for the year ended December 31, 2010 includes a
benefit of $41.0 million of payments received from PDVSA and its affiliates as consideration for the
fixed assets of two projects. In January 2010, the Venezuelan government announced a devaluation of
the Venezuelan bolivar. This devaluation resulted in a translation gain of approximately $12.2 million
on the remeasurement of our net liability position in Venezuela and is reflected in Income (loss) from
discontinued operations, net of tax, for the year ended December 31, 2010. The functional currency of
our Venezuela subsidiary is the U.S. dollar, and we had more liabilities than assets denominated in
bolivars in Venezuela at the time of the devaluation. The exchange rate used to remeasure our net
liabilities changed from 2.15 bolivars per U.S. dollar at December 31, 2009 to 4.3 bolivars per U.S.
dollar in January 2010.
In June 2012, we committed to a plan to sell our contract operations and aftermarket services
businesses in Canada as part of our continued emphasis on simplification and focus on our core
businesses. We expect this sale to be completed within the next twelve months. Our Canadian contract
operations and aftermarket services businesses are reflected as discontinued operations in our
consolidated financial statements. These operations were previously included in our North American
contract operations and aftermarket services business segments.
Noncontrolling Interest
As of December 31, 2011, noncontrolling interest is comprised of the portion of the Partnership’s
earnings that is applicable to the limited partner interest in the Partnership owned by the public. As of
December 31, 2011, public unitholders held a 65% ownership interest in the Partnership.
Liquidity and Capital Resources
Our unrestricted cash balance was $34.6 million at December 31, 2012 and $21.9 million at
December 31, 2011. Working capital increased to $463.4 million at December 31, 2012 from
$454.0 million at December 31, 2011. The increase in working capital was primarily due to an increase
in current deferred income tax assets and inventory, partially offset by an increase in billings on
uncompleted contracts in excess of costs and estimated earnings and accounts payable. The increase in
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current deferred taxes was primarily due to an increase in the 2013 expected realization of net
operating losses in the U.S. The increase in inventory was due to increased activity in our North
American fabrication business in 2012. The increase in billings on uncompleted contracts in excess of
costs and estimated earnings was primarily driven by the timing of billings on projects in North
America and Eastern Hemisphere at December 31, 2012 as compared to December 31, 2011. The
increase in accounts payable was due to an increase in payables related to fabrication projects primarily
in North America, partially offset by a decrease in payables at our Belleli Energy subsidiary as a result
of reduced activity.
Our cash flows from operating, investing and financing activities, as reflected in the consolidated
statements of cash flows, are summarized in the table below (in thousands):
Years Ended December 31,
2012
2011
Net cash provided by (used in) continuing operations:
Operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financing activities
Effect of exchange rate changes on cash and cash equivalents . . . . . . . . . . . . .
Discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
387,871
(341,410)
(171,290)
(486)
138,013
111,717
(231,794)
99,290
(3,007)
1,336
Net change in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 12,698
$ (22,458)
Operating Activities. The increase in cash provided by operating activities was primarily due to
improved results from operations including the increase in gross margin and cash provided by working
capital during the year ended December 31, 2012 compared to the year ended December 31, 2011.
Changes in working capital items were primarily driven by increases in deferred revenue and costs and
estimated earnings versus billings on uncompleted contracts during the year ended December 31, 2012
compared to decreases in these items during the year ended December 31, 2011. These changes were
partially offset by an increase in inventory during the year ended December 31, 2012 compared to a
decrease in inventory during the year ended December 31, 2011.
Investing Activities. The increase in cash used in investing activities was primarily attributable to
an increase in capital expenditures from $272.2 million during the year ended December 31, 2011 to
$428.7 million during the year ended December 31, 2012, partially offset by $51.7 million of net
proceeds received in 2012 from the sale of our Venezuelan joint ventures’ assets.
Financing Activities. The increase in cash used in financing activities during the year ended
December 31, 2012 compared to the year ended December 31, 2011 was primarily attributable to a
decrease in net proceeds from the sale of Partnership units from $289.9 million during the year ended
December 31, 2011 to $114.5 million during the year ended December 31, 2012 and an increase of
$86.2 million in net repayments of long term debt during the year ended December 31, 2012 compared
to the year ended December 31, 2011.
Discontinued Operations. The increase in cash provided by discontinued operations during the
year ended December 31, 2012 compared to the year ended December 31, 2011 was primarily
attributable to $143.5 million of net proceeds received in 2012 from the sale of our Venezuelan
subsidiary’s assets.
Capital Expenditures. We generally invest funds necessary to fabricate fleet additions when our
idle equipment cannot be reconfigured to economically fulfill a project’s requirements and the new
equipment expenditure is expected to generate economic returns over its expected useful life that
exceed our targeted return on capital. We currently plan to spend approximately $425 million to
$450 million in net capital expenditures during 2013, including (1) contract operations equipment
additions and (2) approximately $105 million to $115 million on equipment maintenance capital related
to our contract operations business. Net capital expenditures are net of fleet sales.
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Long-Term Debt. As of December 31, 2012, we had approximately $1.6 billion in outstanding debt
obligations, consisting of $70.0 million outstanding under our revolving credit facility, $143.8 million
outstanding under our 4.75% convertible notes, $320.7 million outstanding under our 4.25% Notes,
$350.0 million outstanding under our 7.25% senior notes, $530.5 million outstanding under the
Partnership’s revolving credit facility and $150.0 million outstanding under the Partnership’s term loan
facility.
In January 2013, we redeemed for cash all $143.8 million principal amount outstanding of our of
4.75% Convertible Senior Notes (the ‘‘4.75% Notes’’) at a redemption price of 100% of the principal
amount thereof plus accrued but unpaid interest to, but excluding, the redemption date. The
redemption of the 4.75% Notes was financed from our revolving credit facility. At December 31, 2012,
we had $0.9 million of unamortized deferred financing costs that will be expensed in the first quarter of
2013.
In July 2011, we entered into a five-year, $1.1 billion senior secured revolving credit facility (the
‘‘2011 Credit Facility’’), which matures in July 2016 and replaced our former senior secured credit
facility. In March 2012, we decreased the borrowing capacity under this facility by $200.0 million to
$900.0 million. As of December 31, 2012, we had $70.0 million in outstanding borrowings and
$183.9 million in outstanding letters of credit under the 2011 Credit Facility. At December 31, 2012,
taking into account guarantees through letters of credit, and the March 2012 decrease in borrowing
capacity, we had undrawn and available capacity of $646.1 million under this facility.
Borrowings under the 2011 Credit Facility bear interest at a base rate or LIBOR, at our option,
plus an applicable margin. Depending on our Total Leverage Ratio (as defined in the credit
agreement), the applicable margin for revolving loans varies (i) in the case of LIBOR loans, from
1.50% to 2.50% and (ii) in the case of base rate loans, from 0.50% to 1.50%. The base rate is the
highest of the prime rate announced by Wells Fargo Bank, National Association, the Federal Funds
Rate plus 0.5% and one-month LIBOR plus 1.0%. At December 31, 2012, all amounts outstanding
under the 2011 Credit Facility were LIBOR loans and the applicable margin was 1.75%. The weighted
average annual interest rate at December 31, 2012 on the outstanding balance under the 2011 Credit
Facility was 2.0%.
Our Significant Domestic Subsidiaries (as defined in the credit agreement) guarantee the debt
under the 2011 Credit Facility. Borrowings under the 2011 Credit Facility are secured by substantially
all of the personal property assets and certain real property assets of us and our Significant Domestic
Subsidiaries, including all of the equity interests of our U.S. subsidiaries (other than certain excluded
subsidiaries) and 65% of the equity interests in certain of our first-tier foreign subsidiaries. The
Partnership does not guarantee the debt under the 2011 Credit Facility, its assets are not collateral
under the 2011 Credit Facility and the general partner units in the Partnership are not pledged under
the 2011 Credit Facility. Subject to certain conditions, at our request, and with the approval of the
lenders, the aggregate commitments under the 2011 Credit Facility may be increased by up to an
additional $300 million.
The credit agreement contains various covenants with which we or certain of our subsidiaries must
comply, including, but not limited to, restrictions on the use of proceeds from borrowings and
limitations on our ability to incur additional indebtedness, enter into transactions with affiliates, merge
or consolidate, sell assets, make certain investments and acquisitions, make loans, grant liens,
repurchase equity and pay dividends and distributions. We are also subject to financial covenants,
including a ratio of Adjusted EBITDA (as defined in the credit agreement) to Total Interest Expense
(as defined in the credit agreement) of not less than 2.25 to 1.0, a ratio of consolidated Total Debt (as
defined in the credit agreement) to Adjusted EBITDA of not greater than 5.0 to 1.0 and a ratio of
Senior Secured Debt (as defined in the credit agreement) to Adjusted EBITDA of not greater than 4.0
to 1.0. As of December 31, 2012, we maintained a 5.3 to 1.0 Adjusted EBITDA to Total Interest
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Expense ratio, a 2.4 to 1.0 consolidated Total Debt to Adjusted EBITDA ratio and a 0.2 to 1.0 Senior
Secured Debt to Adjusted EBITDA ratio. If we fail to remain in compliance with our financial
covenants we would be in default under our debt agreements. In addition, if we experience a material
adverse effect on our assets, liabilities, financial condition, business or operations that, taken as a
whole, impacts our ability to perform our obligations under our debt agreements, this could lead to a
default under our debt agreements. A default under one or more of our debt agreements, including a
default by the Partnership under its credit facility, would trigger cross-default provisions under certain
of our other debt agreements, which would accelerate our obligation to repay our indebtedness under
those agreements.
In November 2010, we issued $350.0 million aggregate principal amount of 7.25% senior notes (the
‘‘7.25% Notes’’). The 7.25% Notes are guaranteed on a senior unsecured basis by all of our existing
subsidiaries that guarantee indebtedness under the Credit Agreement and certain of our future
subsidiaries. The Partnership and its subsidiaries have not guaranteed the 7.25% Notes. The 7.25%
Notes and the guarantees are our and the guarantors’ general unsecured senior obligations,
respectively, rank equally in right of payment with all of our and the guarantors’ other senior
obligations, and are effectively subordinated to all of our and the guarantors’ existing and future
secured debt to the extent of the value of the collateral securing such indebtedness. In addition, the
7.25% Notes and guarantees are structurally subordinated to all existing and future indebtedness and
other liabilities, including trade payables, of our non-guarantor subsidiaries.
Prior to December 1, 2013, we may redeem all or a part of the 7.25% Notes at a redemption price
equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the
redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, we may
redeem up to 35% of the aggregate principal amount of the 7.25% Notes prior to December 1, 2013
with the net proceeds of a public or private equity offering at a redemption price of 107.250% of the
principal amount of the 7.25% Notes, plus any accrued and unpaid interest to the date of redemption,
if at least 65% of the aggregate principal amount of the 7.25% Notes issued under the indenture
remains outstanding after such redemption and the redemption occurs within 120 days of the date of
the closing of such equity offering. On or after December 1, 2013, we may redeem all or a part of the
7.25% Notes at redemption prices (expressed as percentages of principal amount) equal to 105.438%
for the twelve-month period beginning on December 1, 2013, 103.625% for the twelve-month period
beginning on December 1, 2014, 101.813% for the twelve-month period beginning on December 1, 2015
and 100.000% for the twelve-month period beginning on December 1, 2016 and at any time thereafter,
plus accrued and unpaid interest, if any, to the applicable redemption date on the 7.25% Notes.
In June 2009, we issued $355.0 million aggregate principal amount of 4.25% convertible senior
notes (the ‘‘4.25% Notes’’). The 4.25% Notes are convertible upon the occurrence of certain conditions
into shares of our common stock at an initial conversion rate of 43.1951 shares of our common stock
per $1,000 principal amount of the convertible notes, equivalent to an initial conversion price of
approximately $23.15 per share of common stock. The conversion rate will be subject to adjustment
following certain dilutive events and certain corporate transactions. We may not redeem the 4.25%
Notes prior to their maturity date.
The 4.25% Notes are our senior unsecured obligations and rank senior in right of payment to our
existing and future indebtedness that is expressly subordinated in right of payment to the 4.25% Notes;
equal in right of payment to our existing and future unsecured indebtedness that is not so
subordinated; junior in right of payment to any of our secured indebtedness to the extent of the value
of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness
and liabilities incurred by our subsidiaries. The 4.25% Notes are not guaranteed by any of our
subsidiaries.
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In November 2010, the Partnership, as guarantor, and EXLP Operating LLC, a wholly-owned
subsidiary of the Partnership, as borrower, entered into an amendment and restatement of their senior
secured credit agreement (the ‘‘Partnership Credit Agreement’’) to provide for a five-year
$550.0 million senior secured credit facility, consisting of a $400.0 million revolving credit facility and a
$150.0 million term loan facility. The revolving borrowing capacity under this facility was increased by
$150.0 million to $550.0 million in March 2011 and by $200.0 million to $750.0 million in March 2012.
As of December 31, 2012, the Partnership had undrawn capacity of $219.5 million under its revolving
credit facility. The Partnership Credit Agreement limits its Total Debt (as defined in the Partnership
Credit Agreement) to EBITDA ratio (as defined in the Partnership Credit Agreement) to not greater
than 4.75 to 1.0 (which will increase to 5.25 to 1.0 following the occurrence of certain events specified
in the Partnership Credit Agreement). As a result of this limitation, $199.4 million of the $219.5 million
of undrawn capacity under the Partnership’s revolving credit facility was available for additional
borrowings as of December 31, 2012.
The Partnership’s revolving credit facility bears interest at a base rate or LIBOR, at the
Partnership’s option, plus an applicable margin. Depending on the Partnership’s leverage ratio, the
applicable margin for revolving loans varies (i) in the case of LIBOR loans, from 2.25% to 3.25% and
(ii) in the case of base rate loans, from 1.25% to 2.25%. The base rate is the highest of the prime rate
announced by Wells Fargo Bank, National Association, the Federal Funds Effective Rate plus 0.5% and
one-month LIBOR plus 1.0%. At December 31, 2012, all amounts outstanding under this facility were
LIBOR loans and the applicable margin was 2.5%. The weighted average annual interest rate on the
outstanding balance of this facility at December 31, 2012, excluding the effect of interest rate swaps,
was 2.8%.
The Partnership’s term loan facility bears interest at a base rate or LIBOR, at the Partnership’s
option, plus an applicable margin. Depending on the Partnership’s leverage ratio, the applicable margin
for term loans varies (i) in the case of LIBOR loans, from 2.5% to 3.5% and (ii) in the case of base
rate loans, from 1.5% to 2.5%. At December 31, 2012, all amounts outstanding under the term loan
facility were LIBOR loans and the applicable margin was 2.75%. The average annual interest rate on
the outstanding balance of the term loan at December 31, 2012 was 3.0%.
Borrowings under the Partnership Credit Agreement are secured by substantially all of the U.S.
personal property assets of the Partnership and its Significant Domestic Subsidiaries (as defined in the
Partnership Credit Agreement), including all of the membership interests of the Partnership’s Domestic
Subsidiaries (as defined in the Partnership Credit Agreement).
The Partnership Credit Agreement contains various covenants with which the Partnership must
comply, including, but not limited to, restrictions on the use of proceeds from borrowings and
limitations on its ability to incur additional indebtedness, enter into transactions with affiliates, merge
or consolidate, sell assets, make certain investments and acquisitions, make loans, grant liens,
repurchase equity and pay dividends and distributions. It also contains various covenants requiring
mandatory prepayments of the term loans from the net cash proceeds of certain future asset transfers.
The Partnership must maintain various consolidated financial ratios, including a ratio of EBITDA (as
defined in the Partnership Credit Agreement) to Total Interest Expense (as defined in the Partnership
Credit Agreement) of not less than 3.0 to 1.0 (which will decrease to 2.75 to 1.0 following the
occurrence of certain events specified in the Partnership Credit Agreement) and a ratio of Total Debt
(as defined in the Partnership Credit Agreement) to EBITDA of not greater than 4.75 to 1.0 (which
will increase to 5.25 to 1.0 following the occurrence of certain events specified in the Partnership Credit
Agreement). As of December 31, 2012, the Partnership maintained an 8.0 to 1.0 EBITDA to Total
Interest Expense ratio and a 3.7 to 1.0 Total Debt to EBITDA ratio. A violation of the Partnership’s
Total Debt to EBITDA covenant would be an event of default under the Partnership Credit
Agreement, which would trigger cross-default provisions under certain of our debt agreements. As of
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December 31, 2012, the Partnership was in compliance with all financial covenants under the
Partnership Credit Agreement.
We have entered into interest rate swap agreements related to a portion of our variable rate debt.
In the fourth quarter of 2010, we paid $43.0 million to terminate interest rate swap agreements with a
total notional value of $585.0 million and a weighted average effective fixed rate of 4.6%. These swaps
qualified for hedge accounting and were previously included on our balance sheet as a liability and in
accumulated other comprehensive income (loss). The liability was paid in connection with the
termination, and the associated amount in accumulated other comprehensive income (loss) is being
amortized into interest expense over the original terms of the swaps. Of the total amount included in
accumulated other comprehensive income (loss), $10.7 million was amortized into interest expense
during the year ended December 31, 2012 and we expect $1.6 million to be amortized into interest
expense in 2013. See Part II,
Item 7A ‘‘Quantitative and Qualitative Disclosures About Market Risk’’ of this report for further
discussion of our interest rate swap agreements.
We may from time to time seek to retire or purchase our outstanding debt though cash purchases
and/or exchanges for equity securities, in open market purchases, privately negotiated transactions or
otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our
liquidity requirements, contractual restrictions and other factors. The amounts involved may be
material.
Historically, we have financed capital expenditures with a combination of net cash provided by
operating and financing activities. Our ability to access the capital markets may be restricted at a time
when we would like, or need, to do so, which could have an adverse impact on our ability to maintain
our operations and to grow. If any of our lenders become unable to perform their obligations under
our credit facilities, our borrowing capacity under these facilities could be reduced. Inability to borrow
additional amounts under those facilities could limit our ability to fund our future growth and
operations. Based on current market conditions, we expect that net cash provided by operating
activities and borrowings under our credit facilities will be sufficient to finance our operating
expenditures, capital expenditures and scheduled interest and debt repayments through December 31,
2013; however, to the extent it is not, we may seek additional debt or equity financing.
Dividends. We have not paid any cash dividends on our common stock since our formation, and
we do not anticipate paying such dividends in the foreseeable future. Our board of directors anticipates
that all cash flows generated from operations in the foreseeable future will be retained and used to
repay our debt or develop and expand our business, except for a portion of the cash flow generated
from operations of the Partnership which is expected to be used to pay distributions on its units. Any
future determinations to pay cash dividends on our common stock will be at the discretion of our board
of directors and will depend on our financial condition and results of operations, credit and loan
agreements in effect at that time and other factors deemed relevant by our board of directors.
Partnership Distributions to Unitholders. The Partnership’s partnership agreement requires it to
distribute all of its ‘‘available cash’’ quarterly. Under the partnership agreement, available cash is
defined generally to mean, for each fiscal quarter, (1) cash on hand at the Partnership at the end of the
quarter in excess of the amount of reserves its general partner determines is necessary or appropriate
to provide for the conduct of its business, to comply with applicable law, any of its debt instruments or
other agreements or to provide for future distributions to its unitholders for any one or more of the
upcoming four quarters, plus, (2) if the Partnership’s general partner so determines, all or a portion of
the Partnership’s cash on hand on the date of determination of available cash for the quarter.
Under the terms of the partnership agreement, there is no guarantee that unitholders will receive
quarterly distributions from the Partnership. The Partnership’s distribution policy, which may be
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changed at any time, is subject to certain restrictions, including (1) restrictions contained in the
Partnership’s revolving credit facility, (2) the Partnership’s general partner’s establishment of reserves to
fund future operations or cash distributions to the Partnership’s unitholders, (3) restrictions contained
in the Delaware Revised Uniform Limited Partnership Act and (4) the Partnership’s lack of sufficient
cash to pay distributions.
Through our ownership of common units and all of the equity interests in the Partnership’s general
partner, we expect to receive cash distributions from the Partnership.
On January 29, 2013, Exterran GP LLC’s board of directors approved a cash distribution by the
Partnership of $0.5125 per limited partner unit, or approximately $23.3 million, including distributions
to the Partnership’s general partner on its incentive distribution rights. The distribution covers the
period from October 1, 2012 through December 31, 2012. The record date for this distribution was
February 8, 2013.
Contractual obligations. The following summarizes our cash contractual obligations as of
December 31, 2012 and the effect such obligations are expected to have on our liquidity and cash flow
in future periods (in thousands):
Total
2013
2014 - 2015
2016 - 2017
Thereafter
Long-term Debt(1):
Revolving credit facility due July 2016 . .
Partnership’s revolving credit facility due
November 2015 . . . . . . . . . . . . . . . . .
Partnership’s term loan facility due
November 2015 . . . . . . . . . . . . . . . . .
4.25% convertible senior notes due June
2014(2) . . . . . . . . . . . . . . . . . . . . . . .
4.75% convertible senior notes due
January 2014 . . . . . . . . . . . . . . . . . . .
7.25% senior notes due December 2018 .
Total long-term debt
. . . . . . . . . . . . .
Interest on long-term debt(3) . . . . . . . . . .
Purchase commitments . . . . . . . . . . . . . . .
Facilities and other operating leases . . . . .
$
70,000
$
— $
— $ 70,000
$
530,500
150,000
355,000
143,750
350,000
1,599,250
260,476
457,156
65,705
—
—
—
—
—
530,500
150,000
355,000
143,750
—
— 1,179,250
109,441
—
16,968
74,935
457,156
12,930
—
—
—
—
—
—
—
—
—
— 350,000
70,000
52,811
—
12,885
350,000
23,289
—
22,922
Total contractual obligations . . . . . . . . . . .
$2,382,587
$545,021
$1,305,659
$135,696
$396,211
(1) For more information on our long-term debt, see Note 10 to the Financial Statements.
(2) These amounts include the full face value of the 4.25% Notes and are not reduced by the
unamortized discount of $34.3 million as of December 31, 2012.
(3) Interest amounts calculated using interest rates in effect as of December 31, 2012, including the
effect of interest rate swaps.
At December 31, 2012, $9.6 million of unrecognized tax benefits (including discontinued
operations) have been recorded as liabilities in accordance with the accounting standard for income
taxes related to uncertain tax positions and we are uncertain as to if or when such amounts may be
settled. Related to these unrecognized tax benefits, we have also recorded a liability for potential
penalties and interest of $2.4 million (including discontinued operations).
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Off-Balance Sheet Arrangements
We have no material off-balance sheet arrangements.
Effects of Inflation
Our revenues and results of operations have not been materially impacted by inflation in the past
three fiscal years.
Critical Accounting Estimates
This discussion and analysis of our financial condition and results of operations is based upon our
consolidated financial statements, which have been prepared in accordance with accounting principles
generally accepted in the U.S. (‘‘GAAP’’). The preparation of these financial statements requires us to
make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and
expenses, and related disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate
our estimates and accounting policies, including those related to bad debts, inventories, fixed assets,
investments, intangible assets, income taxes, revenue recognition and contingencies and litigation. We
base our estimates on historical experience and on other assumptions that we believe are reasonable
under the circumstances. The results of this process form the basis of our judgments about the carrying
values of assets and liabilities that are not readily apparent from other sources. Actual results may
differ from these estimates under different assumptions or conditions, and these differences can be
material to our financial condition, results of operations and liquidity. We describe our significant
accounting policies more fully in Note 1 to our Financial Statements.
Allowances and Reserves
We maintain allowances for doubtful accounts for estimated losses resulting from the inability of
our customers to make required payments. The determination of the collectibility of amounts due from
our customers requires us to use estimates and make judgments regarding future events and trends,
including monitoring our customers’ payment history and current creditworthiness to determine that
collectibility is reasonably assured, as well as consideration of the overall business climate in which our
customers operate. Inherently, these uncertainties require us to make judgments and estimates
regarding our customers’ ability to pay amounts due us in order to determine the appropriate amount
of valuation allowances required for doubtful accounts. We review the adequacy of our allowance for
doubtful accounts quarterly. We determine the allowance needed based on historical write-off
experience and by evaluating significant balances aged greater than 90 days individually for
collectibility. Account balances are charged off against the allowance after all means of collection have
been exhausted and the potential for recovery is considered remote. During the years ended
December 31, 2012, 2011 and 2010, we recorded bad debt expense of $8.8 million, $1.5 million and
$4.7 million, respectively. A five percent change in the allowance for doubtful accounts would have had
an impact on income (loss) before income taxes of approximately $0.8 million for the year ended
December 31, 2012.
Inventory is a significant component of current assets and is stated at the lower of cost or market.
This requires us to record provisions and maintain reserves for excess, slow moving and obsolete
inventory. To determine these reserve amounts, we regularly review inventory quantities on hand and
compare them to estimates of future product demand, market conditions and production requirements.
These estimates and forecasts inherently include uncertainties and require us to make judgments
regarding potential outcomes. During 2012, 2011, and 2010, we recorded additional inventory reserves
of $1.0 million, $5.0 million and $2.3 million, respectively. Significant or unanticipated changes to our
estimates and forecasts could impact the amount and timing of any additional provisions for excess or
obsolete inventory that may be required. A five percent change in this inventory reserve balance would
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have had an impact on income (loss) before income taxes of approximately $0.6 million for the year
ended December 31, 2012.
Depreciation
Property, plant and equipment are carried at cost. Depreciation for financial reporting purposes is
computed on the straight-line basis using estimated useful lives and salvage values. The assumptions
and judgments we use in determining the estimated useful lives and salvage values of our property,
plant and equipment reflect both historical experience and expectations regarding future use of our
assets. The use of different estimates, assumptions and judgments in the establishment of property,
plant and equipment accounting policies, especially those involving their useful lives, would likely result
in significantly different net book values of our assets and results of operations.
Long-Lived Assets
We review for impairment of long-lived assets, including property, plant and equipment and
identifiable intangibles that are being amortized, whenever events or changes in circumstances indicate
that the carrying amount of an asset may not be recoverable. The determination that the carrying
amount of an asset may not be recoverable requires us to make judgments regarding long-term
forecasts of future revenues and costs related to the assets subject to review. These forecasts are
uncertain as they require significant assumptions about future market conditions. Significant and
unanticipated changes to these assumptions could require a provision for impairment in a future
period. Given the nature of these evaluations and their application to specific assets and specific times,
it is not possible to reasonably quantify the impact of changes in these assumptions. An impairment
loss exists when estimated undiscounted cash flows expected to result from the use of the asset and its
eventual disposition are less than its carrying amount. When necessary, an impairment loss is
recognized and represents the excess of the asset’s carrying value as compared to its estimated fair
value and is charged to the period in which the impairment occurred.
Income Taxes
Our income tax expense, deferred tax assets and liabilities, and reserves for unrecognized tax
benefits reflect management’s best assessment of estimated current and future taxes to be paid. We
operate in approximately 30 countries and, as a result, are subject to income taxes in both the U.S. and
numerous foreign jurisdictions. Significant judgments and estimates are required in determining
consolidated income tax expense.
Deferred income taxes arise from temporary differences between the financial statements and tax
basis of assets and liabilities. In evaluating our ability to recover our deferred tax assets within the
jurisdiction from which they arise, we consider all available positive and negative evidence, including
scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies,
and results of recent operations. In projecting future taxable income, we begin with historical results
adjusted for the results of discontinued operations and changes in accounting policies and incorporate
assumptions including the amount of future U.S. federal, state and foreign pretax operating income, the
reversal of temporary differences and the implementation of feasible and prudent tax-planning
strategies. These assumptions require significant judgment about the forecasts of future taxable income
and are consistent with the plans and estimates we are using to manage the underlying businesses. In
evaluating the objective evidence that historical results provide, we consider three years of cumulative
operating income (loss).
Changes in tax laws and rates could also affect recorded deferred tax assets and liabilities in the
future. Management is not aware of any such changes that would have a material effect on the
Company’s financial position, results of operations or cash flows. The calculation of our tax liabilities
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involves dealing with uncertainties in the application of complex tax laws and regulations in a multitude
of jurisdictions across our global operations.
The accounting standard for income taxes provides that a tax benefit from an uncertain tax
position may be recognized when it is more likely than not that the position will be sustained upon
examination, including resolutions of any related appeals or litigation processes, on the basis of the
technical merits. In addition, guidance is provided on measurement, derecognition, classification,
interest and penalties, accounting in interim periods, disclosure and transition. We adjust these
liabilities when our judgment changes as a result of the evaluation of new information not previously
available. Because of the complexity of some of these uncertainties, the ultimate resolution may result
in a payment that is materially different from our current estimate of the tax liabilities. These
differences will be reflected as increases or decreases to income tax expense in the period in which new
information is available.
We consider the earnings of certain non-U.S. subsidiaries to be indefinitely invested outside the
U.S. on the basis of estimates that future domestic cash generation will be sufficient to meet future
domestic cash needs. We have not recorded a deferred tax liability related to these unremitted foreign
earnings as it is not practicable to estimate the amount of unrecognized deferred tax liabilities. Should
we decide to repatriate any unremitted foreign earnings, we would have to adjust the income tax
provision in the period we determined that such earnings will no longer be indefinitely invested outside
the U.S.
Revenue Recognition—Percentage-of-Completion Accounting
We recognize revenue and profit for our fabrication operations as work progresses on long-term
contracts using the percentage-of-completion method when the applicable criteria are met, which relies
on estimates of total expected contract revenue and costs. We follow this method because reasonably
dependable estimates of the revenue and costs applicable to various stages of a contract can be made
and because the fabrication projects usually last several months. Recognized revenues and profit are
subject to revisions as the contract progresses to completion. Revisions in profit estimates are charged
to income in the period in which the facts that give rise to the revision become known. The typical
duration of these projects is three to 36 months. Due to the long-term nature of some of our jobs,
developing the estimates of cost often requires significant judgment.
We estimate percentage-of-completion for compressor and accessory fabrication on a direct labor
hour to total labor hour basis. This calculation requires management to estimate the number of total
labor hours required for each project and to estimate the profit expected on the project. Production
and processing equipment fabrication percentage-of-completion is estimated using the direct labor hour
and cost to total cost basis. The cost to total cost basis requires us to estimate the amount of total costs
(labor and materials) required to complete each project. Because we have many fabrication projects in
process at any given time, we do not believe that materially different results would be achieved if
different estimates, assumptions or conditions were used for any single project.
Factors that must be considered in estimating the work to be completed and ultimate profit
include labor productivity and availability, the nature and complexity of work to be performed, the
impact of change orders, availability of raw materials and the impact of delayed performance. If the
aggregate combined cost estimates for all of our fabrication businesses had been higher or lower by 1%
in 2012, our results of operations before tax would have decreased or increased by approximately
$11.9 million. As of December 31, 2012, we had recognized approximately $195.7 million in estimated
earnings on uncompleted contracts.
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Contingencies and Litigation
We are substantially self-insured for worker’s compensation, employer’s liability, property, auto
liability, general liability and employee group health claims in view of the relatively high per-incident
deductibles we absorb under our insurance arrangements for these risks. In addition, we currently have
a minimal amount of insurance on our offshore assets. Losses up to deductible amounts are estimated
and accrued based upon known facts, historical trends and industry averages. We review these estimates
quarterly and believe such accruals to be adequate. However, insurance liabilities are difficult to
estimate due to unknown factors, including the severity of an injury, the determination of our liability
in proportion to other parties, the timeliness of reporting of occurrences, ongoing treatment or loss
mitigation, general trends in litigation recovery outcomes and the effectiveness of safety and risk
management programs. Therefore, if our actual experience differs from the assumptions and estimates
used for recording the liabilities, adjustments may be required and would be recorded in the period in
which the difference becomes known. As of December 31, 2012 and 2011, we had recorded
approximately $8.4 million and $6.3 million, respectively, in claim reserves.
In the ordinary course of business, we are involved in various pending or threatened legal actions.
While we are unable to predict the ultimate outcome of these actions, the accounting standard for
contingencies requires management to make judgments about future events that are inherently
uncertain. We are required to record (and have recorded) a loss during any period in which we believe
a contingency is probable and can be reasonably estimated. In making determinations of likely
outcomes of pending or threatened legal matters, we consider the evaluation of counsel knowledgeable
about each matter.
The impact of an uncertain tax position taken or expected to be taken on an income tax return
must be recognized in the financial statements at the largest amount that is more likely than not to be
sustained upon examination by the relevant taxing authority in accordance with the accounting standard
for income taxes. We regularly assess and, if required, establish accruals for tax contingencies pursuant
to the applicable accounting standards that could result from assessments of additional tax by taxing
jurisdictions in countries where we operate. The tax contingencies are subject to a significant amount of
judgment and are reviewed and adjusted on a quarterly basis in light of changing facts and
circumstances considering the outcome expected by management. As of December 31, 2012 and 2011,
we had recorded approximately $36.7 million and $50.7 million (including penalties and interest and
discontinued operations), respectively, of accruals for tax contingencies. If our actual experience differs
from the assumptions and estimates used for recording the liabilities, adjustments may be required and
would be recorded in the period in which the difference becomes known.
Recent Accounting Pronouncements
For a discussion of recent accounting pronouncements that may affect us, see Note 21 to the
Financial Statements.
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Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risks primarily associated with changes in interest rates and foreign
currency exchange rates. We use derivative financial instruments to minimize the risks and/or costs
associated with financial activities by managing our exposure to interest rate fluctuations on a portion
of our debt obligations. We do not use derivative financial instruments for trading or other speculative
purposes.
We have significant international operations. The net assets and liabilities of these operations are
exposed to changes in currency exchange rates. These operations may also have net assets and liabilities
not denominated in their functional currency, which exposes us to changes in foreign currency exchange
rates that impact income. We recorded a foreign currency loss in our consolidated statements of
operations of $8.2 million and $16.5 million for the years ended December 31, 2012 and 2011,
respectively. Our foreign currency gains and losses are primarily due to exchange rate fluctuations
related to monetary asset balances denominated in currencies other than the functional currency.
Changes in exchange rates may create gains or losses in future periods to the extent we maintain net
assets and liabilities not denominated in the functional currency.
As of December 31, 2012, after taking into consideration interest rate swaps, we had approximately
$500.5 million of outstanding indebtedness that was effectively subject to floating interest rates. A 1%
increase in the effective interest rate on our outstanding debt subject to floating interest rates would
result in an annual increase in our interest expense of approximately $5.0 million.
For further information regarding our use of interest rate swap agreements to manage our
exposure to interest rate fluctuations on a portion of our debt obligations, see Note 11 to the Financial
Statements.
Item 8. Financial Statements and Supplementary Data
The financial statements and supplementary information specified by this Item are presented in
Part IV, Item 15 of this report.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Management’s Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, our principal executive officer and principal
financial officer evaluated the effectiveness of our disclosure controls and procedures (as defined in
Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the ‘‘Exchange Act’’)), which are
designed to provide reasonable assurance that we are able to record, process, summarize and report the
information required to be disclosed in our reports under the Exchange Act within the time periods
specified in the rules and forms of the Securities and Exchange Commission. Based on the evaluation,
as of December 31, 2012 our principal executive officer and principal financial officer have concluded
that our disclosure controls and procedures were effective to provide reasonable assurance that the
information required to be disclosed in reports that we file or submit under the Exchange Act is
accumulated and communicated to management, and made known to our principal executive officer
and principal financial officer, on a timely basis to ensure that it is recorded, processed, summarized
and reported within the time periods specified in the SEC’s rules and forms.
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Management’s Annual Report on Internal Control Over Financial Reporting
As required by Exchange Act Rules 13a-15(c) and 15d-15(c), our management, including the Chief
Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate
internal control over financial reporting. Management conducted an evaluation of the effectiveness of
internal control over financial reporting based on the Internal Control—Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission. Because of its inherent
limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness as 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. Based on the results of management’s evaluation described
above, management concluded that our internal control over financial reporting was effective as of
December 31, 2012.
The effectiveness of internal control over financial reporting as of December 31, 2012 was audited
by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in its report
found within this report.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting (as defined in Exchange Act
Rules 13a-15(f) and 15d-15(f)) during the last fiscal quarter that materially affected, or are reasonably
likely to materially affect, our internal control over financial reporting.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Exterran Holdings, Inc.
Houston, Texas
We have audited the internal control over financial reporting of Exterran Holdings, Inc. and
subsidiaries (the ‘‘Company’’) as of December 31, 2012, based on the criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission. The Company’s management is responsible for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness of internal control over financial
reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial
Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial
reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was maintained
in all material respects. Our audit included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, 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 by, or under the
supervision of, the company’s principal executive and principal financial officers, or persons performing
similar functions, and effected by the company’s board of directors, management, and other personnel
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
(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.
Because of the inherent limitations of internal control over financial reporting, including the
possibility of collusion or improper management override of controls, material misstatements due to
error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation
of the effectiveness of the internal control over financial reporting to future periods are subject to the
risk that the controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over
financial reporting as of December 31, 2012, based on the criteria established in Internal Control—
Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission.
We have also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated financial statements and financial statement schedule
as of and for the year ended December 31, 2012 of the Company and our report dated February 26,
2013 expressed an unqualified opinion on those financial statements and financial statement schedule.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 26, 2013
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Item 9B. Other Information
None.
Item 10. Directors, Executive Officers and Corporate Governance
PART III
The information required in Part III, Item 10 of this report is incorporated by reference to the
sections entitled ‘‘Election of Directors,’’ ‘‘Information Regarding Corporate Governance, the Board of
Directors and Committees of the Board,’’ ‘‘Executive Officers’’ and ‘‘Beneficial Ownership of Common
Stock—Section 16(a) Beneficial Ownership Reporting Compliance’’ in our definitive proxy statement, to
be filed with the SEC within 120 days of the end of our fiscal year.
Item 11. Executive Compensation
The information required in Part III, Item 11 of this report is incorporated by reference to the
sections entitled ‘‘Compensation Discussion and Analysis’’ and ‘‘Information Regarding Executive
Compensation’’ in our definitive proxy statement, to be filed with the SEC within 120 days of the end
of our fiscal year.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
Portions of the information required in Part III, Item 12 of this report are incorporated by
reference to the section entitled ‘‘Beneficial Ownership of Common Stock’’ in our definitive proxy
statement, to be filed with the SEC within 120 days of the end of our fiscal year.
Securities Authorized for Issuance under Equity Compensation Plans
The following table sets forth information as of December 31, 2012, with respect to the Exterran
compensation plans under which our common stock is authorized for issuance, aggregated as follows:
(a)
Number of Securities
to be Issued Upon
Exercise of
(b)
Weighted-Average
Exercise Price of
Outstanding Options, Outstanding Options,
Warrants and Rights Warrants and Rights
Plan Category
(#)
Equity compensation plans approved
by security holders(1) . . . . . . . . . . .
1,722,645
Equity compensation plans not
approved by security holders(2) . . . .
328,676
Total . . . . . . . . . . . . . . . . . . . . . . . . .
2,051,321
($)
25.71
10.21
(c)
Number of Securities
Remaining Available for
Future Issuance Under
Equity Compensation Plans
(Excluding Securities
Reflected in Column (a))
(#)
4,301,195
599,034
4,900,229
(1) Comprised of the Exterran Holdings, Inc. 2007 Stock Incentive Plan and the Exterran
Holdings, Inc. Employee Stock Purchase Plan. In addition to the outstanding options, as of
December 31, 2012 there were 269,796 restricted stock units, payable in common stock upon
vesting, outstanding under the 2007 Stock Incentive Plan.
(2) Comprised of the Exterran Holdings, Inc. Directors’ Stock and Deferral Plan and the 2011
Employment Inducement Long-Term Incentive Plan.
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The table above does not include information with respect to equity plans we assumed from
Hanover or Universal (the ‘‘Legacy Plans’’). No additional grants may be made under the Legacy Plans.
The following equity grants are outstanding under Legacy Plans that were approved by security
holders:
Plan Category
Hanover Compressor Company 2003 Stock Incentive Plan . . .
Universal Compression Holdings, Inc. Incentive Stock Option
Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Number of Shares
Reserved for Issuance Weighted-
Average
Exercise
Price
($)
Upon the Exercise
of Outstanding
Stock Options
(#)
Shares
Available
for Future
Grants
(#)
56,026
36.15
None
476,686
42.25
None
Item 13. Certain Relationships and Related Transactions and Director Independence
The information required in Part III, Item 13 of this report is incorporated by reference to the
sections entitled ‘‘Certain Relationships and Related Transactions’’ and ‘‘Information Regarding
Corporate Governance, the Board of Directors and Committees of the Board—Director Independence’’
in our definitive proxy statement, to be filed with the SEC within 120 days of the end of our fiscal year.
Item 14. Principal Accountant Fees and Services
The information required in Part III, Item 14 of this report is incorporated by reference to the
section entitled ‘‘Ratification of Appointment of Independent Registered Public Accounting Firm’’ in
our definitive proxy statement, to be filed with the SEC within 120 days of the end of our fiscal year.
Item 15. Exhibits and Financial Statement Schedules
(a) Documents filed as a part of this report.
PART IV
1. Financial Statements. The following financial statements are filed as a part of this report.
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-1
Consolidated Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-2
Consolidated Statements of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-3
Consolidated Statements of Comprehensive Income (Loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-4
Consolidated Statements of Stockholders’ Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-5
Consolidated Statements of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-6
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-7
2. Financial Statement Schedule
Schedule II—Valuation and Qualifying Accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
S-1
All other schedules have been omitted because they are not required under the relevant
instructions.
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3. Exhibits
Exhibit No.
2.1
2.2
2.3
3.1
3.2
4.1
4.2
4.3
4.4
4.5
Description
Contribution, Conveyance and Assumption Agreement, dated May 23, 2011, by and among
Exterran Holdings, Inc., Exterran Energy Corp., Exterran General Holdings LLC, Exterran
Energy Solutions, L.P., EES Leasing LLC, EXH GP LP LLC, Exterran GP LLC, EXH
MLP LP LLC, Exterran General Partner, L.P., EXLP Operating LLC, EXLP Leasing LLC
and Exterran Partners, L.P., incorporated by reference to Exhibit 2.1 of the Registrant’s
Current Report on Form 8-K filed on May 24, 2011
Contribution, Conveyance and Assumption Agreement, dated February 22, 2012, by and
among Exterran Holdings, Inc., Exterran Energy Corp., Exterran General Holdings LLC,
Exterran Energy Solutions, L.P., EES Leasing LLC, EXH GP LP LLC, Exterran GP LLC,
EXH MLP LP LLC, Exterran General Partner, L.P., EXLP Operating LLC, EXLP
Leasing LLC and Exterran Partners, L.P., incorporated by reference to Exhibit 2.1 to the
Registrant’s Current Report on Form 8-K filed on February 24, 2012
Asset Transfer Contract, dated August 7, 2012, between Exterran Venezuela, C.A. and
PDVSA Gas, S.A., incorporated by reference to Exhibit 2.1 to the Registrant’s Current
Report on Form 8-K filed on August 13, 2012
Restated Certificate of Incorporation of Exterran Holdings, Inc., incorporated by reference
to Exhibit 3.1 of the Registrant’s Current Report on Form 8-K filed on August 20, 2007
Second Amended and Restated Bylaws of Exterran Holdings, Inc., incorporated by
reference to Exhibit 3.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter
ended September 30, 2008
Eighth Supplemental Indenture, dated August 20, 2007, by and between Hanover
Compressor Company, Exterran Holdings, Inc., and U.S. Bank National Association, as
Trustee, for the 4.75% Convertible Senior Notes due 2014, incorporated by reference to
Exhibit 10.15 of the Registrant’s Current Report on Form 8-K filed on August 23, 2007
Ninth Supplemental Indenture, dated as of June 27, 2012, by and among Exterran
Holdings, Inc., Exterran Energy LLC and U.S. Bank National Association, as trustee, for
the 4.75% Convertible Senior Notes due 2014, incorporated by reference to Exhibit 4.1 to
the Registrant’s Current Report on Form 8-K filed on July 2, 2012
Indenture, dated as of June 10, 2009, between Exterran Holdings, Inc. and Wells Fargo
Bank, National Association, as trustee, incorporated by reference to Exhibit 4.1 of the
Registrant’s Current Report on Form 8-K filed on June 16, 2009
Supplemental Indenture, dated as of June 10, 2009, between Exterran Holdings, Inc. and
Wells Fargo Bank, National Association, as trustee, incorporated by reference to
Exhibit 4.2 of the Registrant’s Current Report on Form 8-K filed on June 16, 2009
Indenture, dated as of November 23, 2010, by and among Exterran Holdings, Inc., the
Guarantors named therein and Wells Fargo Bank, National Association, incorporated by
reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on
November 24, 2010
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Exhibit No.
10.1
Description
Senior Secured Credit Agreement, dated as of July 8, 2011, by and among Exterran
Holdings, Inc., as Borrower, Wells Fargo Bank, National Association, as Administrative
Agent, BNP Paribas, Credit Agricole Corporate and Investment Bank, Royal Bank of
Canada and The Royal Bank of Scotland plc, as Co-Syndication Agents, and the other
lenders signatory thereto, incorporated by reference to Exhibit 10.1 to the Registrant’s
Current Report on Form 8-K filed on July 14, 2011 (portions of this exhibit have been
omitted by redacting a portion of the text (indicated by asterisks in the text) and filed
separately with the Securities and Exchange Commission pursuant to a request for
confidential treatment)
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
Guaranty Agreement, dated as of July 8, 2011, made by EES Leasing LLC, EXH GP
LP LLC, EXH MLP LP LLC and Exterran Energy Solutions, L.P. in favor of Wells Fargo
Bank, National Association, as Administrative Agent, incorporated by reference to
Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on July 14, 2011
Collateral Agreement, dated as of July 8, 2011, made by Exterran Holdings, Inc., EES
Leasing LLC, EXH GP LP LLC, EXH MLP LP LLC and Exterran Energy Solutions, L.P.
in favor of Wells Fargo Bank, National Association, as Administrative Agent, incorporated
by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on
July 14, 2011
Pledge Agreement, dated as of July 8, 2011, made by Exterran Holdings, Inc., EES
GP, L.P., Enterra Compression Investment Company, EXH GP LP LLC, EXH MLP
LP LLC, Exterran Energy Corp., Exterran Energy Solutions, L.P., Exterran General
Holdings LLC, Exterran HL LLC, Exterran Holdings HL LLC, Hanover Asia, Inc.,
Universal Compression International, Inc. and Universal Compression Services LLC in
favor of Wells Fargo Bank, National Association, as Administrative Agent, incorporated by
reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on July 14,
2011
Call Option Transaction Confirmation, dated June 4, 2009, between Exterran Holdings, Inc.
and J.P. Morgan Chase Bank, National Association, London Branch, as dealer,
incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K
filed on June 10, 2009
Call Option Transaction Confirmation, dated June 4, 2009, between Exterran Holdings, Inc.
and Bank of America, N.A., as dealer, incorporated by reference to Exhibit 10.2 of the
Registrant’s Current Report on Form 8-K filed on June 10, 2009
Call Option Transaction Confirmation, dated June 4, 2009, between Exterran Holdings, Inc.
and Wachovia Bank, National Association, as dealer, incorporated by reference to
Exhibit 10.3 of the Registrant’s Current Report on Form 8-K filed on June 10, 2009
Call Option Transaction Confirmation, dated June 4, 2009, between Exterran Holdings, Inc.
and Credit Suisse International, as dealer, incorporated by reference to Exhibit 10.4 of the
Registrant’s Current Report on Form 8-K filed on June 10, 2009
Warrants Confirmation, dated June 4, 2009, between Exterran Holdings, Inc. and
J.P. Morgan Chase Bank, National Association, London Branch, as dealer, incorporated by
reference to Exhibit 10.5 of the Registrant’s Current Report on Form 8-K filed on June 10,
2009
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Exhibit No.
10.10
10.11
10.12
10.13
10.14
10.15
10.16
10.17
Description
Warrants Confirmation, dated June 4, 2009, between Exterran Holdings, Inc. and Bank of
America, N.A., as dealer, incorporated by reference to Exhibit 10.6 of the Registrant’s
Current Report on Form 8-K filed on June 10, 2009
Warrants Confirmation, dated June 4, 2009, between Exterran Holdings, Inc. and Wachovia
Bank, National Association, as dealer, incorporated by reference to Exhibit 10.7 of the
Registrant’s Current Report on Form 8-K filed on June 10, 2009
Warrants Confirmation, dated June 4, 2009, between Exterran Holdings, Inc. and Credit
Suisse International, as dealer, incorporated by reference to Exhibit 10.8 of the Registrant’s
Current Report on Form 8-K filed on June 10, 2009
Amended and Restated Senior Secured Credit Agreement, dated as of November 3, 2010,
by and among EXLP Operating LLC, as Borrower, Exterran Partners, L.P., as Guarantor,
Wells Fargo Bank, National Association, as Administrative Agent, Bank of America, N.A.
and JPMorgan Chase Bank, N.A., as Co-Syndication Agents, Barclays Bank plc and The
Royal Bank of Scotland plc, as Co-Documentation Agents, and the lenders signatory
thereto, incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on
Form 8-K filed on November 9, 2010
Amended and Restated Guaranty Agreement, dated as of November 3, 2010, made by
Exterran Partners, L.P. and EXLP Leasing LLC in favor of Wells Fargo Bank, National
Association, as Administrative Agent, incorporated by reference to Exhibit 10.2 to the
Registrant’s Current Report on Form 8-K filed on November 9, 2010
Amended and Restated Collateral Agreement, dated as of November 3, 2010, made by
EXLP Operating LLC, Exterran Partners, L.P. and EXLP Leasing LLC in favor of Wells
Fargo Bank, National Association, as Administrative Agent, incorporated by reference to
Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on November 9, 2010
Third Amended and Restated Omnibus Agreement, dated June 10, 2011, by and among
Exterran Holdings, Inc., Exterran Energy Solutions, L.P., Exterran GP LLC, Exterran
General Partner, L.P., EXLP Operating LLC and Exterran Partners, L.P., incorporated by
reference to Exhibit 10.1 of the Registrant’s Quarterly Report on Form 10-Q for the
quarter ended June 30, 2011 (portions of this exhibit have been omitted by redacting a
portion of the text (indicated by asterisks in the text) and filed separately with the
Securities and Exchange Commission pursuant to a request for confidential treatment)
First Amendment to Third Amended and Restated Omnibus Agreement, dated March 8,
2012, by and among Exterran Holdings, Inc., Exterran Energy Solutions, L.P.,
Exterran GP LLC, Exterran General Partner, L.P., EXLP Operating LLC and Exterran
Partners, L.P. (portions of this exhibit have been omitted by redacting a portion of the text
(indicated by asterisks in the text) and filed separately with the Securities and Exchange
Commission pursuant to a request for confidential treatment), incorporated by reference to
Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended
March 31, 2012
10.18
10.19†
Office Lease Agreement by and between RFP Lincoln Greenspoint, LLC and Exterran
Energy Solutions, L.P., incorporated by reference to Exhibit 10.1 of the Registrant’s
Current Report on Form 8-K filed on August 30, 2007
Exterran Holdings, Inc. Amended and Restated 2007 Stock Incentive Plan, incorporated by
reference to Annex B to the Registrant’s Definitive Proxy Statement on Schedule 14A filed
on March 26, 2009
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Exhibit No.
10.20†
10.21†
10.22†
10.23†
10.24†
10.25†
10.26†
10.27†
10.28†
10.29†
10.30†
10.31†
10.32†
10.33†
10.34†
Description
Amendment No. 1 to Exterran Holdings, Inc. Amended and Restated 2007 Stock Incentive
Plan, incorporated by reference to Annex A to the Registrant’s Definitive Proxy Statement
on Schedule 14A filed on March 26, 2009
Amendment No. 2 to Exterran Holdings, Inc. Amended and Restated 2007 Stock Incentive
Plan, incorporated by reference to Exhibit 10.10 to the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended March 31, 2009
Amendment No. 3 to the Exterran Holdings, Inc. Amended and Restated 2007 Stock
Incentive Plan, incorporated by reference to Annex A to the Registrant’s Definitive Proxy
Statement on Schedule 14A filed on March 29, 2010
Amendment No. 4 to the Exterran Holdings, Inc. Amended and Restated 2007 Stock
Incentive Plan, incorporated by reference to Annex A to the Registrant’s Definitive Proxy
Statement on Schedule 14A, filed March 29, 2011
Exterran Holdings, Inc. 2011 Employment Inducement Long-Term Equity Plan,
incorporated by reference to Exhibit 4.1 to the Registrant’s Registration Statement on
Form S-8, filed November 4, 2011
Exterran Holdings, Inc. Directors’ Stock and Deferral Plan, incorporated by reference to
Exhibit 10.16 of the Registrant’s Current Report on Form 8-K filed on August 23, 2007
First Amendment to Exterran Holdings, Inc. Directors’ Stock and Deferral Plan,
incorporated by reference to Exhibit 10.22 of the Registrant’s Annual Report on
Form 10-K for the year ended December 31, 2008
Exterran Holdings, Inc. Employee Stock Purchase Plan, incorporated by reference to
Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on August 23, 2007
Amendment No. 1 to the Exterran Holdings, Inc. Employee Stock Purchase Plan,
incorporated by reference to Annex D to the Registrant’s Definitive Proxy Statement on
Schedule 14A, filed March 29, 2011
Amendment No. 2 to the Exterran Holdings, Inc. Employee Stock Purchase Plan,
incorporated by reference to Annex C to the Registrant’s Definitive Proxy Statement on
Schedule 14A, filed March 29, 2011
Exterran Holdings, Inc. Deferred Compensation Plan, incorporated by reference to
Exhibit 10.29 of the Registrant’s Annual Report on Form 10-K for the year ended
December 31, 2007
Exterran Employees’ Supplemental Savings Plan, incorporated by reference to
Exhibit 10.30 of the Registrant’s Annual Report on Form 10-K for the year ended
December 31, 2007
First Amendment to Universal Compression, Inc. 401(k) Retirement and Savings Plan,
incorporated by reference to Exhibit 10.2 of Universal Compression Holdings, Inc.’s
Current Report on Form 8-K filed on August 3, 2007
Form of Exterran Holdings, Inc. Award Notice for Time-Vested Incentive Stock Option,
incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended March 31, 2009
Form of Exterran Holdings, Inc. Award Notice for Time-Vested Non-Qualified Stock
Option, incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended March 31, 2009
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Exhibit No.
10.35†
10.36†
10.37†
10.38†
10.39†
10.40†
10.41†
10.42†
10.43†
10.44†
10.45†
10.46†
10.47†
10.48†
Description
Form of Exterran Holdings, Inc. Award Notice for Time-Vested Restricted Stock,
incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended March 31, 2009
Form of Exterran Holdings, Inc. Award Notice for Time-Vested Restricted Stock for
Director, incorporated by reference to Exhibit 10.4 to the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended March 31, 2009
Form of Exterran Holdings, Inc. Award Notice for Time-Vested Stock-Settled Restricted
Stock Units, incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report
on Form 10-Q for the quarter ended March 31, 2009
Form of Exterran Holdings, Inc. Award Notice for Time-Vested Stock Option for Officers,
incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended March 31, 2010
Form of Exterran Holdings, Inc. Award Notice for Time-Vested Non-Qualified Stock
Option, incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended March 31, 2010
Form of Exterran Holdings, Inc. Award Notice for Time-Vested Restricted Stock,
incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended March 31, 2010
Form of Exterran Holdings, Inc. Award Notice for Time-Vested Restricted Stock
(Directors), incorporated by reference to Exhibit 10.4 to the Registrant’s Quarterly Report
on Form 10-Q for the quarter ended March 31, 2010
Form of Exterran Holdings, Inc. Award Notice for Time-Vested Stock-Settled Restricted
Stock Units, incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report
on Form 10-Q for the quarter ended March 31, 2010
Form of Exterran Holdings, Inc. Award Notice for Time-Vested Cash-Settled Restricted
Stock Units, incorporated by reference to Exhibit 10.6 to the Registrant’s Quarterly Report
on Form 10-Q for the quarter ended March 31, 2010
Form of Exterran Holdings, Inc. Award Notice for Performance Shares, incorporated by
reference to Exhibit 10.7 to the Registrant’s Quarterly Report on Form 10-Q for the
quarter ended March 31, 2010
Form of Exterran Holdings, Inc. Award Notice for Time-Vested Stock Option for Officers,
incorporated by reference to Exhibit 10.63 to the Registrant’s Annual Report on
Form 10-K for the year ended December 31, 2010
Form of Exterran Holdings, Inc. Award Notice for Time-Vested Non-Qualified Stock
Option, incorporated by reference to Exhibit 10.64 to the Registrant’s Annual Report on
Form 10-K for the year ended December 31, 2010
Form of Exterran Holdings, Inc. Award Notice for Performance Shares, incorporated by
reference to Exhibit 10.65 to the Registrant’s Annual Report on Form 10-K for the year
ended December 31, 2010
Form of Exterran Holdings, Inc. Award Notice for Time-Vested Restricted Stock,
incorporated by reference to Exhibit 10.66 to the Registrant’s Annual Report on
Form 10-K for the year ended December 31, 2010
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Exhibit No.
10.49†
10.50†
10.51†
10.52†
10.53†
10.54†
10.55†
10.56†
10.57†
Description
Form of Exterran Holdings, Inc. Award Notice for Time-Vested Restricted Stock
(Directors) , incorporated by reference to Exhibit 10.67 to the Registrant’s Annual Report
on Form 10-K for the year ended December 31, 2010
Form of Exterran Holdings, Inc. Award Notice for Time-Vested Stock-Settled Restricted
Stock Units, incorporated by reference to Exhibit 10.68 to the Registrant’s Annual Report
on Form 10-K for the year ended December 31, 2010
Form of Exterran Holdings, Inc. Award Notice for Time-Vested Cash-Settled Restricted
Stock Units, incorporated by reference to Exhibit 10.69 to the Registrant’s Annual Report
on Form 10-K for the year ended December 31, 2010
Form of Exterran Holdings, Inc. Award Notice for Time-Vested Restricted Stock under the
2011 Employment Inducement Long-Term Equity Plan, incorporated by reference to
Exhibit 10.54 to the Registrant’s Annual Report on Form 10-K for the year ended
December 31, 2011
Form of Exterran Holdings, Inc. Award Notice for Time-Vested Non-qualified Stock
Option under the 2011 Employment Inducement Long-Term Equity Plan, incorporated by
reference to Exhibit 10.55 to the Registrant’s Annual Report on Form 10-K for the year
ended December 31, 2011
Form of Exterran Holdings, Inc. Award Notice and Agreement for Performance Units,
incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended March 31, 2012
Form of Indemnification Agreement, incorporated by reference to Exhibit 10.2 of the
Registrant’s Current Report on Form 8-K filed on August 23, 2007
Form of Exterran Holdings, Inc. Change of Control Agreement, incorporated by reference
to Exhibit 10.19 of the Registrant’s Current Report on Form 8-K filed on August 23, 2007
Form of First Amendment to Exterran Holdings, Inc. Change of Control Agreement,
incorporated by reference to Exhibit 10.2 of the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended September 30, 2008
10.58†
Form of Second Amendment to Exterran Holdings, Inc. Change of Control Agreement
10.59†
10.60†
10.61†
10.62†
10.63†
Change of Control Agreement, effective December 12, 2011, between Exterran
Holdings, Inc. and D. Bradley Childers
Change of Control Agreement, effective December 12, 2011, between Exterran
Holdings, Inc. and William M. Austin
Form of First Amendment to Exterran Holdings, Inc. Change of Control Agreement
(Messrs. Childers and Austin)
Separation Agreement between Exterran Holdings, Inc. and Ernie L. Danner, dated
August 3, 2011, incorporated by reference to Exhibit 10.1 to the Registrant’s Current
Report on Form 8-K filed on September 4, 2011
Form of Exterran Holdings, Inc. Severance Benefit Agreement, incorporated by reference
to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on September 16,
2011
10.64†
Severance Benefit Agreement, effective December 12, 2011, between Exterran
Holdings, Inc. and William M. Austin
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Exhibit No.
Description
10.65†
Offer Letter, dated December 6, 2011, to D. Bradley Childers
10.66†
Offer Letter, dated December 6, 2011, to William M. Austin
10.67†
10.68†
10.69†
Letter agreement, dated January 28, 2012, between Exterran Holdings, Inc. and J. Michael
Anderson, incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report
on Form 10-Q for the quarter ended March 31, 2012
First Amendment to Severance Benefit Agreement, dated December 12, 2011, between
Exterran Holdings, Inc. and J. Michael Anderson, incorporated by reference to Exhibit 10.4
to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012
Second Amendment to Severance Benefit Agreement, dated January 28, 2012, between
Exterran Holdings, Inc. and J. Michael Anderson, incorporated by reference to Exhibit 10.5
to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012
21.1*
List of Subsidiaries
23.1*
Consent of Deloitte & Touche LLP
31.1*
31.2*
Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002
Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002
32.1** Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2** Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.1*** Interactive data files pursuant to Rule 405 of Regulation S-T
† Management contract or compensatory plan or arrangement.
*
Filed herewith.
** Furnished, not filed.
*** Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part
of a registration statement or prospectus for purposes of sections 11 and 12 of the Securities Act
of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934
and otherwise are not subject to any liability under those sections.
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2 C Cs: 49612
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
Exterran Holdings, Inc.
/s/ D. BRADLEY CHILDERS
Name: D. Bradley Childers
Title: President and Chief Executive Officer
Date: February 26, 2013
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POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below
constitutes and appoints D. Bradley Childers, William M. Austin, Kenneth R. Bickett and Donald C.
Wayne, and each of them, his true and lawful attorneys-in-fact and agents, with full power of
substitution and resubstitution for him and in his name, place and stead, in any and all capacities, to
sign any and all amendments to this Report, and to file the same, with all exhibits thereto, and other
documents in connection therewith, with the Securities and Exchange Commission granting unto said
attorneys-in-fact and agents full power and authority to do and perform each and every act and thing
requisite and necessary to be done as fully to all said attorneys-in-fact and agents, or any of them, may
lawfully do or cause to be done by virtue thereof.
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 and in the capacities indicated on
February 26, 2013.
Signature
/s/ D. BRADLEY CHILDERS
D. Bradley Childers
/s/ WILLIAM M. AUSTIN
William M. Austin
/s/ KENNETH R. BICKETT
Kenneth R. Bickett
/s/ URIEL E. DUTTON
Uriel E. Dutton
/s/ GORDON T. HALL
Gordon T. Hall
/s/ J.W.G. HONEYBOURNE
J.W.G. Honeybourne
/s/ MARK A. MCCOLLUM
Mark A. McCollum
/s/ WILLIAM C. PATE
William C. Pate
/s/ STEPHEN M. PAZUK
Stephen M. Pazuk
/s/ CHRISTOPHER T. SEAVER
Christopher T. Seaver
/s/ MARK R. SOTIR
Mark R. Sotir
Title
President and Chief Executive Officer
(Principal Executive Officer)
Executive Vice President and Chief Financial
Officer
(Principal Financial Officer)
Vice President and Controller (Principal
Accounting Officer)
Director
Director
Director
Director
Director
Director
Director
Director
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Exterran Holdings, Inc.
Houston, Texas
We have audited the accompanying consolidated balance sheets of Exterran Holdings, Inc. and
subsidiaries (the ‘‘Company’’) as of December 31, 2012 and 2011, and the related consolidated
statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of
the three years in the period ended December 31, 2012. Our audits also included the financial
statement schedule listed in the Index at Item 15. These financial statements and financial statement
schedule are the responsibility of the Company’s management. Our responsibility is to express an
opinion on these financial statements and financial statement schedule 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, such consolidated financial statements present fairly, in all material respects, the
financial position of the Company as of December 31, 2012 and 2011, and the results of their
operations and their cash flows for each of the three years in the period ended December 31, 2012, in
conformity with accounting principles generally accepted in the United States of America. Also, in our
opinion, such financial statement schedule when considered in relation to the basic consolidated
financial statements taken as a whole, presents fairly, in all material respects, the information set forth
therein.
We have also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the Company’s internal control over financial reporting as of
December 31, 2012, based on the criteria established in Internal Control—Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated
February 26, 2013 expressed an unqualified opinion on the Company’s internal control over financial
reporting.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 26, 2013
F-1
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EXTERRAN HOLDINGS, INC.
CONSOLIDATED BALANCE SHEETS
(In thousands, except par value and share amounts)
December 31,
2012
2011
Current assets:
ASSETS
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restricted cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable, net of allowance of $15,052 and $11,270, respectively . . . . . . .
Inventory, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Costs and estimated earnings in excess of billings on uncompleted contracts . . . . . .
Current deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current assets associated with discontinued operations . . . . . . . . . . . . . . . . . . . . .
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, plant and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intangible and other assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . .
Long-term assets associated with discontinued operations
$
34,601
1,283
451,547
387,710
159,098
88,508
93,475
21,746
1,237,968
2,842,031
174,848
—
$
21,903
1,121
448,998
342,095
122,214
37,401
111,531
38,664
1,123,927
2,934,664
222,851
79,220
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 4,254,847
$ 4,360,662
Current liabilities:
LIABILITIES AND EQUITY
Accounts payable, trade . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . .
Billings on uncompleted contracts in excess of costs and estimated earnings
Current liabilities associated with discontinued operations . . . . . . . . . . . . . . . . . . .
$
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term liabilities associated with discontinued operations . . . . . . . . . . . . . . . . . .
232,165
271,321
95,230
164,251
11,572
774,539
1,564,923
91,148
120,934
1,044
$
210,812
275,130
83,836
83,961
16,142
669,881
1,773,039
98,165
124,847
14,688
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,552,588
2,680,620
Commitments and contingencies (Note 20)
Equity:
Preferred stock, $0.01 par value per share; 50,000,000 shares authorized; zero issued
Common stock, $0.01 par value per share; 250,000,000 shares authorized; 71,291,230
and 70,407,010 shares issued, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated other comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated deficit
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Treasury stock—6,376,426 and 6,143,589 common shares, at cost, respectively . . . . .
Total Exterran stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncontrolling interest
—
—
713
3,710,758
23,909
(2,047,408)
(209,359)
1,478,613
223,646
704
3,645,332
6,059
(2,007,922)
(206,937)
1,437,236
242,806
Total equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,702,259
1,680,042
Total liabilities and equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 4,254,847
$ 4,360,662
The accompanying notes are an integral part of these consolidated financial statements.
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EXTERRAN HOLDINGS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
Years Ended December 31,
2012
2011
2010
Revenues:
North America contract operations . . . . . . . . . . . . . . . . . . . . . . . . . .
International contract operations . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Aftermarket services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fabrication . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 605,367
463,957
385,861
1,348,417
$ 588,034
445,059
371,327
1,225,459
$ 592,055
465,144
293,757
1,066,227
Costs and expenses:
Cost of sales (excluding depreciation and amortization expense):
North America contract operations . . . . . . . . . . . . . . . . . . . . . . . . .
International contract operations . . . . . . . . . . . . . . . . . . . . . . . . . .
Aftermarket services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fabrication . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selling, general and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-lived asset impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restructuring charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity in (income) loss of non-consolidated affiliates . . . . . . . . . . . . . .
Other (income) expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss before income taxes
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefit from income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) from discontinued operations, net of tax . . . . . . . . . . . . . .
2,803,602
2,629,879
2,417,183
289,244
184,608
303,590
1,191,937
376,359
350,847
183,445
6,636
—
134,376
(51,483)
430
303,050
184,405
311,760
1,102,237
352,780
356,972
6,068
11,594
196,807
149,473
471
(5,620)
291,624
175,357
248,392
904,722
351,998
392,153
143,874
—
—
136,149
609
(11,413)
2,969,989
2,969,997
2,633,465
(166,387)
(62,375)
(104,012)
66,843
(340,118)
(10,605)
(329,513)
(10,105)
(216,282)
(62,302)
(153,980)
40,739
Net loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(37,169)
(339,618)
(113,241)
Less: Net (income) loss attributable to the noncontrolling interest . . . . .
(2,317)
(990)
11,416
Net loss attributable to Exterran stockholders . . . . . . . . . . . . . . . . . . . . .
$ (39,486) $ (340,608) $ (101,825)
Basic income (loss) per common share:
Loss from continuing operations attributable to Exterran stockholders . .
Income (loss) from discontinued operations attributable to Exterran
stockholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net loss attributable to Exterran stockholders . . . . . . . . . . . . . . . . .
Diluted income (loss) per common share:
Loss from continuing operations attributable to Exterran stockholders . .
Income (loss) from discontinued operations attributable to Exterran
$
$
$
(1.68) $
(5.28) $
(2.30)
1.06
(0.16)
0.66
(0.62) $
(5.44) $
(1.64)
(1.68) $
(5.28) $
(2.30)
stockholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.06
(0.16)
0.66
Net loss attributable to Exterran stockholders . . . . . . . . . . . . . . . . .
$
(0.62) $
(5.44) $
(1.64)
Weighted average common and equivalent shares outstanding:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
63,436
63,436
62,624
62,624
61,995
61,995
The accompanying notes are an integral part of these consolidated financial statements.
F-3
EXTERRAN HOLDINGS INC. 10-K
Proj: P30087HOU12 Job: 12ZDS78704 (12-30087-4)
Page Dim: 8.250(cid:1) X 10.750(cid:1) Copy Dim: 38. X 54.3
File: FG78704A.;6
MERRILL CORPORATION JBAKER// 4-MAR-13 11:35 DISK106:[12ZDS4.12ZDS78704]FI78704A.;4
mrll_1111.fmt Free: 3650DM/0D Foot: 0D/ 0D VJ RSeq: 1 Clr: 0
DISK024:[PAGER.PSTYLES]UNIVERSAL.BST;102
2 C Cs: 49397
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
EXTERRAN HOLDINGS, INC.
(In thousands)
Net loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other comprehensive income (loss), net of tax:
Derivative gain (loss), net of reclassifications to earnings . . . . . . .
Adjustments from sale of Partnership units . . . . . . . . . . . . . . . . .
Amortization of payments to terminate interest rate swaps . . . . . .
. . . . . . . . . . . . . . . . . . .
Foreign currency translation adjustment
Years Ended December 31,
2012
2011
2010
$(37,169) $(339,618) $(113,241)
5,879
360
6,947
3,762
(2,126)
1,184
20,267
3,343
22,668
8,797
—
2,006
(2,326)
8,477
Total other comprehensive income . . . . . . . . . . . . . . . . . . . . . .
16,948
Comprehensive loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(20,221)
(316,950)
(104,764)
Less: Comprehensive (income) loss attributable to the
noncontrolling interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(1,415)
2,626
9,712
Comprehensive loss attributable to Exterran stockholders . . . . . . . .
$(21,636) $(314,324) $ (95,052)
The accompanying notes are an integral part of these consolidated financial statements.
F-4
EXTERRAN HOLDINGS INC. 10-K
Proj: P30087HOU12 Job: 12ZDS78704 (12-30087-4)
Page Dim: 8.250(cid:1) X 10.750(cid:1) Copy Dim: 38. X 54.3
File: FI78704A.;4
MERRILL CORPORATION JBAKER// 4-MAR-13 11:35 DISK106:[12ZDS4.12ZDS78704]FK78704A.;9
mrll_1111.fmt Free: 625DM/0D Foot: 0D/ 0D VJ RSeq: 1 Clr: 0
DISK024:[PAGER.PSTYLES]UNIVERSAL.BST;102
2 C Cs: 2307
EXTERRAN HOLDINGS, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands, except share data)
Exterran Holding, Inc. Stockholders
Accumulated
Other
Common Stock
Shares
Amount
Additional Comprehensive
Paid-in
Capital
Income
(Loss)
Treasury Stock
Accumulated Noncontrolling
Shares
Amount
Deficit
Interest
Total
68,195,447
$682
$3,434,618
$(27,879)
(5,667,897) $(201,935) $(1,565,489)
(2,061)
(84,922)
$176,862
50,494
102,156
722,930
1
1
7
839
2,223
22,408
(895)
(88,268)
585
$1,816,859
(2,061)
840
2,224
23,000
(895)
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.
.
.
expense .
.
.
Balance at December 31, 2009 .
.
.
.
Treasury stock purchased .
.
Options exercised .
.
.
.
.
.
.
Shares issued in employee stock purchase plan .
Stock-based compensation, net of forfeitures .
.
.
Income tax benefit from stock-based compensation
.
.
Net proceeds from sale of Partnership units, net of
.
.
Cash distribution to noncontrolling unitholders of
.
.
.
.
the Partnership .
.
.
.
Other .
.
.
Comprehensive income (loss):
.
.
Net loss .
.
Derivative gain, net of reclassifications to
.
.
.
.
tax
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.
.
earnings and tax .
.
.
.
Amortization of payments to terminate interest
.
.
.
Foreign currency translation adjustment
rate swaps, net of tax .
.
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.
tax
expense .
.
.
Balance at December 31, 2010 .
.
.
.
Treasury stock purchased .
.
.
.
.
.
.
Options exercised .
.
Shares issued in employee stock purchase plan .
Stock-based compensation, net of forfeitures .
.
.
Income tax benefit from stock-based compensation
.
.
Net proceeds from sale of Partnership units, net of
.
.
Cash distribution to noncontrolling unitholders of
.
.
.
.
the Partnership .
.
.
.
Other .
.
.
Comprehensive income (loss):
.
earnings and tax .
Net income (loss) .
.
.
.
Derivative gain (loss), net of reclassifications to
.
.
.
.
Adjustments from sale of Partnership units
.
Amortization of payments to terminate interest
.
.
.
Foreign currency translation adjustment
rate swaps, net of tax .
.
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.
.
.
.
Balance at December 31, 2011 .
.
.
.
Treasury stock purchased .
.
Options exercised .
.
.
.
.
.
.
Shares issued in employee stock purchase plan .
Stock-based compensation, net of forfeitures .
.
.
Income tax benefit from stock-based compensation
.
.
Net proceeds from sale of Partnership units, net of
.
.
Cash distribution to noncontrolling unitholders of
.
.
expense .
tax
.
.
.
.
.
.
.
.
.
.
.
.
.
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.
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.
.
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.
.
.
.
.
.
.
.
.
.
.
the Partnership .
.
Comprehensive income (loss):
.
.
.
.
.
.
.
.
.
.
.
.
.
.
earnings and tax .
Net income (loss) .
.
.
Derivatives gain (loss), net of reclassifications to
.
.
.
Adjustments from sale of Partnership units
.
Amortization of payments to terminate interest
.
.
.
Foreign currency translation adjustment
rate swaps, net of tax .
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
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.
.
.
41,111
881
(12)
7,093
2,006
(2,326)
32,545
153,489
1,149,949
1
12
526
1,886
20,006
(1,092)
123,904
(190)
34,285
132,784
717,151
1
8
562
1,634
15,373
(1,345)
49,202
69,071,027
$691
$3,500,292
$(20,225)
(5,841,087) $(203,996) $(1,667,314)
(2,941)
(157,756)
$192,976
(144,746)
135
1,490
1,184
20,267
3,343
(3,616)
70,407,010
$704
$3,645,332
$ 6,059
(6,143,589) $(206,937) $(2,007,922)
(2,422)
(157,233)
$242,806
(75,604)
589
35,920
85,122
(57,084)
(57,084)
(39,486)
2,317
(37,169)
(902)
5,879
360
6,947
3,762
6,781
360
6,947
3,762
43,273
85,265
(18,030)
(2)
(18,030)
(14)
(101,825)
(11,416)
(113,241)
1,704
8,797
92,190
216,094
(39,870)
1
(39,870)
(189)
(340,608)
990
(339,618)
2,006
(2,326)
$1,802,424
(2,941)
526
1,887
20,153
(1,092)
(2,126)
1,184
20,267
3,343
$1,680,042
(2,422)
562
1,635
15,970
(1,345)
Balance at December 31, 2012 .
.
.
.
.
.
.
.
.
.
71,291,230
$713
$3,710,758
$ 23,909
(6,376,426) $(209,359) $(2,047,408)
$223,646
$1,702,259
The accompanying notes are an integral part of these consolidated financial statements.
F-5
EXTERRAN HOLDINGS INC. 10-K
Proj: P30087HOU12 Job: 12ZDS78704 (12-30087-4)
Page Dim: 8.250(cid:1) X 10.750(cid:1) Copy Dim: 38. X 54.3
File: FK78704A.;9
MERRILL CORPORATION JBAKER// 4-MAR-13 11:35 DISK106:[12ZDS4.12ZDS78704]FM78704A.;6
mrll_1111.fmt Free: 105DM/0D Foot: 0D/ 0D VJ RSeq: 1 Clr: 0
DISK024:[PAGER.PSTYLES]UNIVERSAL.BST;102
2 C Cs: 42172
EXTERRAN HOLDINGS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Cash flows from operating activities:
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Net loss
.
Adjustments:
.
.
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.
.
Depreciation and amortization .
.
.
.
Long-lived asset impairment
.
Goodwill impairment
.
.
.
.
Amortization of deferred financing cost .
.
(Income) loss from discontinued operations, net of tax .
.
.
.
Amortization of debt discount
.
.
.
Provision for doubtful accounts
.
Gain on sale of property, plant and equipment
.
.
Equity in (income) loss of non-consolidated affiliates .
Interest rate swaps .
.
.
.
.
Amortization of payments to terminate interest rate swaps .
.
(Gain) loss on remeasurement of intercompany balances .
.
. .
Stock-based compensation expense .
.
.
.
.
.
.
Deferred income tax provision .
Changes in assets and liabilities, net of acquisition:
.
.
.
.
.
.
.
.
. .
.
. .
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Accounts receivable and notes .
Inventory .
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.
Costs and estimated earnings versus billings on uncompleted contracts
.
Other current assets .
.
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.
Accounts payable and other liabilities
.
.
Deferred revenue .
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Other .
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Net cash provided by continuing operations .
.
Net cash provided by (used in) discontinued operations .
. .
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.
Net cash provided by operating activities
.
.
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.
.
. .
Cash flows from investing activities:
.
.
.
.
.
.
.
.
.
Capital expenditures .
.
.
Proceeds from sale of property, plant and equipment .
.
Cash paid for business acquisition .
.
.
Return of investments in non-consolidated affiliates .
.
.
.
(Increase) decrease in restricted cash .
.
.
Cash invested in non-consolidated affiliates
.
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Net cash used in continuing operations
.
Net cash provided by (used in) discontinued operations .
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.
Net cash used in investing activities
.
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.
Cash flows from financing activities:
.
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Proceeds from borrowings of long-term debt .
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Repayments of long-term debt .
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Payments for debt issuance costs .
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Net proceeds from the sale of Partnership units .
Proceeds from stock options exercised .
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Proceeds from stock issued pursuant to our employee stock purchase plan .
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Purchases of treasury stock .
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Stock-based compensation excess tax benefit .
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Distributions to noncontrolling partners in the Partnership .
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Net cash provided by (used in) financing activities .
Effect of exchange rate changes on cash and equivalents
Net increase (decrease) in cash and cash equivalents .
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Cash and cash equivalents at beginning of period .
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Cash and cash equivalents at end of period .
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Supplemental disclosure of cash flow information:
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Interest paid, net of capitalized amounts .
Income taxes paid, net
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Years Ended December 31,
2012
2011
2010
$
(37,169)
$ (339,618)
$ (113,241)
350,847
183,445
—
7,243
(66,843)
20,523
8,754
(4,688)
(51,483)
—
10,688
7,406
15,381
(93,884)
(10,298)
(34,926)
44,359
9,452
30,196
4,738
(5,870)
387,871
2,054
389,925
(428,731)
36,000
—
51,707
(162)
(224)
(341,410)
135,959
356,972
6,068
196,807
8,977
10,105
18,323
1,488
(8,063)
471
—
20,267
14,174
20,018
(50,211)
(53,289)
27,438
(21,601)
(16,350)
35,184
(78,846)
(36,597)
111,717
8,726
120,443
(272,185)
43,042
(3,000)
—
820
(471)
(231,794)
(7,390)
392,153
143,874
—
5,303
(40,739)
16,364
4,749
(5,500)
609
751
2,006
(6,255)
23,266
(124,168)
34,701
94,467
2,910
17,952
9,510
(88,385)
4,950
375,277
(8,964)
366,313
(231,607)
21,728
—
—
12,930
(609)
(197,558)
94,593
(205,451)
(239,184)
(102,965)
1,878,000
(2,106,639)
(1,011)
114,530
562
1,635
(2,422)
1,139
(57,084)
(171,290)
(486)
12,698
21,903
34,601
95,416
29,089
$
$
$
$
$
$
1,893,740
(2,036,171)
(8,823)
289,908
526
1,887
(2,941)
1,034
(39,870)
99,290
(3,007)
(22,458)
44,361
21,903
100,735
59,735
2,098,244
(2,478,397)
(12,034)
109,365
840
2,224
(2,061)
1,182
(18,030)
(298,667)
(1,872)
(37,191)
81,552
44,361
109,952
48,306
$
$
$
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The accompanying notes are an integral part of these consolidated financial statements.
F-6
EXTERRAN HOLDINGS INC. 10-K
Proj: P30087HOU12 Job: 12ZDS78704 (12-30087-4)
Page Dim: 8.250(cid:1) X 10.750(cid:1) Copy Dim: 38. X 54.3
File: FM78704A.;6
MERRILL CORPORATION JBAKER// 4-MAR-13 11:47 DISK106:[12ZDS4.12ZDS78704]FO78704A.;9
mrll_1111.fmt Free: 70D*/240D Foot: 0D/ 0D VJ RSeq: 1 Clr: 0
DISK024:[PAGER.PSTYLES]UNIVERSAL.BST;102
2 C Cs: 25333
EXTERRAN HOLDINGS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Background and Significant Accounting Policies
Exterran Holdings, Inc., together with its subsidiaries (‘‘we’’ or ‘‘Exterran’’), is a global market
leader in the full service natural gas compression business and a premier provider of operations,
maintenance, service and equipment for oil and natural gas production, processing and transportation
applications. Our global customer base consists of companies engaged in all aspects of the oil and
natural gas industry, including large integrated oil and natural gas companies, national oil and natural
gas companies, independent producers and natural gas processors, gatherers and pipelines. We operate
in three primary business lines: contract operations, fabrication and aftermarket services. In our
contract operations business line, we own a fleet of natural gas compression equipment and crude oil
and natural gas production and processing equipment that we utilize to provide operations services to
our customers. In our fabrication business line, we fabricate equipment for sale to our customers and
for use in our contract operations services. In addition, our fabrication business line provides
engineering, procurement and fabrication services primarily related to the manufacturing of critical
process equipment for refinery and petrochemical facilities, the fabrication of tank farms and the
fabrication of evaporators and brine heaters for desalination plants. We offer our customers, on either
a contract operations basis or a sale basis, the engineering, design, project management, procurement
and construction services necessary to incorporate our products into complete production, processing
and compression facilities, which we refer to as Integrated Projects. In our aftermarket services business
line, we sell parts and components and provide operations, maintenance, overhaul and reconfiguration
services to customers who own compression, production, processing, treating and other equipment.
We were incorporated in February 2007 as a wholly-owned subsidiary of Universal Compression
Holdings, Inc. (‘‘Universal’’). On August 20, 2007, in accordance with their merger agreement,
Universal and Hanover Compressor Company (‘‘Hanover’’) merged into our wholly-owned subsidiaries,
and we became the parent entity of Universal and Hanover. Immediately following the completion of
the merger, Universal merged with and into us.
Principles of Consolidation
The accompanying consolidated financial statements include Exterran and its wholly-owned and
majority-owned subsidiaries. All intercompany accounts and transactions have been eliminated in
consolidation. Investments in affiliated entities in which we own more than a 20% interest and do not
have a controlling interest are accounted for using the equity method.
For financial reporting purposes, we consolidate the financial statements of Exterran Partners, L.P.
(together with its subsidiaries, the ‘‘Partnership’’) with those of our own and reflect its operations in
our North America contract operations business segment. We control the Partnership through our
ownership of its general partner. Public ownership of the Partnership’s net assets and earnings is
presented as a component of noncontrolling interest in our consolidated financial statements. The
borrowings of the Partnership are presented as part of our consolidated debt. However, we do not have
any obligation for the payment of interest or repayment of borrowings incurred by the Partnership.
Use of Estimates in the Financial Statements
The preparation of financial statements in conformity with accounting principles generally accepted
in the United States of America (‘‘U.S.’’) (‘‘GAAP’’) requires management to make estimates and
assumptions that affect the reported amount of assets, liabilities, revenues and expenses, as well as the
disclosures of contingent assets and liabilities. Because of the inherent uncertainties in this process,
F-7
EXTERRAN HOLDINGS INC. 10-K
Proj: P30087HOU12 Job: 12ZDS78704 (12-30087-4)
Page Dim: 8.250(cid:1) X 10.750(cid:1) Copy Dim: 38. X 54.3
File: FO78704A.;9
MERRILL CORPORATION JBAKER// 4-MAR-13 11:47 DISK106:[12ZDS4.12ZDS78704]FO78704A.;9
mrll_1111.fmt Free: 50D*/240D Foot: 0D/ 0D VJ RSeq: 2 Clr: 0
DISK024:[PAGER.PSTYLES]UNIVERSAL.BST;102
2 C Cs: 11412
actual future results could differ from those expected at the reporting date. Management believes that
the estimates and assumptions used are reasonable.
Cash and Cash Equivalents
We consider all highly liquid investments purchased with an original maturity of three months or
less to be cash equivalents.
Restricted Cash
Restricted cash as of December 31, 2012 and 2011 consists of cash that contractually is not
available for immediate use. Restricted cash is presented separately from cash and cash equivalents in
the balance sheet and statement of cash flows.
Revenue Recognition
Revenue from contract operations is recorded when earned, which generally occurs monthly when
service is provided under our customer contracts. Aftermarket services revenue is recorded as products
are delivered and title is transferred or services are performed for the customer.
Fabrication revenue is recognized using the percentage-of-completion method when the applicable
criteria are met. We estimate percentage-of-completion for compressor and accessory fabrication on a
direct labor hour to total labor hour basis. Production and processing equipment fabrication
percentage-of-completion is estimated using the direct labor hour to total labor hour and the cost to
total cost basis. The duration of these projects is typically between three and 36 months. Fabrication
revenue is recognized using the completed contract method when the applicable criteria of the
percentage-of-completion method are not met. Fabrication revenue from a claim is recognized to the
extent that costs related to the claim have been incurred, when collection is probable and can be
reliably estimated.
Concentrations of Credit Risk
Financial instruments that potentially subject us to concentrations of credit risk consist of cash and
cash equivalents and accounts receivable. We believe that the credit risk in temporary cash investments
is limited because our cash is held in accounts with multiple financial institutions. Trade accounts are
due from companies of varying size engaged principally in oil and natural gas activities throughout the
world. We review the financial condition of customers prior to extending credit and generally do not
obtain collateral for trade receivables. Payment terms are on a short-term basis and in accordance with
industry practice. We consider this credit risk to be limited due to these companies’ financial resources,
the nature of products and services we provide and the terms of our contract operations customer
service agreements.
We maintain allowances for doubtful accounts for estimated losses resulting from our customers’
inability to make required payments. The determination of the collectibility of amounts due from our
customers requires us to use estimates and make judgments regarding future events and trends,
including monitoring our customers’ payment history and current creditworthiness to determine that
collectibility is reasonably assured, as well as consideration of the overall business climate in which our
customers operate. Inherently, these uncertainties require us to make judgments and estimates
regarding our customers’ ability to pay amounts due to us in order to determine the appropriate
amount of valuation allowances required for doubtful accounts. We review the adequacy of our
allowance for doubtful accounts quarterly. We determine the allowance needed based on historical
write-off experience and by evaluating significant balances aged greater than 90 days individually for
collectibility. Account balances are charged off against the allowance after all means of collection have
been exhausted and the potential for recovery is considered remote. During the years ended
F-8
EXTERRAN HOLDINGS INC. 10-K
Proj: P30087HOU12 Job: 12ZDS78704 (12-30087-4)
Page Dim: 8.250(cid:1) X 10.750(cid:1) Copy Dim: 38. X 54.3
File: FO78704A.;9
MERRILL CORPORATION JBAKER// 4-MAR-13 11:47 DISK106:[12ZDS4.12ZDS78704]FO78704A.;9
mrll_1111.fmt Free: 110D*/660D Foot: 0D/ 0D VJ RSeq: 3 Clr: 0
DISK024:[PAGER.PSTYLES]UNIVERSAL.BST;102
2 C Cs: 47592
December 31, 2012, 2011 and 2010, we recorded bad debt expense of $8.8 million, $1.5 million and
$4.7 million, respectively.
Inventory
Inventory consists of parts used for fabrication or maintenance of natural gas compression
equipment and facilities, processing and production equipment and also includes compression units and
production equipment that are held for sale. Inventory is stated at the lower of cost or market using
the average-cost method. A reserve is recorded against inventory balances for estimated obsolescence
based on specific identification and historical experience.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost and depreciated using the straight-line method
over their estimated useful lives as follows:
Compression equipment, facilities and other fleet assets . . . . . . . . . . . . . . . . . . . . . . .
Buildings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation, shop equipment and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3 to 30 years
20 to 35 years
3 to 12 years
Major improvements that extend the useful life of an asset are capitalized. Repairs and
maintenance are expensed as incurred. When property, plant and equipment is sold, retired or
otherwise disposed of, the gain or loss is recorded in other (income) expense, net. Interest is capitalized
during the construction period on equipment and facilities that are constructed for use in our
operations. The capitalized interest is included as part of the cost of the asset to which it relates and is
amortized over the asset’s estimated useful life.
Computer software
Certain costs related to the development or purchase of internal-use software are capitalized and
amortized over the estimated useful life of the software, which ranges from three to five years. Costs
related to the preliminary project stage and the post-implementation/operation stage of an internal-use
computer software development project are expensed as incurred.
Long-Lived Assets
We review for impairment of long-lived assets, including property, plant and equipment and
identifiable intangibles that are being amortized, whenever events or changes in circumstances indicate
that the carrying amount of an asset may not be recoverable. An impairment loss exists when estimated
undiscounted cash flows expected to result from the use of the asset and its eventual disposition are
less than its carrying amount. The impairment loss recognized represents the excess of the asset’s
carrying value as compared to its estimated fair value. Identifiable intangibles are amortized over the
assets’ estimated useful lives.
We hold investments in companies with operations in areas that relate to our business. We record
an investment impairment charge when we believe an investment has experienced a decline in value
that is other than temporary.
Deferred Revenue
Deferred revenue is primarily comprised of billings related to jobs where revenue is recognized on
the percentage-of-completion method that have not begun, milestone billings related to jobs where
revenue is recognized on the completed contract method and deferred revenue on contract operations
jobs.
F-9
EXTERRAN HOLDINGS INC. 10-K
Proj: P30087HOU12 Job: 12ZDS78704 (12-30087-4)
Page Dim: 8.250(cid:1) X 10.750(cid:1) Copy Dim: 38. X 54.3
File: FO78704A.;9
MERRILL CORPORATION JBAKER// 4-MAR-13 11:47 DISK106:[12ZDS4.12ZDS78704]FO78704A.;9
mrll_1111.fmt Free: 50D*/120D Foot: 0D/ 0D VJ RSeq: 4 Clr: 0
DISK024:[PAGER.PSTYLES]UNIVERSAL.BST;102
2 C Cs: 14901
Other (Income) Expense, Net
Other (income) expense, net, is primarily comprised of gains and losses from the remeasurement
of our international subsidiaries’ net assets exposed to changes in foreign currency rates and on the sale
of used assets.
Income Taxes
We account for income taxes under the asset and liability method, which requires the recognition
of deferred tax assets and liabilities for the expected future tax consequences of events that have been
included in the financial statements. Under this method, deferred tax assets and liabilities are
determined based on the differences between the financial statements and tax basis of assets and
liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.
The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the
period that includes the enactment date.
We record net deferred tax assets to the extent we believe these assets will more likely than not be
realized. In making such a determination, we consider all available positive and negative evidence,
including future reversals of existing taxable temporary differences, projected future taxable income,
tax-planning strategies and results of recent operations. In the event we were to determine that we
would be able to realize our deferred income tax assets in the future in excess of their net recorded
amount, we would make an adjustment to the deferred tax asset valuation allowance, which would
reduce the provision for income taxes.
We record uncertain tax positions in accordance with the accounting standard on income taxes on
the basis of a two-step process whereby (1) we determine whether it is more likely than not that the tax
positions will be sustained based on the technical merits of the position and (2) those tax positions that
meet the more-likely-than-not recognition threshold, we recognize the largest amount of tax benefit
that is greater than 50 percent likely to be realized upon ultimate settlement with the related tax
authority.
Foreign Currency Translation
The financial statements of subsidiaries outside the U.S., except those for which we have
determined that the U.S. dollar is the functional currency, are measured using the local currency as the
functional currency. Assets and liabilities of these subsidiaries are translated at the rates of exchange in
effect at the balance sheet date. Income and expense items are translated at average monthly rates of
exchange. The resulting gains and losses from the translation of accounts into U.S. dollars are included
in accumulated other comprehensive income (loss) on our consolidated balance sheets. For all
subsidiaries, gains and losses from remeasuring foreign currency accounts into the functional currency
are included in other (income) expense, net, on our consolidated statements of operations. We
recorded a foreign currency loss of $8.2 million and $16.5 million for the years ended December 31,
2012 and 2011, respectively, and a foreign currency gain of $4.9 million for the year ended
December 31, 2010. Included in our foreign currency (gain) loss was $7.4 million and $14.2 million of
non-cash losses from foreign currency exchange rate changes recorded on intercompany obligations for
the years ended December 31, 2012 and 2011, respectively, and $6.3 million of non-cash gains from
foreign currency exchange rate changes recorded on intercompany obligations for the year ended
December 31, 2010.
Hedging and Use of Derivative Instruments
We use derivative financial instruments to minimize the risks and/or costs associated with financial
activities by managing our exposure to interest rate fluctuations on a portion of our debt obligations.
We also use derivative financial instruments to minimize the risks caused by currency fluctuations in
F-10
EXTERRAN HOLDINGS INC. 10-K
Proj: P30087HOU12 Job: 12ZDS78704 (12-30087-4)
Page Dim: 8.250(cid:1) X 10.750(cid:1) Copy Dim: 38. X 54.3
File: FO78704A.;9
MERRILL CORPORATION JBAKER// 4-MAR-13 11:47 DISK106:[12ZDS4.12ZDS78704]FO78704A.;9
mrll_1111.fmt Free: 275DM/0D Foot: 0D/ 0D VJ RSeq: 5 Clr: 0
DISK024:[PAGER.PSTYLES]UNIVERSAL.BST;102
2 C Cs: 53912
certain foreign currencies. We do not use derivative financial instruments for trading or other
speculative purposes. We record interest rate swaps and foreign currency hedges on the balance sheet
as either derivative assets or derivative liabilities measured at their fair value. The fair value of our
derivatives is estimated using a combination of the market and income approach based on forward
LIBOR curves. Changes in the fair value of the derivatives designated as cash flow hedges are deferred
in accumulated other comprehensive income (loss), net of tax, to the extent the contracts are effective
as hedges until settlement of the underlying hedged transaction. To qualify for hedge accounting
treatment, we must formally document, designate and assess the effectiveness of the transactions. If the
necessary correlation ceases to exist or if the anticipated transaction becomes improbable, we would
discontinue hedge accounting and apply mark-to-market accounting. Amounts paid or received from
interest rate swap agreements are charged or credited to interest expense and matched with the cash
flows and interest expense of the debt being hedged, resulting in an adjustment to the effective interest
rate. Amounts paid or received from foreign currency derivatives designated as hedges are recorded
against revenue and matched with the revenue recognized on the related contract being hedged.
Correction of Misclassification in the Statement of Cash Flows
We received $289.9 million and $109.4 million of net proceeds from the sale of common units of
Exterran Partners, L.P. (together with its subsidiaries, the ‘‘Partnership’’) during the years ended
December 31, 2011 and 2010, respectively. These net proceeds were previously reported in our
consolidated statement of cash flows as cash flows from investing activities. We have subsequently
determined that the net proceeds from the sale of Partnership common units during the years ended
December 31, 2011 and 2010 should have been reported as cash flows from financing activities. This
correction had no impact on cash flows from operating activities. The impact of the reclassification on
the statement of cash flows for the years ended December 31, 2011 and 2010 is shown below (in
thousands):
Net Cash Provided By (Used In)
Years Ended December 31,
2011
2010
Investing
Activities
Financing
Activities
Investing
Activities
Financing
Activities
As previously reported . . . . . . . . . . . . . . . . . . . . . . . .
Increase (decrease) . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 50,724
(289,908)
$(190,618) $
289,908
6,400
(109,365)
$(408,032)
109,365
As corrected . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(239,184) $ 99,290
$(102,965) $(298,667)
Earnings (Loss) Attributable to Exterran Stockholders Per Common Share
Basic income (loss) attributable to Exterran stockholders per common share is computed by
dividing income (loss) attributable to Exterran common stockholders by the weighted average number
of shares outstanding for the period. Unvested share-based awards that contain nonforfeitable rights to
dividends or dividend equivalents, whether paid or unpaid, are participating securities and are included
in the computation of earnings (loss) per share following the two-class method. Therefore, restricted
share awards that include the right to vote and receive dividends are included in the computation of
basic and diluted earnings (loss) per share, unless their effect would be anti-dilutive.
Diluted income (loss) attributable to Exterran stockholders per common share is computed using
the weighted average number of shares outstanding adjusted for the incremental common stock
equivalents attributed to outstanding options and warrants to purchase common stock, restricted stock,
restricted stock units, stock to be issued pursuant to our employee stock purchase plan and convertible
senior notes, unless their effect would be anti-dilutive.
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The table below summarizes loss attributable to Exterran stockholders (in thousands):
Years Ended December 31,
2012
2011
2010
Loss from continuing operations attributable to Exterran
stockholders
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) from discontinued operations, net of tax . . . . . . . . .
$(106,329) $(330,503) $(142,564)
40,739
(10,105)
66,843
Net loss attributable to Exterran stockholders . . . . . . . . . . . . . . . .
$ (39,486) $(340,608) $(101,825)
There were no potential shares of common stock included in computing diluted income (loss) per
common share for the years ended December 31, 2012, 2011 and 2010, as the effect of their inclusion
would have been anti-dilutive.
The table below indicates the potential shares of common stock issuable that were excluded from
computing diluted income (loss) attributable to Exterran stockholders per common share as their
inclusion would have been anti-dilutive (in thousands):
Net dilutive potential common shares issuable:
On exercise of options where exercise price is greater than average market
value for the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
On exercise of options and vesting of restricted stock and restricted stock
Years Ended December 31,
2012
2011
2010
1,858
2,533
1,359
units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
On settlement of employee stock purchase plan shares . . . . . . . . . . . . . . .
On exercise of warrants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
On conversion of 4.25% convertible senior notes due 2014 . . . . . . . . . . . .
On conversion of 4.75% convertible senior notes due 2014 . . . . . . . . . . . .
1,466
9
12,426
15,334
3,114
675
23
12,426
15,334
3,114
735
14
12,426
15,334
3,114
Net dilutive potential common shares issuable . . . . . . . . . . . . . . . . . . . . . .
34,207
34,105
32,982
Comprehensive Income (Loss)
Components of comprehensive income (loss) are net income (loss) and all changes in equity during
a period except those resulting from transactions with owners. Our accumulated other comprehensive
income (loss) consists of foreign currency translation adjustments, changes in the fair value of
derivative financial instruments, net of tax, that are designated as cash flow hedges and to the extent
the hedge is effective and adjustments related to changes in our ownership of the Partnership. As a
result of the changes in the fair values of derivatives designated as hedges and the amortization of
interest rate swap terminations, we recorded an increase in accumulated other comprehensive income
(loss) of $13.7 million (net of tax of $7.4 million), $21.8 million (net of tax of $12.1 million) and
$9.1 million (net of tax of $5.6 million) for the years ended December 31, 2012, 2011 and 2010,
respectively.
Financial Instruments
Our financial instruments consist of cash, restricted cash, receivables, payables, interest rate swaps
and long-term debt. At December 31, 2012 and 2011, the estimated fair values of these financial
instruments approximated their carrying values as reflected in our consolidated balance sheets. The fair
value of our fixed rate debt has been estimated based on quoted market yields in inactive markets or
model derived calculations using market yields observed in active markets, which are Level 2 inputs.
The fair value of our floating rate debt has been estimated using a discounted cash flow analysis based
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on interest rates offered on loans with similar terms to borrowers of similar credit quality, which are
Level 3 inputs. See Note 12 for additional information regarding the fair value hierarchy. A summary
of the fair value and carrying value of our long-term debt as of December 31, 2012 and 2011 is shown
in the table below (in thousands):
December 31, 2012
December 31, 2011
Carrying
Amount
Fair Value
Carrying
Amount
Fair Value
Fixed rate debt . . . . . . . . . . . . . . . . . . . . . . . . . . .
Floating rate debt . . . . . . . . . . . . . . . . . . . . . . . . .
$ 814,423
750,500
$ 857,000
761,000
$ 794,039
979,000
$ 792,000
989,000
Total debt
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,564,923
$1,618,000
$1,773,039
$1,781,000
GAAP requires that all derivative instruments (including certain derivative instruments embedded
in other contracts) be recognized in the balance sheet at fair value, and that changes in such fair values
be recognized in earnings (loss) unless specific hedging criteria are met. Changes in the values of
derivatives that meet these hedging criteria will ultimately offset related earnings effects of the hedged
item pending recognition in earnings.
2. Discontinued Operations
In May 2009, the Venezuelan government enacted a law that reserves to the State of Venezuela
certain assets and services related to hydrocarbon activities, which included substantially all of our
assets and services in Venezuela. The law provides that the reserved activities are to be performed by
the State, by the State-owned oil company, Petroleos de Venezuela S.A. (‘‘PDVSA’’), or its affiliates, or
through mixed companies under the control of PDVSA or its affiliates. The law authorizes PDVSA or
its affiliates to take possession of the assets and take over control of those operations related to the
reserved activities as a step prior to the commencement of an expropriation process, and permits the
national executive of Venezuela to decree the total or partial expropriation of shares or assets of
companies performing those services.
In June 2009, PDVSA commenced taking possession of our assets and operations in a number of
our locations in Venezuela and by the end of the second quarter of 2009, PDVSA had assumed control
over substantially all of our assets and operations in Venezuela. The expropriation of our business in
Venezuela meets the criteria established for recognition as discontinued operations under accounting
standards for presentation of financial statements. Therefore, our Venezuela contract operations and
aftermarket services businesses are reflected as discontinued operations in our consolidated financial
statements.
In March 2010, our Spanish subsidiary filed a request for the institution of an arbitration
proceeding against Venezuela with the International Centre for Settlement of Investment Disputes
(‘‘ICSID’’) related to the seized assets and investments under the Agreement between Spain and
Venezuela for the Reciprocal Promotion and Protection of Investments and under Venezuelan law. The
arbitration hearing occurred in July 2012.
As a result of PDVSA taking possession of substantially all of our assets and operations in
Venezuela, we recorded asset impairments during the year ended December 31, 2009 totaling
$329.7 million ($379.7 million excluding insurance proceeds of $50 million). These charges primarily
related to receivables, inventory, fixed assets and goodwill, and are reflected in Income (loss) from
discontinued operations, net of tax. GAAP requires that our claim be accounted for as a gain
contingency with no benefit being recorded until resolved. Accordingly, we did not include any
compensation for our seized assets and operations from Venezuela in recording the loss on
expropriation.
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In August 2012, our Venezuelan subsidiary completed the sale of its previously nationalized assets
to PDVSA Gas, S.A. (‘‘PDVSA Gas’’) for a purchase price of approximately $441.7 million. We
received an initial payment of $176.7 million in cash at closing, of which we remitted $50.0 million to
the insurance company from which we collected $50.0 million in January 2010 under the terms of an
insurance policy we maintained for the risk of expropriation. In December 2012, we received an
installment payment of $16.8 million. The remaining principal amount due to us of approximately
$248 million is payable in quarterly cash installments through the third quarter of 2016. We have not
recognized amounts payable to us by PDVSA Gas as a receivable and will therefore recognize quarterly
payments received in the future as income from discontinued operations in the periods such payments
are received. The proceeds from the sale of assets are not subject to Venezuelan national taxes due to
an exemption allowed under the Venezuelan Reserve Law applicable to expropriation settlements. In
addition, and in connection with the sale, we and the Venezuelan government agreed to waive rights to
assert certain claims against each other. We therefore recorded a reduction in previously unrecognized
tax benefits, resulting in a $15.5 million benefit reflected in Income (loss) from discontinued operations,
net of tax, in our consolidated statements of operations during the year ended December 31, 2012.
In connection with the sale of these assets, we have agreed to suspend the arbitration proceeding
previously filed by our Spanish subsidiary against Venezuela pending payment in full by PDVSA Gas of
the purchase price for these nationalized assets.
In January 2010, the Venezuelan government announced a devaluation of the Venezuelan bolivar.
This devaluation resulted in a translation gain of approximately $12.2 million on the remeasurement of
our net liability position in Venezuela and is reflected in Other (income) loss, net in the table below for
the year ended December 31, 2010. The functional currency of our Venezuela subsidiary is the U.S.
dollar and we had more liabilities than assets denominated in bolivars in Venezuela at the time of the
devaluation. The exchange rate used to remeasure our net liabilities changed from 2.15 bolivars per
U.S. dollar at December 31, 2009 to 4.3 bolivars per U.S. dollar in January 2010.
Our loss (recovery) attributable to expropriation for the year ended December 31, 2010 includes a
benefit of $41.0 million from payments received from PDVSA and its affiliates as consideration for the
fixed assets for two projects. These payments relate to the recovery of the loss we recognized on the
value of the equipment for these projects in the second quarter of 2009.
In June 2012, we committed to a plan to sell our contract operations and aftermarket services
businesses in Canada as part of our continued emphasis on simplification and focus on our core
businesses. We expect this sale to be completed within the next twelve months. Our Canadian contract
operations and aftermarket services businesses are reflected as discontinued operations in our
consolidated financial statements. These operations were previously included in our North American
contract operations and aftermarket services business segments. In conjunction with the planned
disposition, we recorded impairments of long-lived assets, including intangible and other assets, and
inventory, that totaled $80.2 million during the year ended December 31, 2012. The impairment charges
are reflected in Income (loss) from discontinued operations, net of tax.
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The table below summarizes the operating results of the discontinued operations (in thousands):
2012
2011
2010
Venezuela Canada
Total
Venezuela Canada
Total
Venezuela Canada
Total
Years Ended December 31,
Revenue . . . . . . . . . . . . . $
Expenses and selling,
— $ 50,557 $ 50,557 $ — $53,591 $ 53,591 $ 2,940 $44,350 $ 47,290
general and
administrative . . . . . . .
Loss (recovery)
attributable to
expropriation,
impairments and
inventory write downs . .
Other (income) loss, net . .
Provision for (benefit
1,275
50,521
51,796
1,302
59,421
60,723
5,892
52,559
58,451
(136,947)
(219)
80,159
(130)
(56,788)
(349)
3,092
(150)
944
228
4,036
78
(38,925)
(12,145)
3,029
(2,350)
(35,896)
(14,495)
from) income taxes . . . .
(13,509)
2,564
(10,945)
1,719
(2,860)
(1,141)
2,795
(4,304)
(1,509)
Income (loss) from
discontinued operations,
net of tax . . . . . . . . . . $ 149,400 $(82,557) $ 66,843 $(5,963) $ (4,142) $(10,105) $ 45,323 $ (4,584) $ 40,739
The table below summarizes the balance sheet data for discontinued operations (in thousands):
December 31,
2012
2011
Venezuela
Canada
Total
Venezuela
Canada
Total
Cash . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable . . . . . . . . . . . . . . .
Inventory . . . . . . . . . . . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . .
$ 113
17
—
41
$
791
9,148
9,826
1,810
$
904
9,165
9,826
1,851
$
Total currents assets associated with
discontinued operations
. . . . . . . .
Property, plant and equipment . . . . . . .
Intangible and other long-term assets . .
171
—
—
21,575
—
—
21,746
—
—
304
9
1,017
2,683
4,013
—
—
$
135
13,973
19,590
953
$
439
13,982
20,607
3,636
34,651
69,788
9,432
38,664
69,788
9,432
Total assets associated with
discontinued operations
. . . . . . . .
$ 171
$21,575
$21,746
$ 4,013
$113,871
$117,884
Accounts payable . . . . . . . . . . . . . . . .
Accrued liabilities . . . . . . . . . . . . . . . .
Deferred revenue . . . . . . . . . . . . . . . .
$ 499
4,335
—
$ 3,345
2,724
669
$ 3,844
7,059
669
$
589
4,295
1,499
$
Total currents liabilities associated
with discontinued operations . . . . .
Other long-term liabilities . . . . . . . . . .
4,834
455
6,738
589
11,572
1,044
6,383
14,140
5,515
3,924
320
9,759
548
$
6,104
8,219
1,819
16,142
14,688
Total liabilities associated with
discontinued operations
. . . . . . . .
$5,289
$ 7,327
$12,616
$20,523
$ 10,307
$ 30,830
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3. Inventory
Inventory, net of reserves, consisted of the following amounts (in thousands):
December 31,
2012
2011
Parts and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Work in progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Finished goods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$232,737
120,930
34,043
$212,228
98,402
31,465
Inventory, net of reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$387,710
$342,095
During 2012, 2011 and 2010, we recorded $1.0 million, $5.0 million and $2.3 million, respectively,
in inventory write-downs and reserves for inventory, which were either obsolete, excess or carried at a
price above market value. As of December 31, 2012 and 2011, we had inventory reserves of
$11.7 million and $14.0 million, respectively.
4. Fabrication Contracts
Costs, estimated earnings and billings on uncompleted contracts consisted of the following (in
thousands):
December 31,
2012
2011
Costs incurred on uncompleted contracts . . . . . . . . . . . . . . . . . . . . . . . . . .
Estimated earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,133,835
195,742
$
895,337
157,893
Less—billings to date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,329,577
(1,334,730)
1,053,230
(1,014,977)
$
(5,153) $
38,253
Costs, estimated earnings and billings on uncompleted contracts are presented in the accompanying
financial statements as follows (in thousands):
Costs and estimated earnings in excess of billings on uncompleted contracts . . .
Billings on uncompleted contracts in excess of costs and estimated earnings . . . .
$ 159,098
(164,251)
$122,214
(83,961)
$
(5,153) $ 38,253
December 31,
2012
2011
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5. Property, Plant and Equipment
Property, plant and equipment consisted of the following (in thousands):
December 31,
2012
2011
Compression equipment, facilities and other fleet assets . . . . . . . . . . . . . . .
Land and buildings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transportation and shop equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 4,207,772
186,410
261,520
161,681
$ 4,226,307
176,764
233,689
144,946
Accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4,817,383
(1,975,352)
4,781,706
(1,847,042)
Property, plant and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 2,842,031
$ 2,934,664
Depreciation expense was $330.1 million, $333.0 million and $364.7 million in 2012, 2011 and 2010,
respectively. Assets under construction of $147.0 million and $140.5 million are primarily included in
compression equipment, facilities and other fleet assets at December 31, 2012 and 2011, respectively.
We capitalized $1.2 million, $1.5 million and $1.7 million of interest related to construction in process
during 2012, 2011 and 2010, respectively.
6. Intangible and Other Assets
Intangible and other assets consisted of the following (in thousands):
Deferred debt issuance costs, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intangible assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 18,348
84,993
31,102
40,405
$ 24,581
134,967
21,779
41,524
Intangibles and other assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$174,848
$222,851
Intangible assets and deferred debt issuance costs consisted of the following (in thousands):
December 31,
2012
2011
Deferred debt issuance costs . . . . . . . . . . . . . . . . . . .
Marketing related (5 - 20 year life) . . . . . . . . . . . . . . .
Customer- related (10 - 20 year life) . . . . . . . . . . . . . .
Technology based (20 year life) . . . . . . . . . . . . . . . . .
Contract based (2 - 11 year life) . . . . . . . . . . . . . . . . .
December 31, 2012
December 31, 2011
Gross
Carrying
Amount
$ 44,112
3,060
164,562
4,375
55,776
Accumulated
Amortization
$ (25,764)
(1,675)
(86,605)
(3,561)
(50,939)
Gross
Carrying
Amount
$ 44,141
3,043
169,282
32,275
64,465
Accumulated
Amortization
$ (19,560)
(1,400)
(73,566)
(6,747)
(52,385)
Intangible assets and deferred debt issuance costs . . . .
$271,885
$(168,544)
$313,206
$(153,658)
Amortization of deferred financing costs totaled $7.2 million, $8.9 million and $5.3 million in 2012,
2011 and 2010, respectively, and is recorded to interest expense in our consolidated statements of
operations. Amortization of intangible assets totaled $20.8 million, $24.0 million and $27.5 million in
2012, 2011 and 2010, respectively. During 2012, we recorded an impairment of intangible assets of
$29.1 million related to our contract water treatment business (see Note 13).
F-17
EXTERRAN HOLDINGS INC. 10-K
Proj: P30087HOU12 Job: 12ZDS78704 (12-30087-4)
Page Dim: 8.250(cid:1) X 10.750(cid:1) Copy Dim: 38. X 54.3
File: FQ78704A.;9
MERRILL CORPORATION JBAKER// 4-MAR-13 11:47 DISK106:[12ZDS4.12ZDS78704]FS78704A.;8
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Estimated future intangible amortization expense is as follows (in thousands):
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$14,914
12,381
10,483
8,987
7,321
30,907
$84,993
7. Investments in Non-Consolidated Affiliates
Investments in affiliates that are not controlled by Exterran but where we have the ability to
exercise significant control over the operations are accounted for using the equity method.
We own a 30.0% interest in WilPro Energy Services (PIGAP II) Limited (‘‘PIGAP II’’) and 33.3%
interest in WilPro Energy Services (El Furrial) Limited (‘‘El Furrial’’) joint ventures that provided
natural gas compression and injection services in Venezuela. In May 2009, PDVSA assumed control
over the assets of our Venezuelan joint ventures and transitioned the operations including the hiring of
their employees, to PDVSA. In March 2011, our Venezuelan joint ventures, together with the
Netherlands’ parent company of our joint venture partners, filed a request for the institution of an
arbitration proceeding against Venezuela with ICSID related to the seized assets and investments.
In March 2012, our Venezuelan joint ventures completed the sale of their assets to PDVSA Gas.
We received an initial payment of $37.6 million in March 2012, and received installment payments
totaling $14.1 million in the year ended December 31, 2012. The remaining principal amount due to us
of approximately $57 million is payable in quarterly net cash installments through the first quarter of
2016. We have not recognized amounts payable to us by PDVSA Gas as a receivable and will therefore
recognize quarterly payments received in the future as equity in (income) loss of non-consolidated
affiliates in our consolidated statements of operations in the periods such payments are received. In
connection with the sale of our Venezuelan joint ventures’ assets, the joint ventures and our joint
venture partners have agreed to suspend their previously filed arbitration proceeding against Venezuela
pending payment in full by PDVSA Gas of the purchase price for the assets.
8. Goodwill
Goodwill acquired in connection with business combinations represents the excess of consideration
over the fair value of tangible and identifiable intangible net assets acquired. Certain assumptions and
estimates are employed in determining the fair value of assets acquired and liabilities assumed, as well
as in determining the allocation of goodwill to the appropriate reporting units.
We performed our goodwill impairment test in the fourth quarter of each year, or whenever events
indicated impairment may have occurred, to determine if the estimated recoverable value of each of
our reporting units exceeded the net carrying value of the reporting unit, including the applicable
goodwill.
The first step in performing a goodwill impairment test is to compare the estimated fair value of
each reporting unit with its recorded net book value (including the goodwill). If the estimated fair value
of the reporting unit is higher than the recorded net book value, no impairment is deemed to exist and
no further testing is required. If, however, the estimated fair value of the reporting unit is below the
recorded net book value, then a second step must be performed to determine the goodwill impairment
required, if any. In this second step, the estimated fair value from the first step is used as the purchase
price in a hypothetical acquisition of the reporting unit. Purchase business combination accounting rules
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Proj: P30087HOU12 Job: 12ZDS78704 (12-30087-4)
Page Dim: 8.250(cid:1) X 10.750(cid:1) Copy Dim: 38. X 54.3
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MERRILL CORPORATION JBAKER// 4-MAR-13 11:47 DISK106:[12ZDS4.12ZDS78704]FS78704A.;8
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are followed to determine a hypothetical purchase price allocation to the reporting unit’s assets and
liabilities. The residual amount of goodwill resulting from this hypothetical purchase price allocation is
compared to the recorded amount of goodwill for the reporting unit, and the recorded amount is
written down to the hypothetical amount, if lower.
Because quoted market prices for our reporting units are not available, management must apply
judgment in determining the estimated fair value of these reporting units for purposes of performing
the annual goodwill impairment test. Management used all available information to make these fair
value determinations, including the present values of expected future cash flows using discount rates
commensurate with the risks involved in the assets.
We determined the fair value of our reporting units using both the expected present value of
future cash flows and a market approach. The present value of future cash flows is estimated using our
most recent forecast and the weighted average cost of capital of each reporting unit. The market
approach uses a market multiple on the reporting units’ earnings before interest, tax, depreciation and
amortization.
As a result of the level of decline in our stock price and corresponding market capitalization in the
third quarter of 2011, we performed a goodwill impairment test of our aftermarket services and
fabrication reporting units’ goodwill as of September 30, 2011. We determined the fair value of these
reporting units using the expected present value of future cash flows. This decline in our market
capitalization led us to increase the estimate of the market’s implied weighted average cost of capital
and reduce the present value of the forecasted cash flows. The test indicated that our aftermarket
services and fabrication reporting units’ goodwill was impaired and therefore we recorded a full
impairment of our remaining goodwill during 2011 of $196.8 million.
The table below presents the change in the net carrying amount of goodwill for the year ended
December 31, 2011 (in thousands):
Aftermarket
Services
Fabrication
Total
Balance as of December 31, 2010:
Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated impairment losses . . . . . . . . . . . . . . . . . . . . . . . .
$ 63,095
—
$ 221,154
(87,569)
$ 284,249
(87,569)
63,095
133,585
196,680
Goodwill acquired during year . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impact of foreign currency translation . . . . . . . . . . . . . . . . . . . .
447
(63,299)
(243)
218
(133,508)
(295)
665
(196,807)
(538)
Balance as of December 31, 2011:
Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated impairment losses . . . . . . . . . . . . . . . . . . . . . . . .
63,299
(63,299)
221,077
(221,077)
284,376
(284,376)
$
— $
— $
—
F-19
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Proj: P30087HOU12 Job: 12ZDS78704 (12-30087-4)
Page Dim: 8.250(cid:1) X 10.750(cid:1) Copy Dim: 38. X 54.3
File: FS78704A.;8
MERRILL CORPORATION JBAKER// 4-MAR-13 11:47 DISK106:[12ZDS4.12ZDS78704]FS78704A.;8
mrll_1111.fmt Free: 60D*/300D Foot: 0D/ 0D VJ RSeq: 3 Clr: 0
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9. Accrued Liabilities
Accrued liabilities consisted of the following (in thousands):
December 31,
2012
2011
Accrued salaries and other benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued income and other taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued warranty expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued interest
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest rate swaps fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued start-up and commissioning expenses . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 94,027
106,907
4,561
7,483
3,873
1,477
5,552
47,441
$ 69,106
108,177
3,879
8,366
14,250
3,543
14,400
53,409
Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$271,321
$275,130
10. Long-Term Debt
Long-term debt consisted of the following (in thousands):
Revolving credit facility due July 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Partnership’s revolving credit facility due November 2015 . . . . . . . . . . . . . . .
Partnership’s term loan facility due November 2015 . . . . . . . . . . . . . . . . . . .
4.25% convertible senior notes due June 2014 (presented net of the
unamortized discount of $34.3 million and $54.9 million, respectively) . . . .
4.75% convertible senior notes due January 2014 . . . . . . . . . . . . . . . . . . . . .
7.25% senior notes due December 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, interest at various rates, collateralized by equipment and other assets .
December 31,
2012
2011
$
70,000
530,500
150,000
$ 433,500
395,500
150,000
320,673
143,750
350,000
—
300,149
143,750
350,000
140
Long-term debt
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,564,923
$1,773,039
Exterran Senior Secured Credit Facility
In July 2011, we entered into a credit agreement providing for a five-year, $1.1 billion senior
secured revolving credit facility (the ‘‘2011 Credit Facility’’), which matures in July 2016 and replaced
our former senior secured credit facility. We incurred approximately $7.8 million in transaction costs
related to the 2011 Credit Facility. These costs are included in Intangible and other assets, net and
amortized over the facility term. As a result of the termination of our former senior secured credit
facility, we expensed approximately $1.6 million of unamortized deferred financing costs associated with
our former senior secured credit facility in the third quarter of 2011, which is reflected in Interest
expense in our consolidated statements of operations.
Concurrently with the execution of the credit agreement, we borrowed $387.3 million under the
2011 Credit Facility and used the proceeds to (i) repay the entire amount outstanding under our former
senior secured credit facility and terminate that facility and (ii) pay customary fees and other expenses
relating to the 2011 Credit Facility. In March 2012, we decreased the borrowing capacity under the
2011 Credit Facility by $200.0 million to $900.0 million. As a result of the decrease in borrowing
capacity under the 2011 Credit Facility, we expensed $1.3 million of unamortized deferred financing
costs associated with this facility in the first quarter of 2012, which is reflected in Interest expense in
our consolidated statements of operations.
F-20
EXTERRAN HOLDINGS INC. 10-K
Proj: P30087HOU12 Job: 12ZDS78704 (12-30087-4)
Page Dim: 8.250(cid:1) X 10.750(cid:1) Copy Dim: 38. X 54.3
File: FS78704A.;8
MERRILL CORPORATION JBAKER// 4-MAR-13 11:47 DISK106:[12ZDS4.12ZDS78704]FS78704A.;8
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Borrowings under the 2011 Credit Facility bear interest at a base rate or LIBOR, at our option,
plus an applicable margin. Depending on our Total Leverage Ratio (as defined in the credit
agreement), the applicable margin for revolving loans varies (i) in the case of LIBOR loans, from
1.50% to 2.50% and (ii) in the case of base rate loans, from 0.50% to 1.50%. The base rate is the
highest of the prime rate announced by Wells Fargo Bank, National Association, the Federal Funds
Rate plus 0.5% and one-month LIBOR plus 1.0%. At December 31, 2012, all amounts outstanding
under the 2011 Credit Facility were LIBOR loans and the applicable margin was 1.75%. The weighted
average annual interest rate at December 31, 2012 on the outstanding balance under the 2011 Credit
Facility was 2.0%.
As of December 31, 2012, we had $70.0 million in outstanding borrowings and $183.9 million in
outstanding letters of credit under the 2011 Credit Facility. At December 31, 2012, taking into account
guarantees through letters of credit, we had undrawn and available capacity of $646.1 million under the
2011 Credit Facility.
Our Significant Domestic Subsidiaries (as defined in the credit agreement) guarantee the debt
under the 2011 Credit Facility. Borrowings under the 2011 Credit Facility are secured by substantially
all of the personal property assets and certain real property assets of us and our Significant Domestic
Subsidiaries, including all of the equity interests of our U.S. subsidiaries (other than certain excluded
subsidiaries) and 65% of the equity interests in certain of our first-tier foreign subsidiaries. The
Partnership does not guarantee the debt under the 2011 Credit Facility, its assets are not collateral
under the 2011 Credit Facility and the general partner units in the Partnership are not pledged under
the 2011 Credit Facility. Subject to certain conditions, at our request, and with the approval of the
lenders, the aggregate commitments under the 2011 Credit Facility may be increased by up to an
additional $300 million.
The credit agreement contains various covenants with which we or certain of our subsidiaries must
comply, including, but not limited to, restrictions on the use of proceeds from borrowings and
limitations on our ability to incur additional indebtedness, enter into transactions with affiliates, merge
or consolidate, sell assets, make certain investments and acquisitions, make loans, grant liens,
repurchase equity and pay dividends and distributions. We are also subject to financial covenants,
including a ratio of Adjusted EBITDA (as defined in the credit agreement) to Total Interest Expense
(as defined in the credit agreement) of not less than 2.25 to 1.0, a ratio of consolidated Total Debt (as
defined in the credit agreement) to Adjusted EBITDA of not greater than 5.0 to 1.0 and a ratio of
Senior Secured Debt (as defined in the credit agreement) to Adjusted EBITDA of not greater than 4.0
to 1.0.
Exterran Asset-Backed Securitization Facility
In March 2011, we repaid the $6.0 million outstanding balance under our asset-backed
securitization facility and terminated that facility. As a result of this termination, we expensed
$1.4 million of unamortized deferred financing costs, which is reflected in Interest expense in our
consolidated statements of operations for the year ended December 31, 2011.
The Partnership Revolving Credit Facility and Term Loan
In November 2010, the Partnership, as guarantor, and EXLP Operating LLC, a wholly-owned
subsidiary of the Partnership, as borrower, entered into an amendment and restatement of their senior
secured credit agreement (the ‘‘Partnership Credit Agreement’’) to provide for a five-year
$550.0 million senior secured credit facility, consisting of a $400.0 million revolving credit facility and a
$150.0 million term loan facility. In March 2011, the revolving borrowing capacity under this facility was
increased by $150.0 million to $550.0 million. Concurrent with the execution of the Partnership Credit
Agreement in November 2010, the Partnership borrowed $304.0 million under its revolving credit
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facility and $150.0 million under its term loan facility and used the proceeds to (i) repay the entire
$406.1 million outstanding under the Partnership’s previous senior secured credit facility, (ii) repay the
entire $30.0 million outstanding under the Partnership’s asset-backed securitization facility and
terminate that facility, (iii) pay $14.8 million to terminate the interest rate swap agreements to which
the Partnership was a party and (iv) pay customary fees and other expenses relating to the Partnership
Credit Agreement. The Partnership incurred transaction costs of approximately $4.0 million related to
the Partnership Credit Agreement. These costs were included in Intangible and other assets, net and
are being amortized over the respective facility terms. As a result of the amendment and restatement of
the Partnership Credit Agreement, we expensed $0.2 million of unamortized deferred financing costs
associated with the refinanced debt, which is reflected in Interest expense in our consolidated statement
of operations.
In March 2012, the Partnership and EXLP Operating LLC, the Partnership’s wholly-owned
subsidiary, increased the borrowing capacity under their revolving credit facility by $200.0 million to
$750.0 million. During the three months ended March 31, 2012, the Partnership incurred transaction
costs of approximately $0.5 million related to the amendment of the Partnership Credit Agreement.
These costs are included in Intangible and other assets, net and are being amortized over the facility
term.
As of December 31, 2012, the Partnership had undrawn capacity of $219.5 million under its
revolving credit facility. The Partnership Credit Agreement limits its Total Debt (as defined in the
Partnership Credit Agreement) to EBITDA ratio (as defined in the Partnership Credit Agreement) to
not greater than 4.75 to 1.0 (which will increase to 5.25 to 1.0 following the occurrence of certain
events specified in the Partnership Credit Agreement). As a result of this limitation, $199.4 million of
the $219.5 million of undrawn capacity under the Partnership’s revolving credit facility was available for
additional borrowings as of December 31, 2012.
The Partnership’s revolving credit facility bears interest at a base rate or LIBOR, at the
Partnership’s option, plus an applicable margin. Depending on the Partnership’s leverage ratio, the
applicable margin for revolving loans varies (i) in the case of LIBOR loans, from 2.25% to 3.25% and
(ii) in the case of base rate loans, from 1.25% to 2.25%. The base rate is the highest of the prime rate
announced by Wells Fargo Bank, National Association, the Federal Funds Effective Rate plus 0.5% and
one-month LIBOR plus 1.0%. At December 31, 2012, all amounts outstanding under this facility were
LIBOR loans and the applicable margin was 2.5%. The weighted average annual interest rate on the
outstanding balance of this facility at December 31, 2012, excluding the effect of interest rate swaps,
was 2.8%.
The Partnership’s term loan facility bears interest at a base rate or LIBOR, at the Partnership’s
option, plus an applicable margin. Depending on the Partnership’s leverage ratio, the applicable margin
for term loans varies (i) in the case of LIBOR loans, from 2.5% to 3.5% and (ii) in the case of base
rate loans, from 1.5% to 2.5%. At December 31, 2012, all amounts outstanding under the term loan
facility were LIBOR loans and the applicable margin was 2.75%. The average annual interest rate on
the outstanding balance of the term loan facility at December 31, 2012 was 3.0%.
Borrowings under the Partnership Credit Agreement are secured by substantially all of the U.S.
personal property assets of the Partnership and its Significant Domestic Subsidiaries (as defined in the
Partnership Credit Agreement), including all of the membership interests of the Partnership’s Domestic
Subsidiaries (as defined in the Partnership Credit Agreement).
The Partnership Credit Agreement contains various covenants with which the Partnership must
comply, including, but not limited to, restrictions on the use of proceeds from borrowings and
limitations on its ability to incur additional indebtedness, enter into transactions with affiliates, merge
or consolidate, sell assets, make certain investments and acquisitions, make loans, grant liens,
repurchase equity and pay dividends and distributions. It also contains various covenants requiring
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mandatory prepayments of the term loans from the net cash proceeds of certain future asset transfers.
The Partnership must maintain various consolidated financial ratios, including a ratio of EBITDA (as
defined in the Partnership Credit Agreement) to Total Interest Expense (as defined in the Partnership
Credit Agreement) of not less than 3.0 to 1.0 (which will decrease to 2.75 to 1.0 following the
occurrence of certain events specified in the Partnership Credit Agreement) and a ratio of Total Debt
(as defined in the Partnership Credit Agreement) to EBITDA of not greater than 4.75 to 1.0 (which
will increase to 5.25 to 1.0 following the occurrence of certain events specified in the Partnership Credit
Agreement). A violation of the Partnership’s Total Debt to EBITDA covenant would be an event of
default under the Partnership Credit Agreement, which would trigger cross-default provisions under
certain of our debt agreements. As of December 31, 2012, the Partnership was in compliance with all
financial covenants under the Partnership Credit Agreement.
7.25% Senior Notes
In November 2010, we issued $350.0 million aggregate principal amount of 7.25% senior notes due
December 2018 (the ‘‘7.25% Notes’’). The 7.25% Notes are guaranteed on a senior unsecured basis by
all of our existing subsidiaries that guarantee indebtedness under the Credit Agreement and certain of
our future subsidiaries. The Partnership and its subsidiaries have not guaranteed the 7.25% Notes. The
7.25% Notes and the guarantees are our and the guarantors’ general unsecured senior obligations,
respectively, rank equally in right of payment with all of our and the guarantors’ other senior
obligations, and are effectively subordinated to all of our and the guarantors’ existing and future
secured debt to the extent of the value of the collateral securing such indebtedness. In addition, the
7.25% Notes and guarantees are structurally subordinated to all existing and future indebtedness and
other liabilities, including trade payables, of our non-guarantor subsidiaries.
Prior to December 1, 2013, we may redeem all or a part of the 7.25% Notes at a redemption price
equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the
redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, we may
redeem up to 35% of the aggregate principal amount of the 7.25% Notes prior to December 1, 2013
with the net proceeds of a public or private equity offering at a redemption price of 107.250% of the
principal amount of the 7.25% Notes, plus any accrued and unpaid interest to the date of redemption,
if at least 65% of the aggregate principal amount of the 7.25% Notes issued under the indenture
remains outstanding after such redemption and the redemption occurs within 120 days of the date of
the closing of such equity offering. On or after December 1, 2013, we may redeem all or a part of the
7.25% Notes at redemption prices (expressed as percentages of principal amount) equal to 105.438%
for the twelve-month period beginning on December 1, 2013, 103.625% for the twelve-month period
beginning on December 1, 2014, 101.813% for the twelve-month period beginning on December 1, 2015
and 100.000% for the twelve-month period beginning on December 1, 2016 and at any time thereafter,
plus accrued and unpaid interest, if any, to the applicable redemption date on the 7.25% Notes.
4.25% Convertible Senior Notes
In June 2009, we issued $355.0 million aggregate principal amount of 4.25% convertible senior
notes due June 2014 (the ‘‘4.25% Notes’’). The 4.25% Notes are convertible upon the occurrence of
certain conditions into shares of our common stock at an initial conversion rate of 43.1951 shares of
our common stock per $1,000 principal amount of the convertible notes, equivalent to an initial
conversion price of approximately $23.15 per share of common stock. The conversion rate will be
subject to adjustment following certain dilutive events and certain corporate transactions. The value of
the shares the 4.25% Notes can be converted into did not exceed their principal amount as of
December 31, 2012. We may not redeem the 4.25% Notes prior to their maturity date.
GAAP requires that the liability and equity components of certain convertible debt instruments
that may be settled in cash upon conversion be separately accounted for in a manner that reflects an
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issuer’s nonconvertible debt borrowing rate. Upon issuance of our 4.25% Notes, $97.9 million was
recorded as a debt discount and reflected in equity related to the convertible feature of these notes.
The discount on the 4.25% Notes will be amortized using the effective interest method through
June 30, 2014. During each of the years ended December 31, 2012, 2011 and 2010, we recognized
$15.1 million of interest expense related to the contractual interest coupon. During the years ended
December 31, 2012, 2011 and 2010, we recognized $20.5 million, $18.3 million and $16.4 million,
respectively, of interest expense related to the amortization of the debt discount. The effective interest
rate on the debt component of these notes is 11.67%.
The 4.25% Notes are our senior unsecured obligations and rank senior in right of payment to our
existing and future indebtedness that is expressly subordinated in right of payment to the 4.25% Notes;
equal in right of payment to our existing and future unsecured indebtedness that is not so
subordinated; junior in right of payment to any of our secured indebtedness to the extent of the value
of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness
and liabilities incurred by our subsidiaries. The 4.25% Notes are not guaranteed by any of our
subsidiaries.
In connection with the offering of the 4.25% Notes, we purchased call options on our stock at
approximately $23.15 per share of common stock and sold warrants on our stock at approximately
$32.67 per share of common stock. These transactions economically adjust the effective conversion
price to $32.67 for $325.0 million of the 4.25% Notes and therefore are expected to reduce the
potential dilution to our common stock upon any such conversion.
4.75% Convertible Senior Notes
In December 2003, Hanover issued $143.75 million aggregate principal amount of 4.75%
Convertible Senior Notes due January 15, 2014 (the ‘‘4.75% Notes’’). In connection with the merger in
August 2007, we executed supplemental indentures between Hanover and the trustees, pursuant to
which we agreed to fully and unconditionally guarantee the obligations of Hanover relating to the
4.75% Notes. In June 2012, in connection with an organizational restructuring of certain of our
subsidiaries, we entered into a supplemental indenture, pursuant to which we assumed all rights and
obligations of the issuer relating to the 4.75% Notes.
The 4.75% Notes are our general unsecured obligations and rank equally in right of payment with
all of our other senior debt. The 4.75% Notes are effectively subordinated to all existing and future
liabilities of our subsidiaries.
The 4.75% Notes are convertible into a whole number of shares of our common stock and cash in
lieu of fractional shares. The 4.75% Notes are convertible at the option of the holder into shares of our
common stock at a conversion rate of 21.6667 shares of common stock per $1,000 principal amount of
convertible senior notes, which is equivalent to a conversion price of approximately $46.15 per share.
At any time on or after January 15, 2011 but prior to January 15, 2013, we may redeem some or
all of the 4.75% Notes at a redemption price equal to 100% of the principal amount of the 4.75%
Notes plus accrued and unpaid interest, if any, if the price of our common stock exceeds 135% of the
conversion price of the convertible senior notes then in effect for 20 trading days out of a period of 30
consecutive trading days. At any time on or after January 15, 2013, we may redeem some or all of the
4.75% Notes at a redemption price equal to 100% of the principal amount of the 4.75% Notes plus
accrued and unpaid interest, if any. Holders have the right to require us to repurchase the 4.75% Notes
upon a specified change in control, at a repurchase price equal to 100% of the principal amount of
4.75% Notes plus accrued and unpaid interest, if any.
F-24
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File: FS78704A.;8
MERRILL CORPORATION JBAKER// 4-MAR-13 11:47 DISK106:[12ZDS4.12ZDS78704]FU78704A.;11
mrll_1111.fmt Free: 95D*/120D Foot: 0D/ 0D VJ RSeq: 1 Clr: 0
DISK024:[PAGER.PSTYLES]UNIVERSAL.BST;102
2 C Cs: 46396
Debt Compliance
We were in compliance with our debt covenants as of December 31, 2012. If we fail to remain in
compliance with our financial covenants we would be in default under our credit agreements. In
addition, if we experienced a material adverse effect on our assets, liabilities, financial condition,
business or operations that, taken as a whole, impact our ability to perform our obligations under our
credit agreements, this could lead to a default under our credit agreements. A default under one or
more of our debt agreements, including a default by the Partnership under its credit facility, would
trigger cross-default provisions under certain of our debt agreements, which would accelerate our
obligation to repay our indebtedness under those agreements.
Long-term Debt Maturity Schedule
Contractual maturities of long-term debt (excluding interest to be accrued thereon) at
December 31, 2012 are as follows (in thousands):
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31,
2012
$
—
498,750(1)
680,500
70,000
—
350,000
Total debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$1,599,250(1)
(1) This amount includes the full face value of the 4.25% Notes and is not reduced by the
unamortized discount of $34.3 million as of December 31, 2012.
11. Accounting for Derivatives
We are exposed to market risks primarily associated with changes in interest rates and foreign
currency exchange rates. We use derivative financial instruments to minimize the risks and/or costs
associated with financial activities by managing our exposure to interest rate fluctuations on a portion
of our debt obligations. We also use derivative financial instruments to minimize the risks caused by
currency fluctuations in certain foreign currencies. We do not use derivative financial instruments for
trading or other speculative purposes.
Interest Rate Risk
At December 31, 2012, we were a party to interest rate swaps pursuant to which we make fixed
payments and receive floating payments on a notional value of $250.0 million. We entered into these
swaps to offset changes in expected cash flows due to fluctuations in the associated variable interest
rates. Our interest rate swaps expire in November 2015. As of December 31, 2012, the weighted
average effective fixed interest rate on our interest rate swaps was 1.8%. We have designated these
interest rate swaps as cash flow hedging instruments so that any change in their fair values is
recognized as a component of comprehensive income (loss) and is included in accumulated other
comprehensive income (loss) to the extent the hedge is effective. The swap terms substantially coincide
with the hedged item and are expected to offset changes in expected cash flows due to fluctuations in
the variable rate, and therefore we currently do not expect a significant amount of ineffectiveness on
these hedges. We perform quarterly calculations to determine whether the swap agreements are still
effective and to calculate any ineffectiveness. For the years ended December 31, 2012 and 2011 there
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was no ineffectiveness related to interest rate swaps. We recorded approximately $0.2 million of interest
expense for the year ended December 31, 2010, due to the ineffectiveness related to interest rate
swaps. We estimate that $3.9 million of deferred pre-tax losses attributable to existing interest rate
swaps and included in our accumulated other comprehensive income (loss) at December 31, 2012, will
be reclassified into earnings as interest expense at then-current values during the next twelve months as
the underlying hedged transactions occur. Cash flows from derivatives designated as hedges are
classified in our consolidated statements of cash flows under the same category as the cash flows from
the underlying assets, liabilities or anticipated transactions.
In the fourth quarter of 2010, we paid $43.0 million to terminate interest rate swap agreements
with a total notional value of $585.0 million and a weighted average effective fixed interest rate of
4.6%. These swaps qualified for hedge accounting and were previously included on our balance sheet
as a liability and in accumulated other comprehensive income (loss). The liability was paid in
connection with the termination, and the associated amount in accumulated other comprehensive
income (loss) is being amortized into interest expense over the original terms of the swaps. We
estimate that $1.6 million of deferred pre-tax losses from these terminated interest rate swaps will be
amortized into interest expense during the next twelve months.
Foreign Currency Exchange Risk
We operate in approximately 30 countries throughout the world, and a fluctuation in the value of
the currencies of these countries relative to the U.S. dollar could impact our profits from international
operations and the value of the net assets of our international operations when reported in U.S. dollars
in our financial statements. From time to time we may enter into foreign currency hedges to reduce
our foreign exchange risk associated with cash flows we will receive in a currency other than the
functional currency of the local Exterran affiliate that entered into the contract. The impact of foreign
currency exchange on our consolidated statements of operations will depend on the amount of our net
asset and liability positions exposed to currency fluctuations in future periods.
Foreign currency swaps or forward contracts that meet the hedging requirements or that qualify for
hedge accounting treatment are accounted for as cash flow hedges and changes in the fair value are
recognized as a component of comprehensive income (loss) to the extent the hedge is effective. The
amounts recognized as a component of other comprehensive income (loss) will be reclassified into
earnings (loss) in the periods in which the underlying foreign currency exchange transaction is
recognized and are included under the same category as the income or loss from the underlying assets,
liabilities, or anticipated transactions in our consolidated statements of operations. For foreign currency
swaps and forward contracts that do not qualify for hedge accounting treatment, changes in fair value
and gains and losses on settlement are included under the same category as the income or loss from
the underlying assets, liabilities or anticipated transactions in our consolidated statements of operations.
The following tables present the effect of derivative instruments on our consolidated financial
position and results of operations (in thousands). The impacts to other comprehensive income (loss)
and accumulated other comprehensive (income) loss on derivatives disclosed below are presented net
of tax:
Derivatives designated as hedging instruments:
Interest rate hedges . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued liabilities
Interest rate hedges . . . . . . . . . . . . . . . . . . . . . . . . . . . Other long-term liabilities
Total derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(3,873)
(6,043)
$(9,916)
December 31, 2012
Balance Sheet
Location
Fair Value
Asset (Liability)
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MERRILL CORPORATION JBAKER// 4-MAR-13 11:47 DISK106:[12ZDS4.12ZDS78704]FU78704A.;11
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Derivatives designated as hedging instruments:
Interest rate hedges . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued liabilities
Interest rate hedges . . . . . . . . . . . . . . . . . . . . . . . . . . . Other long-term liabilities
Total derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(14,250)
(5,196)
$(19,446)
December 31, 2011
Balance Sheet
Location
Fair Value
Asset (Liability)
Year Ended December 31, 2012
Gain (Loss)
Recognized in Other
Comprehensive
Income (Loss) on
Derivatives
Location of Gain (Loss)
Reclassified from
Accumulated Other
Comprehensive
Income (loss)
into Income (Loss)
Gain (Loss)
Reclassified from
Accumulated Other
Comprehensive
Income (loss)
into Income (Loss)
Derivatives designated as cash flow hedges:
Interest rate hedges . . . . . . . . . . . . . . . .
$(13,458)
Interest expense
$(26,284)
Year Ended December 31, 2011
Gain (Loss)
Recognized in Other
Comprehensive
Income (Loss) on
Derivatives
Location of Gain (Loss)
Reclassified from
Accumulated Other
Comprehensive
Income (loss)
into Income (Loss)
Gain (Loss)
Reclassified from
Accumulated Other
Comprehensive
Income (loss)
into Income (Loss)
Derivatives designated as cash flow hedges:
Interest rate hedges . . . . . . . . . . . . . . . .
Foreign currency hedge . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(29,178)
—
$(29,178)
Interest expense
Fabrication revenue
$(47,729)
410
$(47,319)
Year Ended December 31, 2010
Gain (Loss)
Recognized in Other
Comprehensive
Income (Loss) on
Derivatives
Location of Gain (Loss)
Reclassified from
Accumulated Other
Comprehensive
Income (loss)
into Income (Loss)
Gain (Loss)
Reclassified from
Accumulated Other
Comprehensive
Income (loss)
into Income (Loss)
Derivatives designated as cash flow hedges:
Interest rate hedges . . . . . . . . . . . . . . . .
Foreign currency hedge . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(44,558)
(3,880)
$(48,438)
Interest expense
Fabrication revenue
$(55,771)
(3,470)
$(59,241)
The counterparties to our derivative agreements are major international financial institutions. We
monitor the credit quality of these financial institutions and do not expect non-performance by any
counterparty, although such non-performance could have a material adverse effect on us. We have no
specific collateral posted for our derivative instruments. The counterparties to our interest rate swaps
are also lenders under our credit facilities and, in that capacity, share proportionally in the collateral
pledged under the related facility.
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MERRILL CORPORATION JBAKER// 4-MAR-13 11:47 DISK106:[12ZDS4.12ZDS78704]FU78704A.;11
mrll_1111.fmt Free: 70D*/120D Foot: 0D/ 0D VJ RSeq: 4 Clr: 0
DISK024:[PAGER.PSTYLES]UNIVERSAL.BST;102
2 C Cs: 250
12. Fair Value Measurements
The accounting standard for fair value measurements and disclosures establishes a fair value
hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into the
following three broad categories.
(cid:127) Level 1—Quoted unadjusted prices for identical instruments in active markets to which we have
access at the date of measurement.
(cid:127) Level 2—Quoted prices for similar instruments in active markets; quoted prices for identical or
similar instruments in markets that are not active; and model-derived valuations in which all
significant inputs and significant value drivers are observable in active markets. Level 2 inputs
are those in markets for which there are few transactions, the prices are not current, little public
information exists or prices vary substantially over time or among brokered market makers.
(cid:127) Level 3—Model derived valuations in which one or more significant inputs or significant value
drivers are unobservable. Unobservable inputs are those inputs that reflect our own assumptions
regarding how market participants would price the asset or liability based on the best available
information.
The following table presents our assets and liabilities measured at fair value on a recurring basis as
of December 31, 2012 and 2011, with pricing levels as of the date of valuation (in thousands):
December 31,
2012
2011
(Level 1)
(Level 2)
(Level 3)
(Level 1)
(Level 2)
(Level 3)
Interest rate swaps asset (liability) . . . . . . .
$—
$(9,916)
$—
$—
$(19,446)
$—
On a quarterly basis, our interest rate swaps are recorded at fair value utilizing a combination of
the market approach and income approach to estimate fair value based on forward LIBOR curves.
The following table presents our assets and liabilities measured at fair value on a nonrecurring
basis for the years ended December 31, 2012 and 2011, with pricing levels as of the date of valuation
(in thousands):
Impaired long-lived assets . . . . . . . . . . . . . .
Impaired long-lived assets—Discontinued
Years Ended December 31,
2012
2011
(Level 1)
(Level 2)
(Level 3)
(Level 1)
(Level 2)
(Level 3)
$—
$—
$35,654
$—
$—
$1,463
operations . . . . . . . . . . . . . . . . . . . . . . .
—
—
—
—
—
—
Our estimate of the fair value of the impaired long-lived assets was primarily based on the
expected net sale proceeds compared to other fleet units we recently sold, as well as our review of
other units recently offered for sale by third parties, or the estimated component value of the
equipment we plan to use. Because we expect the disposition of the fleet assets we impaired during
2012 to take more than twelve months, we discounted the expected proceeds, net of selling and other
carrying costs, using a weighted average disposal period of four years and a discount rate of 10.4%.
Our estimate of the fair value of the impaired assets that are classified as discontinued operations was
based on our expected proceeds, net of selling costs.
13. Long-Lived Asset Impairment
During 2012, we evaluated the future deployment of our idle fleet and determined to retire and
either sell or re-utilize key components on approximately 930 idle compressor units, or approximately
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318,000 horsepower, that we previously used to provide services in our North America contract
operations segment. As a result, we performed an impairment review and recorded a $97.1 million
asset impairment to reduce the book value of each unit to its estimated fair value. The fair value of
each unit was estimated based on the expected net sale proceeds compared to other fleet units we
recently sold, as well as our review of other units recently offered for sale by third parties, or the
estimated component value of the equipment we plan to use.
In connection with our review of our fleet in 2012, we evaluated for impairment idle units that had
been culled from our fleet in prior years and were available for sale. Based upon that review, we
reduced the expected proceeds from disposition for most of the remaining units and increased the
weighted average disposal period for the units from the assumptions used in prior periods. This
resulted in an additional impairment of $34.8 million to reduce the book value of each unit to its
estimated fair value.
In the fourth quarter of 2012, we committed to a plan to abandon our contract water treatment
business as part of our continued emphasis on simplification and focus on our core businesses. In
conjunction with the planned abandonment, we recorded an impairment of long-lived assets of
$46.8 million, including property, plant and equipment impairment of $17.7 million and intangible
assets impairment of $29.1 million. The fair value of our contract water treatment assets was based on
projected cash flows of active assets currently under contract, which expire in 2013, and expected net
sales proceeds of idle assets that have been culled from our fleet. We expect the abandonment of our
contract water treatment business to be completed by December 31, 2013.
During 2012, we evaluated other long-lived assets for impairment and recorded long-lived asset
impairments of $4.7 million on these assets.
During 2011, we reviewed the idle compression assets used in our contract operations segments for
units that were not of the type, configuration, make or model that are cost effective to maintain and
operate. Our estimate of the fair value of the impaired long-lived assets was based on the expected net
sale proceeds compared to other fleet units we recently sold, as well as our review of other units
recently offered for sale by third parties, or the estimated component value of the equipment we plan
to use. The net book value of these assets exceeded the fair value by $5.7 million for the year ended
December 31, 2011 and was recorded as a long-lived asset impairment. In addition, in the fourth
quarter of 2011, we recorded a $0.4 million impairment of other long-lived assets.
During 2010, we completed an evaluation of our longer-term strategies and determined to retire
and sell approximately 1,800 idle compressor units, or approximately 600,000 horsepower, that we
previously used to provide services in our North America and international contract operations
businesses. As a result, we performed an impairment review and recorded a $133.0 million asset
impairment to reduce the book value of each unit to its estimated fair value. The fair value of each
unit was estimated based on the expected net sale proceeds compared to other fleet units we recently
sold, as well as our review of other units that were recently for sale by third parties.
As a result of a decline in market conditions in North America during 2010, we reviewed the idle
compression assets used in our contract operations segments for units that were not of the type,
configuration, make or model that are cost effective to maintain and operate. We determined that
323 units representing 61,400 horsepower would be retired from the fleet in 2010. We performed a cash
flow analysis of the expected proceeds from the salvage value of these units to determine the fair value
of the assets. The net book value of these assets exceeded the fair value by $7.6 million for the year
ended December 31, 2010 and was recorded as a long-lived asset impairment.
In addition, in the fourth quarter of 2010, 105 fleet units that we previously utilized in our
international contract operations segment were damaged in a flood, resulting in a long-lived asset
impairment of $3.3 million.
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14. Restructuring Charges
In November 2011, we announced a workforce cost reduction program across all of our business
segments as a first step in a broader overall profit improvement initiative. These actions were the result
of a review of our cost structure aimed at identifying ways to reduce our on-going operating costs and
to adjust the size of our workforce to be consistent with current and expected activity levels. A
significant portion of the workforce cost reduction program was completed in 2011, with the remainder
completed in 2012.
During the years ended December 31, 2012 and 2011, we incurred $6.6 and $11.6 million,
respectively, of restructuring charges primarily related to termination benefits and consulting services.
These charges are reflected as Restructuring charges in our consolidated statements of operations.
The following table summarizes the changes to our accrued liability balance related to
restructuring charges for the years ended December 31, 2011 and 2012 (in thousands):
Restructuring
Charges Accrual
Beginning balance at December 31, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Additions for costs expensed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less non-cash expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reductions for payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ending balance at December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Additions for costs expensed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less non-cash expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reductions for payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ —
11,594
(1,575)
(8,243)
1,776
6,636
(83)
(8,329)
Ending balance at December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ —
Restructuring charges by segment are as follows (in thousands):
North America
Contract
Operations
International
Contract
Operations
Aftermarket
Services
Fabrication
Other(1)
Total
Costs incurred in 2011 . . . . . . .
Costs incurred in 2012 . . . . . . .
Total costs incurred . . . . . . . . .
$
53
968
$1,021
$ 502
800
$1,302
$422
485
$907
$1,574
902
$2,476
$ 9,043
3,481
$11,594
6,636
$12,524
$18,230
(1) Includes corporate related items
15. Income Taxes
The components of loss before income taxes were as follows (in thousands):
Years Ended December 31,
2012
2011
2010
United States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(200,005) $(268,492) $(238,776)
22,494
(71,626)
33,618
Loss before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(166,387) $(340,118) $(216,282)
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The provision for (benefit from) income taxes consisted of the following (in thousands):
Years Ended December 31,
2012
2011
2010
Current tax provision (benefit):
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.S. federal
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ (7,050) $ 4,020
6,552
28,000
2,182
35,238
$
Total current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
30,370
38,572
1,690
3,157
55,837
60,684
Deferred tax provision (benefit):
U.S. federal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(71,947)
(5,043)
(15,755)
(72,014)
(7,874)
30,711
(83,763)
(10,110)
(29,113)
Total deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(92,745)
(49,177)
(122,986)
Provision for (benefit from) income taxes . . . . . . . . . . . . . . . . . . . . .
$(62,375) $(10,605) $ (62,302)
The provision for (benefit from) income taxes for 2012, 2011 and 2010 resulted in effective tax
rates on continuing operations of 37.5%, 3.1% and 28.8%, respectively. The reasons for the differences
between these effective tax rates and the U.S. statutory rate of 35% are as follows (in thousands):
Years Ended December 31,
2012
2011
2010
Income taxes at U.S. federal statutory rate of 35% . . . . . . . . . . . . . .
Net state income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncontrolling interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign tax credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrecognized tax benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Valuation allowances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill impairment
Proceeds from sale of joint venture assets . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(58,235) $(119,041) $(75,699)
(3,765)
22,289
3,134
(6,497)
(817)
(1,892)
—
—
945
(2,836)
14,607
(1,772)
(9,925)
(166)
14,649
—
(18,019)
(678)
(538)
5,085
(1,103)
(11,431)
(741)
62,318
53,988
—
858
Provision (benefit from) for income taxes . . . . . . . . . . . . . . . . . . . . .
$(62,375) $ (10,605) $(62,302)
Deferred income tax balances are the direct effect of temporary differences between the financial
statement carrying amounts and the tax basis of assets and liabilities at the enacted tax rates expected
F-31
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2 C Cs: 42239
to be in effect when the taxes are actually paid or recovered. The tax effects of temporary differences
that give rise to deferred tax assets and deferred tax liabilities are as follows (in thousands):
Years Ended December 31,
2012
2011
Deferred tax assets:
Net operating loss carryforwards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Alternative minimum tax credit carryforwards . . . . . . . . . . . . . . . . . . . . . . .
Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign tax credit carryforwards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 210,955
2,254
5,920
15,392
110,191
59,147
$ 243,023
4,942
13,020
14,627
100,266
34,714
Subtotal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Valuation allowances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
403,859
(86,054)
410,592
(76,056)
Total deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
317,805
334,536
Deferred tax liabilities:
Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Basis difference in the Partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill and intangibles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(255,184)
(65,422)
—
(333,948)
(69,922)
124
Total deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(320,606)
(403,746)
Net deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ (2,801) $ (69,210)
Tax balances are presented in the accompanying consolidated balance sheets as follows (in
thousands):
Years Ended December 31,
2012
2011
Current deferred income tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intangibles and other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 88,508
31,102
(1,477)
(120,934)
$ 37,401
21,779
(3,543)
(124,847)
Net deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ (2,801) $ (69,210)
At December 31, 2012, we had U.S. federal net operating loss carryforwards of approximately
$335.3 million that are available to offset future taxable income. If not used, the carryforwards will
begin to expire in 2022. We also had approximately $309.6 million of net operating loss carryforwards
in certain foreign jurisdictions (excluding discontinued operations), approximately $173.6 million of
which has no expiration date, $51.5 million of which is subject to expiration from 2013 to 2017, and the
remainder of which expires in future years through 2032. Foreign tax credit carryforwards of
$110.2 million and alternative minimum tax credit carryforwards of $5.9 million are available to offset
future payments of U.S. federal income tax. The foreign tax credits will expire in varying amounts
beginning in 2013, whereas the alternative minimum tax credits may be carried forward indefinitely
under current U.S. tax law.
Pursuant to Sections 382 and 383 of the Internal Revenue Code of 1986, as amended, utilization of
loss carryforwards and credit carryforwards, such as foreign tax credits, will be subject to annual
limitations due to the ownership changes of both Hanover and Universal. In general, an ownership
change, as defined by Section 382, results from transactions increasing the ownership of certain
stockholders or public groups in the stock of a corporation by more than 50 percentage points over a
F-32
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MERRILL CORPORATION JBAKER// 4-MAR-13 11:47 DISK106:[12ZDS4.12ZDS78704]FW78704A.;9
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three-year period. The merger resulted in such an ownership change for both Hanover and Universal.
Our ability to utilize loss carryforwards and credit carryforwards against future U.S. federal taxable
income and future U.S. federal income tax may be limited. The limitations may cause us to pay U.S.
federal income taxes earlier; however, we do not currently expect that any loss carryforwards or credit
carryforwards will expire as a result of these limitations.
We record valuation allowances when it is more likely than not that some portion or all of our
deferred tax assets will not be realized. The ultimate realization of the deferred tax assets depends on
the ability to generate sufficient taxable income of the appropriate character and in the appropriate
taxing jurisdictions in the future. If we do not meet our expectations with respect to taxable income, we
may not realize the full benefit from our deferred tax assets which would require us to record a
valuation allowance in our tax provision in future years.
In the third quarter of 2011, we recorded a valuation allowance of $1.3 million against our foreign
tax credit deferred tax asset. While we expect to generate sufficient foreign source taxable income in
the future, we no longer expect to generate sufficient overall taxable income in the future to fully use
our net operating loss carryforwards and thus a portion of our foreign tax credit carryforwards before
the year 2014. The foreign tax credits that expire in the year 2013 are no longer more likely than not to
be realized within the 10-year carryforward period.
In the fourth quarter of 2011, a $48.6 million valuation allowance was recorded against the
deferred tax asset for Brazil net operating loss carryforwards. Although the net operating losses have an
unlimited carryforward period, cumulative losses in recent years and losses expected in the near term
result in it no longer being more likely than not that we will realize the deferred tax asset in the
foreseeable future. Due to annual limitations on the utilization of Brazil net operating loss
carryforwards, we would need to generate more than $400 million of taxable income in Brazil to fully
realize the deferred tax asset.
We have not provided U.S. federal income taxes on indefinitely (or permanently) reinvested
cumulative earnings of approximately $396.1 million generated by our non-U.S. subsidiaries. Such
earnings are from ongoing operations which will be used to fund international growth. We have not
recorded a deferred tax liability related to these unremitted foreign earnings as it is not practicable to
estimate the amount of unrecognized deferred tax liabilities. In the event of a distribution of those
earnings to the U.S. in the form of dividends, we may be subject to both foreign withholding taxes and
U.S. federal income taxes net of allowable foreign tax credits.
A reconciliation of the beginning and ending amount of unrecognized tax benefits (including
discontinued operations) is shown below (in thousands):
Years Ended December 31,
2012
2011
2010
Beginning balance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Additions based on tax positions related to current year . . . . . . . . . . . . .
Additions based on tax positions related to prior years . . . . . . . . . . . . . .
Reductions based on settlement with government authority . . . . . . . . . . .
Reductions based on lapse of statute of limitations . . . . . . . . . . . . . . . . .
Reductions based on tax positions related to prior years . . . . . . . . . . . . .
$14,745
289
1,579
(5,753)
(1,263)
—
$15,614
—
—
—
(167)
(702)
$19,756
—
—
—
—
(4,142)
Ending balance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 9,597
$14,745
$15,614
We had $9.6 million, $14.7 million and $15.6 million of unrecognized tax benefits at December 31,
2012, 2011 and 2010, respectively, which if recognized would affect the effective tax rate (except for
amounts that would be reflected in Income (loss) from discontinued operations, net of tax). We also
have recorded $2.4 million, $11.9 million and $10.6 million of potential interest expense and penalties
F-33
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related to unrecognized tax benefits associated with uncertain tax positions (including discontinued
operations) as of December 31, 2012, 2011 and 2010, respectively. To the extent interest and penalties
are not assessed with respect to uncertain tax positions, amounts accrued will be reduced and reflected
as reductions in income tax expense.
We and our subsidiaries file consolidated and separate income tax returns in the U.S. federal
jurisdiction and in numerous state and foreign jurisdictions. We are subject to U.S. federal income tax
examinations for tax years beginning from 1997 onward and, early in the second quarter of 2011, the
Internal Revenue Service (‘‘IRS’’) commenced an examination of our U.S. federal income tax returns
for the tax years 2006, 2008 and 2009. In October 2012, the IRS completed its examination and issued
Revenue Agent’s Reports (‘‘RARs’’) that reflected an aggregate over-assessment of $0.8 million. All of
the adjustments proposed in the RARs were agreed, except for the disallowance of our telephone
excise tax refund claims of $0.5 million related to the 2006 tax year, for which we filed protests with the
Appeals Division of the IRS. We do not expect any tax adjustments that would have a material impact
on our financial position or results of operations.
State income tax returns are generally subject to examination for a period of three to five years
after filing the returns. However, the state impact of any U.S. federal audit adjustments and
amendments remains subject to examination by various states for up to one year after formal
notification to the states. As of December 31, 2012, we did not have any state audits underway that
would have a material impact on our financial position or results of operations.
We are subject to examination by taxing authorities throughout the world, including major foreign
jurisdictions such as Argentina, Brazil, Canada, Italy and Mexico. With few exceptions, we and our
subsidiaries are no longer subject to foreign income tax examinations for tax years before 2002. Several
foreign audits are currently in progress and we do not expect any tax adjustments that would have a
material impact on our financial position or results of operations.
We believe it is reasonably possible that a decrease of up to $2.0 million in unrecognized tax
benefits may be necessary on or before December 31, 2013 due to the settlement of audits and the
expiration of statutes of limitations. However, due to the uncertain and complex application of tax
regulations, it is possible that the ultimate resolution of these matters may result in liabilities which
could materially differ from these estimates.
16. Common Stockholders’ Equity
The Exterran Holdings, Inc. 2007 Amended and Restated Stock Incentive Plan (the ‘‘2007 Plan’’)
allows us to withhold shares to use upon vesting of restricted stock at the then current market price to
cover taxes required to be withheld on the vesting date. We purchased 157,233 of our shares from
participants for approximately $2.4 million during 2012 to cover tax withholding. The 2007 Plan is
administered by the compensation committee of our board of directors.
F-34
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MERRILL CORPORATION JBAKER// 4-MAR-13 11:47 DISK106:[12ZDS4.12ZDS78704]FW78704A.;9
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DISK024:[PAGER.PSTYLES]UNIVERSAL.BST;102
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17. Stock-based Compensation and Awards
The following table presents the stock-based compensation expense included in our results of
operations (in thousands):
Stock options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restricted stock, restricted stock units, cash settled restricted stock units,
cash settled performance awards and phantom units . . . . . . . . . . . . . .
Employee stock purchase plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Years Ended December 31,
2012
2011
2010
$ 2,552
$ 3,916
$ 5,273
16,583
114
14,970
278
17,796
282
Total stock-based compensation expense . . . . . . . . . . . . . . . . . . . . . . . .
$19,249
$19,164
$23,351
Stock Incentive Plan
In August 2007, we adopted the 2007 Plan that provides for the granting of stock-based awards in
the form of options, restricted stock, restricted stock units, stock appreciation rights and performance
awards to our employees and directors. In May 2011, our stockholders approved an amendment to the
2007 Plan increasing the aggregate number of shares of common stock available under the 2007 Plan to
12,500,000. Each option and stock appreciation right granted counts as one share against the aggregate
share limit, and each share of restricted stock and each restricted stock unit granted counts as two
shares against the aggregate share limit. Awards granted under the 2007 Plan that are subsequently
cancelled, terminated or forfeited are available for future grant, and cash settled awards are not
counted against the aggregate share limit.
Stock Options
Under the 2007 Plan, stock options are granted at fair market value at the date of grant, are
exercisable in accordance with the vesting schedule established by the compensation committee of our
board of directors in its sole discretion and expire no later than seven years after the date of grant.
Options generally vest 331⁄3% on each of the first three anniversaries of the grant date.
The weighted average grant date fair value for options granted during the years ended
December 31, 2012, 2011 and 2010 was $5.74, $5.81 and $8.71, respectively, and was estimated using
the Black-Scholes option valuation model with the following weighted average assumptions:
Years Ended December 31,
2012
2011
2010
Expected life in years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Risk-free interest rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Volatility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividend yield . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.5
4.5
4.5
0.78% 1.23% 2.13%
47.96% 45.17% 42.94%
0.0% 0.0% 0.0%
The risk-free interest rate is based on the U.S. Treasury yield curve in effect on the grant date for
a period commensurate with the estimated expected life of the stock options. Expected volatility is
based on the historical volatility of our stock over the period commensurate with the expected life of
the stock options and other factors. We have not historically paid a dividend and do not expect to pay
a dividend during the expected life of the stock options.
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DISK024:[PAGER.PSTYLES]UNIVERSAL.BST;102
2 C Cs: 55698
The following table presents stock option activity for the year ended December 31, 2012 (in
thousands, except per share data and remaining life in years):
Options outstanding, December 31, 2011 . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cancelled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stock
Options
3,271
153
(34)
(806)
Options outstanding, December 31, 2012 . . . . . . . . . . . . .
2,584
Options exercisable, December 31, 2012 . . . . . . . . . . . . . .
1,828
Weighted
Average
Exercise Price
Weighted
Average
Remaining
Life
Aggregate
Intrinsic
Value
$27.39
14.36
16.41
26.55
27.02
31.99
4.6
3.6
$10,866
5,425
Intrinsic value is the difference between the market value of our stock and the exercise price of
each option multiplied by the number of options outstanding for those options where the market value
exceeds their exercise price. The total intrinsic value of stock options exercised during 2012, 2011 and
2010 was $0.1 million, $0.2 million and $0.5 million, respectively. As of December 31, 2012, we expect
$2.6 million of unrecognized compensation cost related to unvested stock options to be recognized over
the weighted-average period of 1.6 years.
Restricted Stock, Restricted Stock Units, Cash Settled Restricted Stock Units and Cash Settled
Performance Awards
For grants of restricted stock and restricted stock units, we recognize compensation expense over
the vesting period equal to the fair value of our common stock at the date of grant. We remeasure the
fair value of cash settled restricted stock units and cash settled performance awards and record a
cumulative adjustment of the expense previously recognized. Our obligation related to the cash settled
restricted stock units and cash settled performance awards is reflected as a liability in our consolidated
balance sheets. Our grants of restricted stock, restricted stock units, cash settled restricted stock units
and cash settled performance awards generally vest 331⁄3% on each of the first three anniversaries of
the grant date.
The following table presents restricted stock, restricted stock unit, cash settled restricted stock unit
and cash settled performance award activity for the year ended December 31, 2012 (in thousands,
except per share data):
Non-vested awards, December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in expected vesting of cash settled performance awards . . . . . . . . . . . . .
Cancelled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Shares
1,670
1,221
(772)
44
(171)
Non-vested awards, December 31, 2012(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,992
Weighted
Average
Grant-Date
Fair Value
Per Share
$19.49
14.33
19.09
14.36
22.39
16.12
(1) Non-vested awards as of December 31, 2012 are comprised of 545 thousand cash settled restricted
stock units and cash settled performance awards and 1,447 thousand restricted stock shares and
stock settled restricted stock units.
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As of December 31, 2012, $22.6 million of unrecognized compensation cost related to unvested
restricted stock, restricted stock units, cash settled restricted stock units and cash settled performance
awards is expected to be recognized over the weighted-average period of 1.7 years.
Employee Stock Purchase Plan
In August 2007, we adopted the Exterran Holdings, Inc. Employee Stock Purchase Plan (‘‘ESPP’’),
which is intended to provide employees with an opportunity to participate in our long-term
performance and success through the purchase of shares of common stock at a price that may be less
than fair market value. The ESPP is designed to comply with Section 423 of the Internal Revenue
Code of 1986, as amended. Each quarter, an eligible employee may elect to withhold a portion of his
or her salary up to the lesser of $25,000 per year or 10% of his or her eligible pay to purchase shares
of our common stock at a price equal to 85% to 100% of the fair market value of the stock as of the
first trading day of the quarter, the last trading day of the quarter or the lower of the first trading day
of the quarter and the last trading day of the quarter, as the compensation committee of our board of
directors may determine. The ESPP will terminate on the date that all shares of common stock
authorized for sale under the ESPP have been purchased, unless it is extended. In May 2011, our
stockholders approved an amendment to the ESPP that increased the aggregate number of shares of
common stock available for purchase under the ESPP to 1,000,000. At December 31, 2012, 304,548
shares remained available for purchase under the ESPP. Our ESPP is compensatory and, as a result, we
record an expense on our consolidated statements of operations related to the ESPP. Since July 2009,
the purchase discount under the ESPP has been 5% of the fair market value of our common stock on
the first trading day of the quarter or the last trading day of the quarter, whichever is lower.
Directors’ Stock and Deferral Plan
On August 20, 2007, we adopted the Exterran Holdings, Inc. Directors’ Stock and Deferral Plan to
provide non-employee members of the board of directors with an opportunity to elect to receive our
common stock as payment for a portion or all of their retainer and meeting fees. The number of shares
paid each quarter is determined by dividing the dollar amount of fees elected to be paid in common
stock by the closing sales price per share of the common stock on the last day of the quarter. In
addition, directors who elect to receive a portion or all of their fees in the form of common stock may
also elect to defer, until a later date, the receipt of a portion or all of their fees to be received in
common stock. We have reserved 100,000 shares under the Directors’ Stock and Deferral Plan, and as
of December 31, 2012, 59,052 shares remain available to be issued under the plan.
Employment Inducement Plan
In anticipation of certain key management changes, in November 2011 our board of directors
adopted the Exterran Holdings, Inc. 2011 Employment Inducement Long-Term Equity Plan (the
‘‘Employment Inducement Plan’’), which authorizes the issuance of up to 1,000,000 of non-qualified
stock options, restricted stock, restricted stock units, stock appreciation rights and performance awards
to certain newly-hired employees of us or our affiliates. The Employment Inducement Plan is only
available to grant awards to an individual, as a material inducement to such individual to enter into
employment with us, who (i) has not previously been an employee of us or our affiliates or (ii) is
rehired following a bona fide period of non-employment with us and our affiliates. Awards granted
under the Employment Inducement Plan that are subsequently cancelled, terminated or forfeited are
available for future grant. As of December 31, 2012, 539,982 shares remain available to be issued under
the Employment Inducement Plan. We do not intend to issue any additional equity under the
Employment Inducement Plan, other than as necessary to materially induce a high-level executive to
enter into employment with us.
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2 C Cs: 2607
Partnership Long-Term Incentive Plan
The Partnership has a long-term incentive plan (the ‘‘Plan’’) that was adopted by
Exterran GP LLC, the general partner of the Partnership’s general partner, in October 2006 for
employees, directors and consultants of the Partnership, us and our respective affiliates. An aggregate
of 1,035,378 common units, common unit options, restricted units and phantom units is available under
the Plan. The Plan is administered by the board of directors of Exterran GP LLC or a committee
thereof (the ‘‘Plan Administrator’’).
Phantom units are notional units that entitle the grantee to receive a common unit upon the
vesting of the phantom unit or, at the discretion of the Plan Administrator, cash equal to the fair value
of a common unit.
Partnership Phantom Units
During the year ended December 31, 2012, the Partnership granted 29,717 phantom units to
officers and directors of Exterran GP LLC and certain of our employees, which vest 331⁄3% on each of
the first three anniversaries of the grant date.
The following table presents phantom unit activity for the year ended December 31, 2012:
Phantom units outstanding, December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cancelled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Phantom
Units
75,267
29,717
(40,329)
(771)
Phantom units outstanding, December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . .
63,884
Weighted
Average
Grant-Date
Fair Value
per Unit
$21.45
22.62
18.73
28.50
23.62
As of December 31, 2012, $1.0 million of unrecognized compensation cost related to unvested
phantom units is expected to be recognized over the weighted-average period of 1.7 years.
18. Retirement Benefit Plan
Our 401(k) retirement plan provides for optional employee contributions up to the Internal
Revenue Service limit and discretionary employer matching contributions. We make discretionary
matching contributions to each participant’s account at a rate of (i) 100% of each participant’s first 1%
of contributions plus (ii) 50% of each participant’s contributions up to the next 5% of eligible
compensation. We made no discretionary matching contributions from July 1, 2009 through June 30,
2010, but began making them again effective on July 1, 2010. We recorded matching contributions of
$7.6 million, $8.7 million and $3.9 million during 2012, 2011 and 2010, respectively.
19. Transactions Related to the Partnership
In March 2012, we sold to the Partnership contract operations customer service agreements with
39 customers and a fleet of 406 compressor units used to provide compression services under those
agreements, comprising approximately 188,000 horsepower, or 5% (by then available horsepower) of
our and the Partnership’s combined U.S. contract operations business. The assets sold also included
139 compressor units, comprising approximately 75,000 horsepower, that we previously leased to the
Partnership, and a natural gas processing plant with a capacity of 10 million cubic feet per day used to
provide processing services. Total consideration for the transaction was approximately $182.8 million,
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excluding transaction costs, and consisted of the Partnership’s payment of $77.4 million in cash and
assumption of $105.4 million of our long-term debt.
In March 2012, the Partnership sold, pursuant to a public underwritten offering, 4,965,000 common
units representing limited partner interests in the Partnership, including 465,000 common units sold
pursuant to an over-allotment option. The Partnership used the $114.5 million of net proceeds from
this offering to repay borrowings outstanding under its revolving credit facility. In connection with this
sale and as permitted under the Partnership’s partnership agreement, the Partnership issued and sold to
Exterran General Partner, L.P. (‘‘GP’’), our wholly-owned subsidiary and the Partnership’s general
partner, approximately 101,000 general partner units in consideration of the continuation of GP’s
approximate 2.0% general partner interest in the Partnership. The change in our ownership interest in
the Partnership resulting from the sale of the common units resulted in adjustments to noncontrolling
interest, accumulated other comprehensive income (loss), deferred income taxes and additional paid-in
capital to reflect our new ownership percentage in the Partnership.
In June 2011, we sold to the Partnership contract operations customer service agreements with
34 customers and a fleet of 407 compressor units used to provide compression services under those
agreements, comprising approximately 289,000 horsepower, or 8% (by then available horsepower) of
our and the Partnership’s combined U.S. contract operations business (the ‘‘June 2011 Contract
Operations Acquisition’’). In addition, the assets sold included 207 compressor units, comprising
approximately 98,000 horsepower, that we previously leased to the Partnership, and a natural gas
processing plant with a capacity of 8 million cubic feet per day used to provide processing services.
Total consideration for the transaction was approximately $223.0 million, excluding transaction costs. In
connection with this acquisition, the Partnership assumed $159.4 million of our debt, paid us
$62.2 million in cash and issued approximately 51,000 general partner units to GP.
In May 2011, the Partnership sold, pursuant to a public underwritten offering, 5,134,175 common
units representing limited partner interests in the Partnership, including 134,175 common units sold
pursuant to an over-allotment option. The Partnership used the $127.7 million of net proceeds from
this offering (i) to repay approximately $64.8 million of borrowings outstanding under its revolving
credit facility and (ii) for general partnership purposes, including to fund a portion of the consideration
for the June 2011 Contract Operations Acquisition. In connection with this sale and as permitted under
the Partnership’s partnership agreement, the Partnership issued and sold to GP approximately 53,000
general partner units in consideration of the continuation of GP’s approximate 2.0% general partner
interest in the Partnership. The change in our ownership interest in the Partnership resulting from the
sale of the common units resulted in adjustments to noncontrolling interest, accumulated other
comprehensive income (loss), deferred income taxes and additional paid-in capital to reflect our new
ownership percentage in the Partnership.
In March 2011, we sold, pursuant to a public underwritten offering, 5,914,466 common units
representing limited partner interests in the Partnership, including 664,466 common units sold pursuant
to an over-allotment option. We used the $162.2 million of net proceeds received from the sale of the
common units to repay borrowings under our revolving credit facility and term loan. The change in our
ownership interest in the Partnership resulting from the sale of the common units resulted in
adjustments to noncontrolling interest, accumulated other comprehensive income (loss), deferred
income taxes and additional paid-in capital to reflect our new ownership percentage in the Partnership.
In September 2010, we sold, pursuant to a public underwritten offering, 5,290,000 common units
representing limited partner interests in the Partnership, including 690,000 common units sold pursuant
to an over-allotment option. We used the $109.4 million of net proceeds received from the sale of the
common units to repay borrowings under our revolving credit facility and term loan. The change in our
ownership interest in the Partnership from the sale of the common units resulted in adjustments to
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MERRILL CORPORATION JBAKER// 4-MAR-13 11:47 DISK106:[12ZDS4.12ZDS78704]FY78704A.;11
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2 C Cs: 15851
noncontrolling interest, accumulated other comprehensive income (loss) and additional paid-in capital
to reflect our new ownership percentage in the Partnership.
In August 2010, we sold to the Partnership contract operations customer service agreements with
43 customers and a fleet of approximately 580 compressor units used to provide compression services
under those agreements, comprising approximately 255,000 horsepower, or approximately 6% (by then
available horsepower) of our combined U.S. contract operations business. Total consideration for the
transaction was approximately $214.0 million, excluding transaction costs. In connection with this
acquisition, the Partnership issued to our wholly-owned subsidiaries approximately 8.2 million common
units and approximately 167,000 general partner units.
Through our wholly-owned subsidiaries, we owned all of the subordinated units of the Partnership.
As of each of June 30, 2011 and 2010, the Partnership met the requirements under its partnership
agreement for early conversion of 1,581,250 of these subordinated units into common units.
Accordingly, in each of August 2011 and 2010, 1,581,250 subordinated units converted into common
units. As of September 30, 2011, the Partnership met the requirements under its partnership agreement
for conversion of all remaining subordinated units into common units and therefore, the remaining
3,162,500 subordinated units converted into common units in November 2011.
The table below presents the effects of changes from net loss attributable to Exterran stockholders
and changes in our equity interest of the Partnership on our equity attributable to Exterran’s
stockholders (in thousands):
Net loss attributable to Exterran stockholders . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in Exterran stockholders’ additional paid in capital for sale of
Years Ended
December 31,
2012
2011
$(39,486) $(340,608)
Partnership units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
49,202
123,904
Change from net loss attributable to Exterran stockholders and transfers to the
noncontrolling interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 9,716
$(216,704)
20. Commitments and Contingencies
Rent expense for 2012, 2011 and 2010 was approximately $22.2 million, $22.9 million and
$21.7 million, respectively. Commitments for future minimum rental payments with terms in excess of
one year at December 31, 2012 are as follows (in thousands):
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31,
2012
$12,930
9,067
7,901
6,682
6,203
22,922
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$65,705
F-40
EXTERRAN HOLDINGS INC. 10-K
Proj: P30087HOU12 Job: 12ZDS78704 (12-30087-4)
Page Dim: 8.250(cid:1) X 10.750(cid:1) Copy Dim: 38. X 54.3
File: FY78704A.;11
MERRILL CORPORATION JBAKER// 4-MAR-13 11:47 DISK106:[12ZDS4.12ZDS78704]FY78704A.;11
mrll_1111.fmt Free: 175D*/0D Foot: 0D/ 0D VJ RSeq: 6 Clr: 0
DISK024:[PAGER.PSTYLES]UNIVERSAL.BST;102
2 C Cs: 8720
We have issued the following guarantees that are not recorded on our accompanying balance sheet
(dollars in thousands):
Maximum Potential
Undiscounted
Payments as of
December 31, 2012
Term
Performance guarantees through letters of credit(1) . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Standby letters of credit
Commercial letters of credit
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Bid bonds and performance bonds(1) . . . . . . . . . . . . . . . . . . . . . . . . .
2013 - 2017
2013
2013
2013 - 2018
Maximum potential undiscounted payments . . . . . . . . . . . . . . . . . . . .
$246,017
13,466
1,736
82,325
$343,544
(1) We have issued guarantees to third parties to ensure performance of our obligations, some of
which may be fulfilled by third parties.
As part of an acquisition in 2001, we may be required to make contingent payments of up to
$46 million to the seller, depending on our realization of certain U.S. federal tax benefits through the
year 2015. To date, we have not realized any such benefits that would require a payment and we do not
anticipate realizing any such benefits that would require a payment before the year 2016.
See Note 2 and Note 7 for a discussion of gain contingencies related to assets and investments that
were expropriated in Venezuela.
The Texas Legislature enacted changes related to the appraisal of natural gas compressors for ad
valorem taxes by expanding the definitions of ‘‘Heavy Equipment Dealer’’ and ‘‘Heavy Equipment.’’
Under the revised statute, we believe we are a Heavy Equipment Dealer and that our natural gas
compressors are Heavy Equipment and are, therefore, required to file the 2012 property tax renditions
under this new methodology. As a result of filing as a Heavy Equipment Dealer in Texas counties, a
number of Appraisal Review Boards have denied our position and we are currently filing petitions for
review in district courts.
As a result of the new methodology, our ad valorem tax expense (which is reflected on our
consolidated statements of operations as a component of Cost of goods sold (excluding depreciation
and amortization expense)) includes a benefit of $6.8 million, of which approximately $1.5 million has
been agreed to by a number of Appraisal Review Boards, for the year ended December 31, 2012.
In addition to federal and state income taxes, we are subject to a number of state and local taxes
that are not income-based. Many of these taxes are subject to audit by the taxing authorities, and
therefore, it is possible that an audit could result in our making additional tax payments. We accrue for
such additional tax payments resulting from an audit when we determine that it is probable that we
have incurred a liability and we can reasonably estimate the amount of the liability. We do not believe
that such payments would be material to our consolidated financial position but cannot provide
assurance that the resolution of an audit would not be material to our results of operations or cash
flows for the period in which the resolution occurs.
Our business can be hazardous, involving unforeseen circumstances such as uncontrollable flows of
natural gas or well fluids and fires or explosions. As is customary in our industry, we review our safety
equipment and procedures and carry insurance against some, but not all, risks of our business. Our
insurance coverage includes property damage, general liability and commercial automobile liability and
other coverage we believe is appropriate. In addition, we have a minimal amount of insurance on our
offshore assets. We believe that our insurance coverage is customary for the industry and adequate for
our business; however, losses and liabilities not covered by insurance would increase our costs.
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Additionally, we are substantially self-insured for worker’s compensation and employee group
health claims in view of the relatively high per-incident deductibles we absorb under our insurance
arrangements for these risks. Losses up to the deductible amounts are estimated and accrued based
upon known facts, historical trends and industry averages.
In the ordinary course of business, we are involved in various pending or threatened legal actions.
While management is unable to predict the ultimate outcome of these actions, we believe that any
ultimate liability arising from these actions will not have a material adverse effect on our consolidated
financial position, results of operations or cash flows. Because of the inherent uncertainty of litigation,
however, we cannot provide assurance that the resolution of any particular claim or proceeding to
which we are a party will not have a material adverse effect on our consolidated financial position,
results of operations or cash flows for the period in which the resolution occurs.
21. Recent Accounting Developments
In May 2011, the FASB issued an update to provide a consistent definition of fair value and ensure
that the fair value measurement and disclosure requirements are similar between GAAP and
International Financial Reporting Standards. This update changes certain fair value measurement
principles and enhances the disclosure requirements particularly for Level 3 fair value measurements.
This update is effective for interim and annual periods beginning on or after December 15, 2011. Our
adoption of this new guidance on January 1, 2012 did not have a material impact on our consolidated
financial statements.
In June 2011, the FASB issued an update on the presentation of other comprehensive income.
Under this update, entities will be required to present the total of comprehensive income, the
components of net income and the components of other comprehensive income either in a single
continuous statement of comprehensive income or in two separate but consecutive statements. The
current option to report other comprehensive income and its components in the statement of changes
in equity has been eliminated. This update is effective for interim and annual periods beginning on or
after December 15, 2011. Our adoption of this new guidance on January 1, 2012 did not have a
material impact on our consolidated financial statements.
In September 2011, the FASB issued an update allowing entities to use a qualitative approach to
test goodwill for impairment. Under this update, entities are permitted to first perform a qualitative
assessment to determine whether it is more likely than not that the fair value of a reporting unit is less
than its carrying value. If it is concluded that this is the case, it is necessary to perform the currently
prescribed two-step goodwill impairment test. Otherwise, the two-step goodwill impairment test is not
required. This update is effective for annual and interim goodwill impairment tests performed for fiscal
years beginning after December 15, 2011. Our adoption of this new guidance on January 1, 2012 did
not have a material impact on our consolidated financial statements.
22. Reportable Segments and Geographic Information
We manage our business segments primarily based upon the type of product or service provided.
We have four reportable segments: North America contract operations, international contract
operations, aftermarket services and fabrication. The North America and international contract
operations segments primarily provide natural gas compression services, production and processing
equipment services and maintenance services to meet specific customer requirements on Exterran-
owned assets. The aftermarket services segment provides a full range of services to support the surface
production, compression and processing needs of customers, from parts sales and normal maintenance
services to full operation of a customer’s owned assets. The fabrication segment provides (i) design,
engineering, fabrication, installation and sale of natural gas compression units and accessories and
equipment used in the production, treating and processing of crude oil and natural gas and
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(ii) engineering, procurement and fabrication services primarily related to the manufacturing of critical
process equipment for refinery and petrochemical facilities, the fabrication of tank farms and the
fabrication of evaporators and brine heaters for desalination plants.
We evaluate the performance of our segments based on gross margin for each segment. Revenues
include only sales to external customers. We do not include intersegment sales when we evaluate the
performance of our segments.
No individual customer accounted for more than 10% of our consolidated revenues during any of
the periods presented. The following table presents sales and other financial information by reportable
segment for the years ended December 31, 2012, 2011 and 2010 (in thousands):
North
America
Contract
Operations
International
Contract
Operations
Aftermarket
Services
Fabrication
Reportable
Segments
Total
Other(1)
Total(2)
2012:
Revenue from
external customers . $ 605,367
316,123
1,846,447
247,021
Gross margin(3) . . . .
Total assets . . . . . . . .
Capital expenditures .
$463,957
279,349
918,187
138,694
2011:
Revenue from
external customers . $ 588,034
284,984
1,982,513
182,178
Gross margin(3) . . . .
Total assets . . . . . . . .
Capital expenditures .
$445,059
260,654
887,046
58,767
2010:
Revenue from
external customers . $ 592,055
300,431
1,981,757
106,720
Gross margin(3) . . . .
Total assets . . . . . . . .
Capital expenditures .
$465,144
289,787
976,700
106,530
$385,861 $1,348,417 $2,803,602 $
156,480
469,520
23,518
834,223
3,332,258
412,537
82,271
98,104
3,304
— $2,803,602
— 834,223
4,233,101
428,731
900,843
16,194
$371,327 $1,225,459 $2,629,879 $
123,222
384,099
22,077
728,427
3,345,827
264,790
59,567
92,169
1,768
— $2,629,879
— 728,427
4,242,778
272,185
896,951
7,395
$293,757 $1,066,227 $2,417,183 $
161,505
580,255
12,187
797,088
3,683,266
226,769
45,365
144,554
1,332
— $2,417,183
— 797,088
4,611,742
231,607
928,476
4,838
The following table presents assets from reportable segments to total assets as of December 31,
2012 and 2011 (in thousands):
Assets from reportable segments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Assets associated with discontinued operations . . . . . . . . . . . . . . . . . . . . . . .
$3,332,258
900,843
21,746
$3,345,827
896,951
117,884
Consolidated assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$4,254,847
$4,360,662
Years Ended December 31,
2012
2011
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MERRILL CORPORATION JBAKER// 4-MAR-13 11:47 DISK106:[12ZDS4.12ZDS78704]GA78704A.;8
mrll_1111.fmt Free: 95D*/120D Foot: 0D/ 0D VJ RSeq: 3 Clr: 0
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2 C Cs: 43875
The following table presents geographic data as of and for the years ended December 31, 2012,
2011 and 2010 (in thousands):
2012:
Revenues from external customers . . . . . . . . . . . . . . . . . . . .
Property, plant and equipment, net . . . . . . . . . . . . . . . . . . . .
$1,820,069
$1,882,580
$ 983,533
$ 959,451
$2,803,602
$2,842,031
U.S.
International
Consolidated
2011:
Revenues from external customers . . . . . . . . . . . . . . . . . . . .
Property, plant and equipment, net . . . . . . . . . . . . . . . . . . . .
$1,453,758
$1,993,082
$1,176,121
$ 941,582
$2,629,879
$2,934,664
2010:
Revenues from external customers . . . . . . . . . . . . . . . . . . . .
Property, plant and equipment, net . . . . . . . . . . . . . . . . . . . .
$1,090,096
$1,985,180
$1,327,087
$1,029,418
$2,417,183
$3,014,598
(1) Includes corporate related items.
(2) Totals exclude assets, capital expenditures and the operating results of discontinued operations.
(3) Gross margin, a non-GAAP financial measure, is reconciled to net income (loss) below.
We define gross margin as total revenue less cost of sales (excluding depreciation and amortization
expense). Gross margin is included as a supplemental disclosure because it is a primary measure used
by our management to evaluate the results of revenue and cost of sales (excluding depreciation and
amortization expense), which are key components of our operations. As an indicator of our operating
performance, gross margin should not be considered an alternative to, or more meaningful than, net
income (loss) as determined in accordance with GAAP. Our gross margin may not be comparable to a
similarly titled measure of another company because other entities may not calculate gross margin in
the same manner.
The following table reconciles net loss to gross margin (in thousands):
Net loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selling, general and administrative . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-lived asset impairment
. . . . . . . . . . . . . . . . . . . . . . . . . . .
Restructuring charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill impairment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity in (income) loss of non-consolidated affiliates . . . . . . . . . .
Other (income) expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefit from income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(Income) loss from discontinued operations, net of tax . . . . . . . .
Years Ended December 31,
2012
2011
2010
$ (37,169) $(339,618) $(113,241)
351,998
352,780
376,359
392,153
356,972
350,847
143,874
6,068
183,445
—
11,594
6,636
196,807
—
—
136,149
149,473
134,376
(51,483)
609
471
(11,413)
(5,620)
430
(62,302)
(10,605)
(62,375)
(40,739)
10,105
(66,843)
Gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$834,223
$ 728,427
$ 797,088
23. Supplemental Guarantor Financial Information
Exterran Energy Corp., our 100% owned subsidiary, was the original issuer of the 4.75% Notes,
which Exterran Holdings, Inc. (‘‘Parent’’) had agreed to fully and unconditionally guarantee. In the
second quarter of 2012, in connection with an organizational restructuring of certain of our subsidiaries,
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Exterran Energy Corp. distributed and assigned substantially all its assets and liabilities, including its
obligations under the 4.75% Notes, to Parent. As a result, Parent became the direct obligor under the
4.75% Notes; therefore, subsidiary issuer financial information for the 4.75% Notes is no longer
provided in this footnote.
Parent is the issuer of the 7.25% Notes. Exterran Energy Solutions, L.P., EES Leasing LLC,
EXH GP LP LLC and EXH MLP LP LLC (each a 100% owned subsidiary; together, the ‘‘Guarantor
Subsidiaries’’), have agreed to fully and unconditionally guarantee Parent’s obligations relating to the
7.25% Notes. As a result of these guarantees, we are presenting the following condensed consolidating
financial information pursuant to Rule 3-10 of Regulation S-X. These schedules are presented using the
equity method of accounting for all periods presented. Under this method, investments in subsidiaries
are recorded at cost and adjusted for our share in the subsidiaries’ cumulative results of operations,
capital contributions and distributions and other changes in equity. Elimination entries relate primarily
to the elimination of investments in subsidiaries and associated intercompany balances and transactions.
The Other Subsidiaries column includes financial information for those subsidiaries that do not
guarantee the 7.25% Notes.
Condensed Consolidating Balance Sheet
December 31, 2012
(In thousands)
Parent
Guarantor
Subsidiaries
Other
Subsidiaries
Eliminations
Consolidation
$
142
$ 754,303
$ 461,810
$
(33) $1,216,222
ASSETS
Current assets . . . . . . . . . . . . . . . . .
Current assets associated with
discontinued operations . . . . . . . .
Total current assets . . . . . . . . . . .
—
142
—
754,303
21,746
483,556
1,542,234
—
21,746
(33)
1,237,968
Property, plant and equipment, net . .
Investments in affiliates . . . . . . . . . .
Intangible and other assets, net . . . .
Intercompany receivables . . . . . . . . .
— 1,299,797
1,145,551
37,748
83,362
1,631,185
33,234
704,319
— (2,776,736)
(19,815)
(1,206,789)
123,681
419,108
— 2,842,031
—
174,848
—
Total long-term assets . . . . . . . . . .
2,368,738
2,566,458
2,085,023
(4,003,340)
3,016,879
Total assets . . . . . . . . . . . . . . . . .
$2,368,880
$3,320,761
$2,568,579
$(4,003,373) $4,254,847
Total current liabilities . . . . . . . . .
5,844
462,668
LIABILITIES AND EQUITY
Current liabilities . . . . . . . . . . . . . .
Current liabilities associated with
discontinued operations . . . . . . . .
Long-term debt . . . . . . . . . . . . . . . .
Intercompany payables . . . . . . . . . .
Other long-term liabilities . . . . . . . .
Long-term liabilities associated with
discontinued operations . . . . . . . .
$
5,844
$ 462,668
$ 294,529
$
(74) $ 762,967
—
—
884,423
—
— 1,123,427
103,481
—
11,572
306,101
680,500
83,362
128,375
—
(74)
11,572
774,539
— 1,564,923
—
212,082
(1,206,789)
(19,774)
—
—
1,044
—
1,044
Total liabilities . . . . . . . . . . . . . . .
890,267
1,689,576
1,199,382
(1,226,637)
2,552,588
Total equity . . . . . . . . . . . . . . . . . . .
1,478,613
1,631,185
1,369,197
(2,776,736)
1,702,259
Total liabilities and equity . . . . . . .
$2,368,880
$3,320,761
$2,568,579
$(4,003,373) $4,254,847
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Condensed Consolidating Balance Sheet
December 31, 2011
(In thousands)
ASSETS
Current assets . . . . . . . . . . . . . . . . .
Current assets associated with
discontinued operations . . . . . . . .
Total current assets . . . . . . . . . . .
Property, plant and equipment, net . .
Investments in affiliates . . . . . . . . . .
Intangible and other assets, net . . . .
Intercompany receivables . . . . . . . . .
Long-term assets associated with
discontinued operations . . . . . . . .
Parent
Guarantor
Subsidiaries
Other
Subsidiaries
Eliminations
Consolidation
$
94
$ 562,964
$ 522,193
$
12
$1,085,263
—
94
—
562,964
— 1,504,399
1,456,782
78,835
96,378
1,531,223
57,556
1,092,298
38,664
560,857
1,430,265
— (2,988,005)
(38,788)
(1,825,841)
125,248
637,165
—
12
38,664
1,123,927
— 2,934,664
—
222,851
—
—
—
79,220
—
79,220
Total long-term assets . . . . . . . . . .
2,681,077
3,136,394
2,271,898
(4,852,634)
3,236,735
Total assets . . . . . . . . . . . . . . . . .
$2,681,171
$3,699,358
$2,832,755
$(4,852,622) $4,360,662
Total current liabilities . . . . . . . . .
14,268
352,981
LIABILITIES AND EQUITY
Current liabilities . . . . . . . . . . . . . .
Current liabilities associated with
discontinued operations . . . . . . . .
Long-term debt . . . . . . . . . . . . . . . .
Intercompany payables . . . . . . . . . .
Other long-term liabilities . . . . . . . .
Long-term liabilities associated with
discontinued operations . . . . . . . .
$
14,268
$ 352,981
$ 299,408
$
(12,918) $ 653,739
—
—
1,227,399
—
— 1,705,911
109,243
2,268
16,142
315,550
545,640
119,930
137,359
—
16,142
(12,918)
669,881
— 1,773,039
—
223,012
(1,825,841)
(25,858)
—
—
14,688
—
14,688
Total liabilities . . . . . . . . . . . . . . .
1,243,935
2,168,135
1,133,167
(1,864,617)
2,680,620
Total equity . . . . . . . . . . . . . . . . . . .
1,437,236
1,531,223
1,699,588
(2,988,005)
1,680,042
Total liabilities and equity . . . . . . .
$2,681,171
$3,699,358
$2,832,755
$(4,852,622) $4,360,662
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Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)
Year Ended December 31, 2012
(In thousands)
Revenues . . . . . . . . . . . . . . . . . . . . . . . . .
$
— $1,766,798 $1,228,428 $(191,624) $2,803,602
Parent
Guarantor
Subsidiaries
Other
Subsidiaries Eliminations Consolidation
Costs of sales (excluding depreciation and
amortization expense) . . . . . . . . . . . . . . .
Selling, general and administrative . . . . . . .
Depreciation and amortization . . . . . . . . . .
Long-lived asset impairment . . . . . . . . . . . .
Restructuring charges
. . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . .
Other (income) expense:
Intercompany charges, net
. . . . . . . . . . .
Equity in income of affiliates . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . .
Loss before income taxes . . . . . . . . . . . . . .
Provision for (benefit from) income taxes . .
Loss from continuing operations . . . . . . . . .
Income from discontinued operations, net
— 1,393,194
203,067
788
136,236
—
100,617
—
4,019
—
9,551
99,236
(57,651)
11,744
40
(54,157)
(14,671)
49,753
(49,638)
(9,848)
(70,153)
(58,409)
767,809
172,504
214,611
82,828
2,617
25,589
7,898
(51,483)
10,238
(4,183)
10,705
(191,624)
—
—
—
—
—
1,969,379
376,359
350,847
183,445
6,636
134,376
—
37,894
—
—
(51,483)
430
(37,894)
—
(166,387)
(62,375)
(39,486)
(11,744)
(14,888)
(37,894)
(104,012)
of tax . . . . . . . . . . . . . . . . . . . . . . . . . .
—
—
Net income (loss) . . . . . . . . . . . . . . . . . . .
Less: Net income attributable to the
(39,486)
(11,744)
66,843
51,955
—
66,843
(37,894)
(37,169)
noncontrolling interest . . . . . . . . . . . . . .
—
—
(2,317)
—
(2,317)
Net income (loss) attributable to Exterran
stockholders . . . . . . . . . . . . . . . . . . . . . .
(39,486)
(11,744)
49,638
(37,894)
(39,486)
Other comprehensive income attributable to
Exterran stockholders . . . . . . . . . . . . . . .
Comprehensive income (loss) attributable to
Exterran stockholders . . . . . . . . . . . . . . .
17,850
10,292
3,888
(14,180)
17,850
$(21,636) $
(1,452) $
53,526 $ (52,074) $ (21,636)
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Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)
Year Ended December 31, 2011
(In thousands)
Parent
Guarantor
Subsidiaries
Other
Subsidiaries Eliminations Consolidation
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . $
— $1,363,693 $1,555,465 $(289,279) $2,629,879
Costs of sales (excluding depreciation and
amortization expense) . . . . . . . . . . . . . .
Selling, general and administrative . . . . . . .
Depreciation and amortization . . . . . . . . .
Long-lived asset impairment . . . . . . . . . . .
Restructuring charges . . . . . . . . . . . . . . . .
Goodwill impairment . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . .
Other (income) expense:
Intercompany charges, net . . . . . . . . . . .
Equity in loss of affiliates . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . .
— 1,091,719
175,523
550
149,658
—
4,724
—
—
—
147,541
—
2,634
106,243
1,099,012
176,707
207,314
1,344
11,594
49,266
40,596
(289,279)
—
—
—
—
—
—
1,901,452
352,780
356,972
6,068
11,594
196,807
149,473
(67,493)
315,023
40
67,493
100,239
(10,586)
—
471
4,926
—
(415,262)
—
—
471
(5,620)
Loss before income taxes . . . . . . . . . . . . .
Provision for (benefit from) income taxes . .
(354,363)
(13,755)
(365,252)
(50,229)
(35,765)
53,379
415,262
—
(340,118)
(10,605)
Loss from continuing operations . . . . . . . .
Loss from discontinued operations, net of
tax . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net loss . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Net income attributable to the
noncontrolling interest . . . . . . . . . . . . . .
Net loss attributable to Exterran
(340,608)
(315,023)
(89,144)
415,262
(329,513)
—
—
(10,105)
—
(10,105)
(340,608)
(315,023)
(99,249)
415,262
(339,618)
—
—
(990)
—
(990)
stockholders . . . . . . . . . . . . . . . . . . . . .
(340,608)
(315,023)
(100,239)
415,262
(340,608)
Other comprehensive income attributable
to Exterran stockholders . . . . . . . . . . . .
26,284
17,519
6,319
(23,838)
26,284
Comprehensive loss attributable to
Exterran stockholders . . . . . . . . . . . . . . $(314,324) $ (297,504) $ (93,920) $ 391,424
$ (314,324)
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Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)
Year Ended December 31, 2010
(In thousands)
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . $
— $1,046,815 $1,615,474 $(245,106) $2,417,183
Parent
Guarantor
Subsidiaries
Other
Subsidiaries Eliminations Consolidation
Costs of sales (excluding depreciation and
amortization expense) . . . . . . . . . . . . . .
Selling, general and administrative . . . . . . .
Depreciation and amortization . . . . . . . . .
Long-lived asset impairment . . . . . . . . . . .
Interest (income) expense . . . . . . . . . . . . .
Other (income) expense:
Intercompany charges, net . . . . . . . . . . .
Equity in (income) loss of affiliates . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . .
—
802
—
—
32,792
(41,697)
124,349
40
849,663
149,689
135,028
111,793
(10,173)
41,697
(23,268)
(15,295)
1,015,538
201,507
257,125
32,081
113,530
(245,106)
—
—
—
—
1,620,095
351,998
392,153
143,874
136,149
—
609
3,842
—
(101,081)
—
—
609
(11,413)
(216,282)
(62,302)
Loss before income taxes . . . . . . . . . . . . .
Provision for (benefit from) income taxes . .
(116,286)
(14,461)
(192,319)
(67,970)
(8,758)
20,129
101,081
—
Loss from continuing operations . . . . . . . .
Income from discontinued operations, net
of tax . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) . . . . . . . . . . . . . . . . . . .
Less: Net loss attributable to the
noncontrolling interest . . . . . . . . . . . . . .
Net income (loss) attributable to Exterran
(101,825)
(124,349)
(28,887)
101,081
(153,980)
—
—
(101,825)
(124,349)
40,739
11,852
—
40,739
101,081
(113,241)
—
—
11,416
—
11,416
stockholders . . . . . . . . . . . . . . . . . . . . .
(101,825)
(124,349)
23,268
101,081
(101,825)
Other comprehensive income attributable
to Exterran stockholders . . . . . . . . . . . .
6,773
2,501
1,625
(4,126)
6,773
Comprehensive income (loss) attributable
to Exterran stockholders . . . . . . . . . . . . $ (95,052) $ (121,848) $
24,893 $ 96,955
$ (95,052)
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Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2012
(In thousands)
Parent
Guarantor
Subsidiaries
Other
Subsidiaries
Eliminations
Consolidation
Cash flows from operating activities:
Net cash provided by (used in) continuing
operations . . . . . . . . . . . . . . . . . . . .
Net cash provided by discontinued
$
(6,877)
$ 127,305
$ 267,443
$
operations . . . . . . . . . . . . . . . . . . . .
—
—
2,054
Net cash provided by (used in) operating
activities . . . . . . . . . . . . . . . . . . . . .
(6,877)
127,305
269,497
Cash flows from investing activities:
Capital expenditures . . . . . . . . . . . . . . . .
Contract operations acquisition . . . . . . . . .
Proceeds from sale of property, plant and
equipment . . . . . . . . . . . . . . . . . . . . .
Capital distributions received from
consolidated subsidiaries . . . . . . . . . . . .
Increase in restricted cash . . . . . . . . . . . .
Return of investments in non-consolidated
affiliates
. . . . . . . . . . . . . . . . . . . . . .
Cash invested in non-consolidated affiliates .
Investment in consolidated subsidiaries . . . .
Net cash used in continuing operations . .
Net cash provided by discontinued
operations . . . . . . . . . . . . . . . . . . . .
Net cash used in investing activities . . . . .
Cash flows from financing activities:
Proceeds from borrowings of long-term debt
Repayments of long-term debt
. . . . . . . . .
Payments for debt issuance costs . . . . . . . .
Net proceeds from the sale of Partnership
units . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from stock options exercised . . . .
Proceeds from stock issued pursuant to our
employee stock purchase plan . . . . . . . .
Purchases of treasury stock . . . . . . . . . . . .
Stock-based compensation excess tax benefit
Distributions to noncontrolling partners in
the Partnership . . . . . . . . . . . . . . . . . .
Net proceeds from sale of general partner
units . . . . . . . . . . . . . . . . . . . . . . . . .
.
Capital contributions received from parent
Borrowings (repayments) between
—
—
—
—
—
—
—
—
—
—
—
(205,356)
77,415
(223,375)
(77,415)
14,511
30,782
—
—
—
(27,184)
21,489
—
(162)
51,707
(224)
—
(109,832)
(227,980)
—
(109,832)
135,959
(92,021)
714,000
(684,489)
(1,011)
114,530
—
—
—
—
1,164,000
(1,422,150)
—
—
562
1,635
(2,422)
1,139
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(30,782)
—
—
—
27,184
(3,598)
—
(3,598)
—
—
—
—
—
—
—
—
$
387,871
2,054
389,925
(428,731)
—
36,000
—
(162)
51,707
(224)
—
(341,410)
135,959
(205,451)
1,878,000
(2,106,639)
(1,011)
114,530
562
1,635
(2,422)
1,139
(87,866)
30,782
(57,084)
2,426
24,758
(2,426)
(24,758)
—
—
—
consolidated subsidiaries, net . . . . . . . . .
264,044
(9,822)
(254,222)
—
Net cash provided by (used in) financing
activities . . . . . . . . . . . . . . . . . . . . .
6,808
(9,822)
(171,874)
3,598
(171,290)
Effect of exchange rate changes on cash and
cash equivalents . . . . . . . . . . . . . . . . . . .
Net increase (decrease) in cash and cash
equivalents . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year . . . .
$
—
(486)
7,651
2,810
5,116
19,000
$ 10,461
$ 24,116
$
—
—
—
—
(486)
12,698
21,903
34,601
$
—
(69)
93
24
F-50
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MERRILL CORPORATION JBAKER// 4-MAR-13 12:21 DISK106:[12ZDS4.12ZDS78704]GI78704A.;9
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Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2011
(In thousands)
Parent
Guarantor
Subsidiaries
Other
Subsidiaries
Eliminations
Consolidation
Cash flows from operating activities:
Net cash provided by (used in) continuing
operations . . . . . . . . . . . . . . . . . . . . .
Net cash provided by discontinued operations
$
(1,191)
—
$ 62,519
—
$ 50,389
8,726
$
Net cash provided by (used in) operating
activities
. . . . . . . . . . . . . . . . . . . . . .
(1,191)
62,519
59,115
Cash flows from investing activities:
Capital expenditures . . . . . . . . . . . . . . . . . .
Contract operations acquisition . . . . . . . . . . .
Proceeds from sale of property, plant and
equipment . . . . . . . . . . . . . . . . . . . . . . .
Cash paid for business acquisition . . . . . . . . .
Capital distributions received from consolidated
subsidiaries . . . . . . . . . . . . . . . . . . . . . .
Decrease in restricted cash . . . . . . . . . . . . . .
Investment in consolidated subsidiaries . . . . . .
Cash invested in non-consolidated affiliates . . .
Return on investments in consolidated
—
—
—
—
—
—
—
—
(171,470)
62,217
(100,715)
(62,217)
13,423
(3,000)
30,766
—
(33,713)
—
29,619
—
—
820
—
(471)
—
—
—
—
—
—
—
(30,766)
—
33,713
—
subsidiaries . . . . . . . . . . . . . . . . . . . . . .
87,419
—
87,419
(174,838)
$
111,717
8,726
120,443
(272,185)
—
43,042
(3,000)
—
820
—
(471)
—
Net cash provided by (used in) continuing
operations . . . . . . . . . . . . . . . . . . . . .
Net cash used in discontinued operations . . .
Net cash provided by (used in) investing
87,419
—
(101,777)
—
(45,545)
(7,390)
(171,891)
—
(231,794)
(7,390)
activities
. . . . . . . . . . . . . . . . . . . . . .
87,419
(101,777)
(52,935)
(171,891)
(239,184)
Cash flows from financing activities:
. .
Proceeds from borrowings of long-term debt
Repayments of long-term debt
. . . . . . . . . . .
Payments for debt issuance costs . . . . . . . . . .
Net proceeds from the sale of Partnership units
Proceeds from stock options exercised . . . . . . .
Proceeds from stock issued pursuant to our
employee stock purchase plan . . . . . . . . . .
Purchases of treasury stock . . . . . . . . . . . . .
Stock-based compensation excess tax benefit . . .
Distributions to noncontrolling partners in the
Partnership . . . . . . . . . . . . . . . . . . . . . .
Net proceeds from sale of general partner units
Capital distributions to affiliates
. . . . . . . . . .
Capital contributions received from parent . . . .
Borrowings (repayments) between consolidated
subsidiaries, net
. . . . . . . . . . . . . . . . . . .
Net cash provided by (used in) financing
1,336,240
(1,409,644)
(7,666)
—
526
1,887
(2,941)
1,034
—
—
—
—
—
—
—
162,236
—
—
—
—
—
—
(87,419)
—
557,500
(626,527)
(1,157)
127,672
—
—
—
—
(70,636)
1,316
(87,419)
32,397
—
—
—
—
—
—
—
—
30,766
(1,316)
174,838
(32,397)
1,893,740
(2,036,171)
(8,823)
289,908
526
1,887
(2,941)
1,034
(39,870)
—
—
—
(5,731)
(34,285)
40,016
—
—
activities
. . . . . . . . . . . . . . . . . . . . . .
(86,295)
40,532
(26,838)
171,891
99,290
Effect of exchange rate changes on cash and cash
equivalents . . . . . . . . . . . . . . . . . . . . . . . .
Net increase (decrease) in cash and cash
equivalents . . . . . . . . . . . . . . . . . . . . . . . .
. .
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year . . . . . .
$
—
(67)
160
93
—
(3,007)
1,274
1,536
(23,665)
42,665
$
2,810
$ 19,000
$
—
—
—
—
(3,007)
(22,458)
44,361
$
21,903
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Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2010
(In thousands)
Parent
Guarantor
Subsidiaries
Other
Subsidiaries
Eliminations
Consolidation
Cash flows from operating activities:
Net cash provided by (used in) continuing
operations . . . . . . . . . . . . . . . . . . . .
Net cash used in discontinued operations .
Net cash provided by (used in) operating
$
(7,515)
—
$ 66,224
—
$
316,568
(8,964)
$
activities . . . . . . . . . . . . . . . . . . . . .
(7,515)
66,224
307,604
Cash flows from investing activities:
Capital expenditures . . . . . . . . . . . . . . . .
Proceeds from sale of property, plant and
equipment . . . . . . . . . . . . . . . . . . . . .
Capital distributions received from
consolidated subsidiaries . . . . . . . . . . . .
Decrease in restricted cash . . . . . . . . . . . .
Investment in consolidated subsidiaries . . . .
Cash invested in non-consolidated affiliates .
Return on investments in consolidated
—
—
—
—
—
—
(95,309)
(136,298)
13,970
7,758
32,460
—
(24,720)
—
—
12,930
—
(609)
(32,460)
—
24,720
—
—
—
—
—
—
$
375,277
(8,964)
366,313
(231,607)
21,728
—
12,930
—
(609)
subsidiaries . . . . . . . . . . . . . . . . . . . . .
109,556
—
109,556
(219,112)
—
Net cash provided by (used in) continuing
operations . . . . . . . . . . . . . . . . . . . .
Net cash provided by discontinued
109,556
(73,599)
(6,663)
(226,852)
(197,558)
operations . . . . . . . . . . . . . . . . . . . .
—
—
94,593
—
94,593
Net cash provided by (used in) investing
activities . . . . . . . . . . . . . . . . . . . . .
109,556
(73,599)
87,930
(226,852)
(102,965)
Cash flows from financing activities:
Proceeds from borrowings of long-term debt
Repayments of long-term debt
. . . . . . . . .
Payments for debt issuance costs . . . . . . . .
Net proceeds from the sale of Partnership
units . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from stock options exercised . . . .
Proceeds from stock issued pursuant to our
employee stock purchase plan . . . . . . . .
Purchases of treasury stock . . . . . . . . . . . .
Stock-based compensation excess tax benefit
Distributions to noncontrolling partners in
the Partnership . . . . . . . . . . . . . . . . . .
Capital distributions to affiliates . . . . . . . .
Capital contributions received from parent
.
Borrowings (repayments) between
1,627,244
(1,459,836)
(7,782)
—
—
—
471,000
(1,018,561)
(4,252)
—
840
109,365
—
2,224
(2,061)
1,182
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(109,556)
—
(50,490)
(109,556)
24,720
32,460
219,112
(24,720)
2,098,244
(2,478,397)
(12,034)
109,365
840
2,224
(2,061)
1,182
(18,030)
—
—
consolidated subsidiaries, net . . . . . . . . .
(263,741)
4,148
259,593
—
—
Net cash provided by (used in) financing
activities . . . . . . . . . . . . . . . . . . . . .
(101,930)
3,957
(427,546)
226,852
(298,667)
Effect of exchange rate changes on cash and
cash equivalents . . . . . . . . . . . . . . . . . . .
Net increase (decrease) in cash and cash
equivalents . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year . . . .
$
—
111
49
160
—
(1,872)
(3,418)
4,954
(33,884)
76,549
$
1,536
$
42,665
$
—
—
—
—
(1,872)
(37,191)
81,552
$
44,361
F-52
EXTERRAN HOLDINGS INC. 10-K
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24. Selected Quarterly Financial Data (Unaudited)
In management’s opinion, the summarized quarterly financial data below (in thousands, except per
share amounts) contains all appropriate adjustments, all of which are normally recurring adjustments,
considered necessary to present fairly our financial position and the results of operations for the
respective periods.
Revenue from external customers . . . . . . . . . . . . . .
Gross profit(6) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) attributable to Exterran
March 31,
2012(1)(2)
$615,241
109,056
June 30,
2012(3)
September 30,
2012(4)
December 31,
2012(5)
$ 630,735
(14,803)
$718,704
130,513
$838,922
137,809
stockholders . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5,495
(152,608)
113,366
(5,739)
Income (loss) per common share attributable to
Exterran stockholders:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revenue from external customers . . . . . . . . . . . . . . .
Gross profit(6) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net loss attributable to Exterran stockholders . . . . . .
Loss per common share attributable to Exterran
stockholders:
Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
0.09
0.09
(2.40)
(2.40)
$
1.75
1.74
$
(0.09)
(0.09)
March 31,
2011(2)
June 30,
2011
September 30,
2011(7)
December 31,
2011(8)
$606,928
105,424
(30,030)
$644,068
90,374
(28,026)
$ 689,820
105,284
(215,974)
$689,063
102,117
(66,578)
$
(0.48) $
(0.48)
(0.45)
(0.45)
$
(3.44)
(3.44)
$
(1.06)
(1.06)
(1) In the first quarter of 2012, we recorded $37.6 million of equity in income of non-consolidated
affiliates received in conjunction with the sale of our Venezuelan joint ventures’ assets (see
Note 7), $4.1 million of long-lived asset impairments (see Note 13) and $3.0 million of
restructuring charges (see Note 14).
(2) In June 2012, we committed to a plan to sell our contract operations and aftermarket services
businesses in Canada (see Note 2). Our Canadian contract operations and aftermarket services
businesses are reflected as discontinued operations in our consolidated financial statements. As a
result, we reclassified $11.3 million and $11.6 million of revenue for the three months ended
March 31, 2012 and 2011, respectively, to discontinued operations.
(3) In the second quarter of 2012, we recorded $128.5 million of long-lived assets impairments (see
Note 13), $4.7 million of equity in income of non-consolidated affiliates (see Note 7), $1.3 million
of restructuring charges (see Note 14) and $40.8 million impairment of Canadian discontinued
operations (see Note 2).
(4) In the third quarter of 2012, we recorded $126.7 million of net proceeds from the sale of
previously nationalized Venezuelan assets to PDVSA Gas (see Note 2), $4.8 million of equity in
income of non-consolidated affiliates (see Note 7), $3.2 million of long-lived asset impairments
(see Note 13), $1.5 million of restructuring charges (see Note 14) and $27.7 million impairment of
Canadian discontinued operations (see Note 2).
(5) In the fourth quarter of 2012, we recorded $46.8 million of long-lived assets impairment related to
our plan to abandon our contract water treatment business (see Note 13), $16.8 million of net
proceeds from the sale of previously nationalized Venezuelan assets to PDVSA Gas (see Note 2),
F-53
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$4.6 million of equity in income of non-consolidated affiliates (see Note 7) and $11.6 million
impairment of Canadian discontinued operations (see Note 2).
(6) Gross profit is defined as revenue less cost of sales, direct depreciation and amortization expense
and long-lived asset impairment charges.
(7) In the third quarter of 2011, we recorded a $196.1 million goodwill impairment charge (see
Note 8) and $2.9 million of restructuring charges (see Note 14).
(8) In the fourth quarter of 2011, we recorded $8.7 million of restructuring charges (see Note 14).
25. Subsequent Event
In January 2013, we redeemed for cash all $143.8 million principal amount outstanding of our
4.75% Notes at a redemption price of 100% of the principal amount thereof plus accrued but unpaid
interest to, but excluding, the redemption date. Upon redemption, the 4.75% Notes are no longer
deemed outstanding, interest ceased to accrue thereon and all rights of the holders of the 4.75% Notes
ceased to exist. The redemption of the 4.75% Notes was financed from our revolving credit facility. At
December 31, 2012, we had $0.9 million of unamortized deferred financing costs that will be expensed
in the first quarter of 2013.
F-54
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2 C Cs: 40264
SCHEDULE II
EXTERRAN HOLDINGS, INC.
VALUATION AND QUALIFYING ACCOUNTS
(In thousands)
Description
Allowance for doubtful accounts deducted from accounts
receivable in the balance sheet
December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . .
Allowance for obsolete and slow moving inventory
deducted from inventories in the balance sheet
December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . .
Allowance for deferred tax assets not expected to be
realized
December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2010 . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance at
Beginning
of Period
Additions
Charged to
Costs and
Expenses
Deductions
Balance at
End of
Period
$11,270
13,088
15,321
$ 8,754
1,488
4,749
$ 4,972(1) $15,052
3,306(1) 11,270
6,982(1) 13,088
$14,011
15,945
16,038
$ 1,005
4,975
2,337
$ 3,280(2) $11,736
6,909(2) 14,011
2,430(2) 15,945
$76,056
18,131
20,024
$29,132
70,513
5,122
$19,134(3) $86,054
12,588(3) 76,056
7,015(3) 18,131
(1) Uncollectible accounts written off, net of recoveries.
(2) Obsolete inventory written off at cost, net of value received.
(3) Reflects expected realization of deferred tax assets and amounts credited to other accounts for
stock-based compensation excess tax benefits, expiring net operating losses, changes in tax rates
and changes in currency exchange rates.
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Last year, the people of Exterran focused on driving signifi cant and lasting
performance improvement. Our promising results in 2012, including a return
in the second half of the year to positive earnings per share from continuing
operations, excluding charges, demonstrate that we are on our way.
Directors
Gordon T. Hall
Chairman of the Board
Mark R. Sotir
Executive Vice Chairman
Uriel E. Dutton
William C. Pate
J.W.G. “Will” Honeybourne
Stephen M. Pazuk
Mark A. McCollum
Christopher T. Seaver
18%Increase in EBITDA
EBITDA, as adjusted, increased by 18%
on 7% growth in revenues, supported
by improved gross margins in all four of
our business segments
2.4xTotal Leverage
Exterran Holdings’ covenant total leverage
ratio declined from 4.3x to 2.4x by year
end, as a result of reduced debt levels
and increased EBITDA
Executive Offi cers
D. Bradley Childers
President and Chief Executive Offi cer
William M. Austin
Executive Vice President and
Chief Financial Offi cer
Joseph G. Kishkill
Senior Vice President
President, Eastern Hemisphere
Chris Michel
Senior Vice President,
Global Human Resources
Ronaldo Reimer
Senior Vice President
President, Latin America
Rob Rice
Senior Vice President
President, North America
Daniel K. Schlanger
Senior Vice President,
Operations Services
Donald C. Wayne
Senior Vice President,
General Counsel and Secretary
Kenneth R. Bickett
Vice President
Corporate Controller
Corporate Information
Annual Meeting
The 2013 Annual Meeting of Stockholders will be held April 30,
2013, at 11:30 a.m. central time, at Exterran’s Corporate Offi ce.
Stock Trading
New York Stock Exchange symbol: EXH
Stockholder Information Website
Additional information on Exterran, including securities
fi lings, press releases, Code of Business Conduct, Corporate
Governance Principles and Board Committee Charters, is
available on our website at www.exterran.com.
Transfer Agent-Registrar
American Stock Transfer and Trust Company
59 Maiden Lane
Plaza Level
New York, New York 10038 USA
(800) 937-5449 or (718) 921-8200
Independent Registered Public Accounting Firm
Deloitte & Touche LLP
Houston, Texas USA
Corporate Offi ce
16666 Northchase Drive
Houston, Texas 77060 USA
(281) 836-7000
On the cover: Chance Huron, Senior Emissions Technician
10-K/Investor Contact
Stockholders may obtain a copy, without charge, of Exterran’s 2012
Form 10-K, fi led with the Securities and Exchange Commission, by
visiting our website at www.exterran.com or by requesting a copy
in writing to investor.relations@exterran.com or Exterran’s
Corporate Offi ce, Attention: Investor Relations.
The certifi cations by our Chief Executive Offi cer and Chief Financial
Offi cer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
are fi led as exhibits to our 2012 Form 10-K. We have also fi led with
the New York Stock Exchange the written affi rmation certifying
that we are not aware of any violations by Exterran of NYSE
Corporate Governance Listing Standards.
Contact Board of Directors
To report a concern about Exterran’s accounting, internal controls
or auditing matters, or any other matter, to the Audit Committee
or non-management members of the Board of Directors, send a
detailed note, with relevant documents, to Exterran’s Corporate
Offi ce, Attention: Gordon T. Hall, Chairman of the Board, or leave
a message at 1-800-281-5439 (U.S. and Canada) or 1-832-554-4859
(outside U.S. and Canada), request reverse charges.
Forward-Looking Statements
Certain statements contained in this Annual Report may constitute
forward-looking statements within the meaning of the Private
Securities Litigation Reform Act of 1995. These statements
involve a number of risks, uncertainties and other factors that
could cause actual results to be materially different, as discussed
more fully elsewhere in this Annual Report and in our fi lings
with the Securities and Exchange Commission, including our
2012 Form 10-K fi led on February 26, 2013. Except as required
by law, we expressly disclaim any intention or obligation to revise
or update any forward-looking statements whether as a result of
new information, future events or otherwise.
2012 Annual Report
On Our Way
Exterran Holdings, Inc.
www.exterran.com