NATCO GROUP INC - 10-K Annual Report

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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003 COMMISSION FILE NUMBER: 1-15603

NATCO GROUP INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

DELAWARE 22-2906892
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER IDENTIFICATION NO.)
INCORPORATION OR ORGANIZATION)

2950 N. LOOP WEST, 7TH FLOOR, HOUSTON, TEXAS 77092
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
Registrant's telephone number, including area code: (713) 683-9292

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE

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 X No ___

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. [ ]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes X No ___

State the aggregate market value of the voting and non-voting common equity held
by non-affiliates computed by reference to the price at which the common equity
was last sold, or the average bid and asked price of such common equity as of
the last business day of the registrant's most recently completed second fiscal
quarter.

As of June 30, 2003 $64,077,503

Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.

As of March 10, 2004 Common Stock, $0.01 par value per share 15,922,661 shares

DOCUMENTS INCORPORATED BY REFERENCE (TO THE EXTENT INDICATED HEREIN)

Specified portions of the 2004 Notice of Annual Meeting of Stockholders and
Proxy Statement (Part III)
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NATCO GROUP INC.
FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2003

TABLE OF CONTENTS

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PART I

ITEM 1. BUSINESS

NATCO Group Inc. is a leading provider of equipment, systems and services
used in the production of crude oil and natural gas to separate oil, gas and
water within a production stream and to remove contaminants. Our products and
services are used in onshore and offshore fields in most major oil and gas
producing regions in the world. Separation and decontamination of a production
stream is needed at almost every producing well in order to meet the
specifications of transporters and end users.

We design and manufacture a diverse line of production equipment including,
among other items: heaters, which prevent hydrates from forming in gas streams
and reduce the viscosity of oil; dehydration and desalting units, which remove
water and salt from oil and gas; separators, which separate wellhead production
streams into oil, gas and water; gas conditioning units and membrane separation
systems, which remove carbon dioxide and other contaminants from gas streams;
control systems, which monitor and control production equipment; and water
processing systems, which include systems for water re-injection, oily water
treatment and other treatment applications.

We offer our products and services as either integrated systems or
individual components primarily through three business lines:

- traditional production equipment and services, which provides
standardized components, replacement parts and used components and
equipment servicing, primarily in North America, and operates domestic
CO(2) separation facilities;

- engineered systems, which provides customized, large scale integrated
oil, gas and water production and processing systems; and

- automation and control systems, which provides and services control
panels and systems that monitor and control oil and gas production, as
well as repair, testing and inspection services for existing systems.

NATCO Group Inc. is a Delaware corporation formed in 1989. Through our
subsidiaries, we have designed, manufactured and marketed production equipment
and systems for more than 75 years. We operate seven primary manufacturing
facilities located in the U.S. and Canada and 36 sales and service facilities,
34 of which are located in the U.S. and Canada, and 2 of which are located
outside of the U.S. and Canada. We have engineering offices in the U.S., Canada
and the U.K., as well as engineered systems sales offices in these and other
international locations. We also have offices in the U.S. and overseas from
which we supply control systems, equipment and services. We believe that, among
our competitors, we have one of the largest installed base of production
equipment in the industry. We have achieved our position in the industry by
maintaining technological leadership, capitalizing on our strong brand name
recognition and offering a broad range of quality products and services.

Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current
Reports on Form 8-K, as well as any amendments and exhibits to those reports,
are available free of charge through our website, www.natcogroup.com, as soon as
reasonably practicable after we file them with, or furnish them to, the SEC.

INDUSTRY

Demand for oil and gas production equipment and services is driven
primarily by the following: levels of production of oil and gas in response to
worldwide demand; the changing production profiles of existing fields (meaning
the mix of oil, gas and water in the production stream and the level of
contaminants); the discovery of new oil and gas fields; the quality of new
hydrocarbon production; and investment in exploration and production efforts by
oil and gas producers.

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We believe that the oil and gas production equipment and services market
continues to have significant growth potential due to the following:

- Increasing demand for oil and natural gas. According to the U.S.
Department of Energy, petroleum and natural gas consumption in the United
States are expected to increase through 2025, with higher consumption
rates expected worldwide, driven by demand for refined products and the
use of natural gas to power plants that generate electricity.

- Long-term demand for oil and gas products should lead to increases in
drilling activity. The number of drilling rigs operating in North
America and internationally has fluctuated in recent years, depending on
market conditions. The average North American rig count for 2003 was
1,403 versus 1,093 for 2002 and 1,497 for 2001, as published by Baker
Hughes Incorporated. The international rig count as of December 31, 2003,
2002 and 2001 was 803, 753 and 752, respectively, as published by Baker
Hughes Incorporated. We believe that rig counts will increase over the
long-term as demand for oil and gas products and services increases. With
such increases, we anticipate increased demand for oil and gas production
equipment and services.

- Changing profile of existing production. The production profile of
existing fields changes over time, either naturally or due to
implementation of enhanced recovery techniques. Consequently, the mix of
oil, gas, water and contaminants changes, and the production stream
requires additional, more sophisticated processing equipment. Changing
production profiles often require retrofitting and debottlenecking of
existing production equipment, which is one of our specialties.

- Increasing focus on large-scale complicated equipment packages and
integrated systems projects. Due to the increased demand for oil and
gas, oil companies are pursuing larger and more complex development
projects that often require specialized production equipment. These
projects may be in remote, deepwater or harsh environments, may involve
complex production profiles and operations and typically involve more
sophisticated equipment.

- Increasing need for technology solutions. Higher specification and
performance standards, environmental regulation, cost reduction
requirements, desire to reduce space and weight of equipment and other
similar considerations have increased demand for technology in production
equipment. We are a leader in process technology for upstream
applications.

COMPETITIVE STRENGTHS

We believe that our key competitive strengths are:

- Market leadership and industry reputation. We have designed,
manufactured and marketed production equipment and systems for more than
75 years. We believe that, among our competitors, we have the largest
installed base of production equipment in the industry. We will continue
to enhance our products and services in order to meet the demands of our
customers.

- Technological leadership. We believe that we have established a position
of global technological leadership by pioneering the development of
innovative separation technologies. We continue to be a technological
leader in areas such as carbon dioxide separation using membrane
technology, oil-water emulsion treatment using the latest electrostatic
technology, seawater injection systems, complex produced oily water
treatment systems and a variety of specialty applications. We hold 37
active U.S. and equivalent foreign patents and continue to invest in
research and development. Applications have been filed for nine
additional patents in the U.S.

- Extensive line of products and services. We provide a broad range of
high quality production equipment and services, ranging from standard
processing and control equipment, to highly specialized engineered
systems and fully integrated solutions to our customers around the world.
By providing the broadest range of products and services in the industry,
we offer our customers the time and cost savings resulting from the use
of a single supplier for process engineering, design, manufacturing and
installation of production and related control systems.

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- Experienced and focused management team. Our senior management team has
extensive experience in our industry with an average of over 20 years of
experience. We believe that our management team has successfully
demonstrated its ability to grow our business and integrate acquisitions.
Additionally, our management team has a substantial financial interest in
our continued success through equity ownership or incentives.

- Leading role in CO(2) separation for domestic enhanced oil recovery and
ownership and operation of Sacroc facilities. Our membrane systems have
a dominant position in U.S. CO(2) flood enhanced oil recovery
applications, led by our Sacroc facility in West Texas. We own and
operate facilities at Sacroc capable of processing up to 367 million
cubic feet per day (mmcf) under long-term contract processing agreements.
We received an order in early 2004 to manufacture and sell an additional
capacity expansion of 180 mmcf per day at this facility. This expansion
is expected to be placed in service in mid-2004, for which we plan to
enter into a separate operating agreement. In addition, we have sold
membrane facilities to five other major CO(2) flood operations in West
Texas.

BUSINESS STRATEGY

Our primary objective is to maximize cash flow by maintaining and enhancing
our position as a leading provider of equipment, systems, services and solutions
used in the production of crude oil and natural gas. We intend to achieve this
goal by pursuing the following business strategies:

- Focusing on Customer Relationships. We believe that our customers prefer
to work on a regular basis with a small number of leading suppliers. We
believe our size, scope of products, technological expertise and service
orientation provide us with a competitive advantage in establishing
preferred supplier relationships with customers. We intend to generate
growth in revenue and market share by establishing new, and further
developing existing, customer relationships.

- Providing Integrated Systems and Solutions. We believe our integrated
design and manufacturing capabilities enable us to reduce our customers'
production equipment and systems costs and shorten delivery times. Our
strategy is to be involved in projects early, to provide the broadest and
most complete scope of equipment and services in our industry and to
focus on larger, sophisticated and integrated systems.

- Introducing New Technologies and Products. Since our inception, we have
developed and acquired leading technologies that enable us to address the
global market demand for increasingly sophisticated production equipment
and systems. We will continue to pursue new technologies through internal
development, acquisitions and licenses.

- Pursuing Complementary Acquisitions. Our industry is fragmented and
contains smaller competitors with less extensive product lines and
geographic scope. We continue to review potential strategic alternatives
involving companies that provide complementary technologies, enhance our
ability to offer integrated systems or expand our geographic reach.

- Expanding International Presence. We have operated in various
international markets for more than 50 years. We intend to continue to
expand internationally in targeted geographic regions, such as Latin
America, West Africa and Southeast Asia. International operations
provided approximately 33% of total revenues for the year ended December
31, 2003.

RISKS RELATING TO OUR BUSINESS

A SUBSTANTIAL OR EXTENDED DECLINE IN OIL OR GAS PRICES COULD RESULT IN LOWER
EXPENDITURES BY THE OIL AND GAS INDUSTRY, THEREBY NEGATIVELY AFFECTING OUR
REVENUE.

Our business is substantially dependent on the condition of the oil and gas
industry and its willingness to spend capital on the exploration for and
development of oil and gas reserves. A substantial or extended decline in these
expenditures may result in the discovery of fewer new reserves of oil and gas,
adversely affecting the market for our production equipment and services. The
level of these expenditures is generally dependent on

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the industry's view of future oil and gas prices, which have been characterized
by significant volatility in recent years. Oil and gas prices are affected by
numerous factors, including: the level of exploration activity; worldwide
economic activity; interest rates, the cost of capital and currency exchange
rate fluctuations; environmental regulation; tax policies; political
requirements of national governments; coordination by the Organization of
Petroleum Exporting Countries ("OPEC"); political environment, including the
threat of war and terrorism; the cost of producing oil and gas; technological
advances; changes in the supply of and demand for oil, natural gas and
electricity; and weather conditions.

MOST OF OUR CONTRACTS ARE FIXED-PRICE CONTRACTS THAT ARE SUBJECT TO GROSS PROFIT
FLUCTUATIONS, WHICH MAY IMPACT OUR MARGIN EXPECTATIONS.

Most of our projects, including larger engineered systems projects, are
performed on a fixed-price basis. We are responsible for all cost overruns,
other than any resulting from change orders. Our costs and any gross profit
realized on our fixed-price contracts will often vary from the estimated amounts
on which these contracts were originally based. This may occur for various
reasons, including: errors in estimates or bidding; changes in availability and
cost of labor and material; and variations in productivity from our original
estimates.

These variations and the risks inherent in engineered systems projects may
result in reduced profitability or losses on our projects. Depending on the size
of a project, variations from estimated contract performance can have a
significant negative impact on our operating results or our financial condition.

OUR QUARTERLY SALES AND CASH FLOW MAY FLUCTUATE SIGNIFICANTLY.

Our revenues are substantially derived from significant contracts that are
often performed over periods of two to six or more quarters. As a result, our
revenues and cash flow may fluctuate significantly from quarter to quarter,
depending upon our ability to replace existing contracts with new orders and
upon the extent of any delays in completing existing projects.

WE HAVE RELIED AND WE EXPECT TO CONTINUE TO RELY ON A LIMITED NUMBER OF
CUSTOMERS FOR A SIGNIFICANT PORTION OF OUR REVENUES.

There have been and are expected to be periods where a substantial portion
of our revenues is derived from a single customer or a small group of customers.
We had revenues of $24.2 million, or 9% of total revenues, provided by
ChevronTexaco Corp. and affiliates, $18.7 million, or 7% of total revenues,
provided by ExxonMobil Corporation and affiliates and $14.6 million, or 5% of
total revenues, provided by BP and affiliates for the year ended December 31,
2003. We had revenues of $28.8 million, or 10% of total revenues, provided by
ExxonMobil Corporation and affiliates, $17.2 million, or 6% of revenues,
provided by BP and affiliates excluding the Carigali-Triton Operating Company
SDN BHD ("CTOC"), and $16.5 million, or 5%, provided by ChevronTexaco Corp. and
affiliates, for the year ended December 31, 2002. We had revenues of $15.7
million, or 5% of our total revenues, provided by Anadarko and affiliates, $15.5
million, or 5% of total revenues, provided by ChevronTexaco Corp. and
affiliates, and $13.4 million, or 5% of total revenues provided by BP and
affiliates excluding CTOC, for the year ended December 31, 2001.

We have a number of ongoing relationships with major oil companies,
national oil companies and large independent producers. The loss of one or more
of these ongoing relationships could have an adverse effect on our business and
results of operations.

THE DOLLAR AMOUNT OF OUR BACKLOG, AS STATED AT ANY GIVEN TIME, IS NOT
NECESSARILY INDICATIVE OF OUR FUTURE CASH FLOW.

Backlog consists of firm customer orders that have satisfactory credit or
financing arrangements in place, for which authorization to begin work or
purchase materials has been given and for which a delivery date has been
established. As of December 31, 2003, we had backlog of $64.0 million, of which
approximately 13% related to ExxonMobil Corporation and affiliates, 12% related
to an Aker/Kvaerner joint venture, 9% related to TSS Dalia Angola and 8% related
to Sembawang Singapore.
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We cannot guarantee that the revenues projected in our backlog will be
realized, or if realized, will result in profits. To the extent that we
experience significant terminations, suspensions or adjustments in the scope of
our projects as reflected in our backlog contracts, we could be materially
adversely affected.

Occasionally, a customer will cancel or delay a project for reasons beyond
our control. In the event of a project cancellation, we are generally reimbursed
for our costs but typically have no contractual right to the total revenues
expected from such project as reflected in our backlog. In addition, projects
may remain in our backlog for extended periods of time. If we were to experience
significant cancellations or delays of projects in our backlog, our results of
operations and financial condition could be materially adversely affected.

OUR ABILITY TO ATTRACT AND RETAIN SKILLED LABOR IS CRUCIAL TO OUR PROFITABILITY.

Our ability to succeed depends in part on our ability to attract and retain
skilled manufacturing workers, equipment operators, engineers and other
technical personnel. Our ability to expand our operations depends primarily on
our ability to increase our labor force. Demand for these workers can fluctuate
in line with overall activity levels within our industry. A significant increase
in the wages paid by competing employers could result in a reduction in our
skilled labor force, increases in the rates of wages we must pay or both. If
this were to occur, the immediate effect would be a reduction in our profits and
the extended effect would be diminishment of our production capacity and
profitability and impairment of our growth potential.

POSTRETIREMENT HEALTH CARE BENEFITS THAT WE PROVIDE TO CERTAIN RETIREES OF A
PREDECESSOR COMPANY EXPOSE US TO POTENTIAL INCREASES IN FUTURE CASH OUTLAYS THAT
CANNOT BE RECOUPED THROUGH INCREASED PREMIUMS.

We are obligated to provide postretirement health care benefits to a group
of retirees of a predecessor company who retired before June 21, 1989. For the
year ended December 31, 2003, our cash costs related to these benefits were $1.6
million, net of reimbursement of $157,000 from the predecessor plan sponsor. At
that date, there were 500 retirees and surviving eligible dependents covered by
the specified postretirement benefit obligations. As of December 31, 2003, our
accumulated pre-tax postretirement benefit obligation was calculated to be
approximately $16.7 million as determined by actuarial calculations. The costs
of the actual benefits could exceed those projected, and future actuarial
assessments of the extent of those costs could exceed the current assessment.
Inflationary trends in medical costs may outpace our ability to recoup these
increases through higher premium charges, benefit design changes or both. As a
result, our actual cash costs of providing this benefit may increase in the
future and could have a negative impact on our future cash flow.

OUR INTERNATIONAL OPERATIONS MAY EXPERIENCE INTERRUPTIONS DUE TO POLITICAL AND
ECONOMIC RISKS.

We operate our business and market our products and services throughout the
world. We are, therefore, subject to the risks customarily attendant to
international operations and investments in foreign countries. Moreover, oil and
gas producing regions in which we operate include many countries in the Middle
East and other less developed parts of the world, where risks have increased
significantly in the recent past. We cannot accurately predict whether these
risks will increase or abate. These risks include: nationalization;
expropriation; war, terrorism and civil disturbances; restrictive actions by
local governments; limitations on repatriation of earnings; changes in foreign
tax laws; and changes in currency exchange rates.

The occurrence of any of these risks could have an adverse effect on
regional demand for our products and services or our ability to provide them.
Further, we may experience restrictions in travel to visit customers or start-up
projects, and we incur added costs by implementing security precautions. An
interruption of our international operations could have a material adverse
effect on our results of operations and financial condition.

The occurrence of some of these risks, such as changes in foreign tax laws
and changes in currency exchange rates, may have extended consequences.

Axsia Group Limited and its subsidiaries, our U.K.-based operations, and
our Canadian subsidiary have made sales (as part of their ongoing businesses)
and have informed us that they expect to continue making sales of equipment and
services to customers in certain countries that are subject to U.S. government
trade

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sanctions ("Embargoed Countries"). In the past, these included sales to the
Iraqi national oil companies permitted under the United Nations Food-for-Oil
Program. Sales to customers in Embargoed Countries were approximately 1% of our
consolidated revenue in 2003, approximately 3 1/2% in 2002 and approximately
2 1/2% in 2001.

OUR INSURANCE POLICIES MAY NOT COVER ALL PRODUCT LIABILITY CLAIMS AGAINST US OR
MAY BE INSUFFICIENT IN AMOUNT TO COVER SUCH CLAIMS.

Some of our products are used in potentially hazardous production
applications that can cause personal injury; loss of life; damage to property,
equipment or the environment; and suspension of operations. We maintain
insurance coverage against these risks in accordance with standard industry
practice. This insurance may not protect us against liability for some kinds of
events, including events involving pollution or losses resulting from business
interruption or acts of terrorism. We cannot assure you that our insurance will
be adequate in risk coverage or policy limits to cover all losses or liabilities
that we may incur. Moreover, we cannot assure you that we will be able in the
future to maintain insurance at levels of risk coverage or policy limits that we
deem adequate. Any future damages caused by our products or services that are
not covered by insurance or are in excess of policy limits could have a material
adverse effect on our business, results of operations and financial condition.

LIABILITY TO CUSTOMERS UNDER WARRANTIES MAY MATERIALLY AND ADVERSELY AFFECT OUR
CASH FLOW.

We typically warrant the workmanship and materials used in the equipment we
manufacture. At the request of our customers, we occasionally warrant the
operational performance of the equipment we manufacture. Failure of this
equipment to operate properly or to meet specifications may increase our costs
by requiring additional engineering resources, replacement of parts and
equipment or service or monetary reimbursement to a customer. Our warranties are
often backed by letters of credit. At December 31, 2003, we had provided to our
customers approximately $6.9 million in letters of credit related to warranties.
We have received warranty claims in the past, and we expect to continue to
receive them in the future. To the extent that we should incur warranty claims
in any period substantially in excess of our warranty reserve, our results of
operations and financial condition could be materially and adversely affected.

OUR ABILITY TO SECURE AND RETAIN NECESSARY FINANCING MAY BE LIMITED.

Our ability to execute our growth strategies may be limited by our ability
to secure and retain reasonably priced financing. From time to time we have
utilized significant amounts of letters of credit to secure our performance on
large projects as well as provide warranties to our customers. Outstanding
letters of credit can consume a significant portion of our available liquidity
under our revolving credit facilities. Some of our competitors are larger
companies with better access to capital, which could give them a competitive
advantage over us should our access to capital be limited. Additionally, the
industry in which we compete is often characterized by significant cyclical
fluctuations in activity levels that can adversely impact our financial results.
Our revolving credit and term loan facilities contain restrictive loan covenants
with which we are required to comply. There is no assurance that our financial
results will be adequate to ensure we remain in compliance with these covenants
in the future, nor is there any assurance we can obtain amendments to or waivers
of these covenants should we not be in compliance.

COMPETITION COULD RESULT IN REDUCED PROFITABILITY AND LOSS OF MARKET SHARE.

Contracts for our products and services are generally awarded on a
competitive basis. Historically, the existence of overcapacity in our industry
has caused increased price competition in many areas of our business. The most
important factors considered by our customers in awarding contracts include: the
availability and capabilities of our equipment; our ability to meet the
customer's delivery schedule; price; our reputation; our technology; our
experience; and our safety record.

In addition, we may encounter obstacles in our international operations
that impair our ability to compete in individual countries. These obstacles may
include: subsidies granted in favor of local companies; taxes,

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import duties and fees imposed on foreign operators; lower wage rates in foreign
countries; and fluctuations in the exchange value of the United States dollar
compared with the local currency. Any or all these factors could adversely
affect our ability to compete and thus adversely affect our results of
operations.

A FURTHER ECONOMIC DECLINE COULD ADVERSELY AFFECT DEMAND FOR OUR PRODUCTS AND
SERVICES.

Economic growth in several of our key markets, including the United States
and Southeast Asia, declined throughout 2001 due to a world-wide recession,
which was exacerbated by significant terrorist acts in the United States during
September 2001. Slower than expected economic growth in the United States during
2002, as well as in other regions of the world, contributed to a decline in
exploration and production activity in the oil and gas industry. Although
several economic indicators, including the recent performance of the U.S. stock
market, as measured by growth rates in 2003 for the Dow Jones Industrial Average
and Standard & Poor's 500 Index, may indicate improved economic growth for 2003
and further potential growth in 2004, we cannot provide assurance that the
United States economy will continue to grow or remain stable. If the U.S.
economy were to decline or if the economies of other nations in which we do
business were to experience material problems, the demand and price for oil and
gas and, therefore, for our products and services, could decline, which would
adversely affect our results of operations.

OUR ABILITY TO COMPETE SUCCESSFULLY IS DEPENDENT ON TECHNOLOGICAL ADVANCES IN
OUR PRODUCTS, AND OUR FAILURE TO RESPOND TIMELY OR ADEQUATELY TO TECHNOLOGICAL
ADVANCES IN OUR INDUSTRY MAY ADVERSELY AFFECT OUR RESULTS OF OPERATIONS.

Our ability to succeed with our long-term growth strategy is dependent on
the technological competitiveness of our products. If we are unable to innovate
and implement advanced technology in our products, other competitors may be able
to compete more effectively with us, and our business and results of operations
may be adversely affected.

FUTURE ACQUISITIONS, IF ANY, MAY BE DIFFICULT TO INTEGRATE, DISRUPT OUR BUSINESS
AND ADVERSELY AFFECT OUR OPERATING RESULTS.

We intend to continue our past practice of acquiring other companies,
assets and product lines that complement or expand our existing businesses. We
cannot assure you that we will be able to successfully identify suitable
acquisition opportunities or to finance and complete any particular acquisition.
Furthermore, acquisitions involve a number of risks and challenges, including:
the diversion of our management's attention to the assimilation of the
operations and personnel of the acquired business; possible adverse effects on
our operating results during the integration process; potential loss of key
employees and customers of the acquired companies; potential lack of experience
operating in a geographic market of the acquired business; an increase in our
expenses and working capital requirements; and the possible inability to achieve
the intended objectives of the combination.

Any of these factors could adversely affect our ability to achieve
anticipated levels of cash flow from an acquired business or realize other
anticipated benefits of an acquisition.

WE MAY INCUR SUBSTANTIAL COSTS TO COMPLY WITH OUR ENVIRONMENTAL OBLIGATIONS.

In our equipment fabrication and refurbishing operations, we generate and
manage hazardous wastes. These include: waste solvents; waste paint; waste oil;
wash-down wastes; and sandblasting wastes.

We attempt to identify and address environmental issues before acquiring
properties and to utilize industry accepted operating and disposal practices
regarding the management and disposal of hazardous wastes. Nevertheless, either
others or we may have released hazardous materials on our properties or in other
locations where hazardous wastes have been taken for disposal. We may be
required by federal, state or foreign environmental laws to remove hazardous
wastes or to remediate sites where they have been released. We could also be
subjected to civil and criminal penalties for violations of those laws. Our
costs to comply with these laws may adversely affect our earnings.

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OPERATIONS

We offer our products and services as either integrated systems or
individual components primarily through three business lines: traditional
production equipment and services, engineered systems and automation and control
systems.

TRADITIONAL PRODUCTION EQUIPMENT AND SERVICES

Traditional production equipment and services consists of production
equipment, replacement parts, and used equipment refurbishing and servicing,
which is sold primarily onshore in North America and in the Gulf of Mexico.
Through our NATCO Canada subsidiary, we provide traditional production equipment
with modifications to operate in a cold weather environment. The equipment built
for the North American oil and gas industry are "off the shelf" items or are
customized variations of standardized equipment requiring limited engineering.
We market traditional production equipment and services through 28 sales and
service centers in the United States, six in Canada, one in Mexico and one in
Venezuela.

Traditional production equipment includes:

- Separators. Separators are used for the primary separation of a
hydrocarbon stream into oil, water and gas. In addition to traditional
separator solutions, we offer customers new separation technologies like
the Whirly Scrub(TM) Recycling Separators and Revolution(TM) Inlet
Devices. The new separation technologies use proprietary devices inside
separator vessels to achieve more efficient separation. This translates
into smaller and lighter process equipment, and/or the ability to
retrofit existing facilities to increase processing throughput. Customers
benefit from the use of Porta-Test(R) Revolution(TM) tubes, perforated
baffles and other proprietary internals that allow separation systems to
be designed for specific needs, reduce size and weight, improve
separation efficiency, and eliminate process problems like foaming. Our
separator product line includes:

- horizontal separators, used to separate hydrocarbon streams with large
volumes of gas, liquids or foam;

- vertical separators, used to separate hydrocarbon streams containing
contaminants including salt and wax;

- filter separators, used to remove particulate contaminants from gas
streams and/or to coalesce liquids;

- Thermo Pak(TM) Units, used for the combined heating and separating of
production in cold climates; and

- Whirly Scrub(TM) V centrifugal separators, used as state-of-the-art
compact scrubbers.

- Oil Dehydration Equipment. Oil dehydrators are used to remove water from
oil. Our oil dehydration product line includes:

- horizontal PERFORMAX(R) treaters, which separate oil and water mixtures
using gravity and proprietary technology;

- Dual Polarity(R) and Electrodynamic Desalting(TM) electrostatic
treaters, which dehydrate oil using high voltage electrical
coalescence;

- vertical treaters, which separate oil and water using gravity and heat;

- Vertical Flow Horizontal (VFH(TM)) processors, which combine the
advantages of horizontal and vertical vessels to remove gas and water
from oil streams; and

- heater-treaters, which use heat to accelerate the dehydration process.

- Heaters. Heaters are used to reduce the viscosity of oil to improve flow
rates and to prevent hydrates from forming in gas streams. We manufacture
both standardized and customized direct and indirect

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fired heaters. In each system, heat is transferred to the hydrocarbon
stream through a medium such as water, water/glycol, steam, salt or flue
gas. Our heater product line includes:

- indirect fired water bath heaters;

- vaporizers used to vaporize propane and other liquefied gases;

- salt bath heaters used to heat high pressure natural gas streams to
elevated temperatures above that obtained with indirect heaters;

- steam bath heaters; and

- Controlled Heat Flux (CHF(TM)) heaters, which use flue gas to create a
heat transfer medium.

- Gas Conditioning Equipment. Gas conditioning equipment removes
contaminants from hydrocarbon and gas streams. Our gas conditioning
equipment includes:

- Cynara(R) membranes, which extract carbon dioxide from gas streams;

- glycol dehydration equipment, which uses glycol to absorb water vapor
from gas streams;

- amine systems, which use amine to remove acidic gases such as hydrogen
sulfide and carbon dioxide from gas streams;

- Glymine(R) units, which combine the effects of glycol equipment and
amine systems;

- Paques(TM) and Shell-Paques(TM) licensed desulfurization technology,
which utilizes a biological system to efficiently take hydrogen sulfide
out of gas streams;

- the BTEX-BUSTER(R), which virtually eliminates the emission of volatile
hydrocarbons associated with glycol dehydration reboilers; and

- DESI-DRI(R) Systems, which use highly compressed drying agents to
remove water vapor from gas streams.

- Gas Processing Equipment. We offer standard and custom processing
equipment for the extraction of liquid hydrocarbons to meet feed gas and
liquid product requirements. We manufacture several standard mechanical
refrigeration units for the recovery of salable hydrocarbon liquids from
gas streams. Low Temperature Extractor (LTX(R)) units are mechanical
separation systems designed for handling high-pressure gas at the
wellhead. These systems remove liquid hydrocarbons from gas streams more
efficiently and economically than other methods.

- Carbon Dioxide Field Operations. We also provide gas-processing
facilities for the removal of carbon dioxide from hydrocarbon streams.
These facilities use our proprietary Cynara(R) membrane technology that
provides one of the most effective separation solutions for hydrocarbon
streams containing carbon dioxide. The primary market for these
facilities is production from wells such as those located in west Texas
in which carbon dioxide injection is used to enhance the recovery of oil
reserves. Utilizing this technology, we have entered into three separate
service agreements with Kinder Morgan CO(2) Company, L.P. relative to gas
processing of production at the Sacroc field in West Texas. Each contract
has a term of ten years and is automatically renewed for successive
one-year periods, unless either Kinder Morgan or we provide the other
party with written notification of cancellation. Currently the earliest
termination date is set for July 2012.

- Water Treatment Equipment. We offer a complete line of water treatment
and conditioning equipment for the removal of contaminants from water
extracted during oil and gas production. Our water treatment equipment
includes:

- PERFORMAX(R) Matrix Plate Coalescers, used in both primary separation
and final skimming applications;

- TriPack(TM) Corrugated Plate Interceptors, used to remove oil and
salable hydrocarbons from water;

11

- Oilspin AV(TM) and AVi(TM) liquid/liquid hydrocyclones, compact
centrifugal separation devices used in primary water treatment
applications;

- Tridair(TM) Sparger Gas Flotation units, used as secondary water
cleanup systems; and

- PowerClean(TM) Nutshell Filters, used where tertiary water cleanup is
required.

- Equipment Refurbishment. We source, refurbish and integrate used oil and
gas production equipment. Customers that purchase this equipment benefit
from reduced delivery times and lower equipment costs relative to new
equipment. The used equipment market is focused primarily in North
America, both onshore and offshore, although we have observed a growing
interest internationally. We have entered into agreements with major,
large independent oil companies in both the United States and Canada to
evaluate, track and refurbish used production equipment and may act as a
broker between another oil company and our customer or may purchase,
refurbish and sell used equipment to our customers. We believe that we
have one of the largest databases in the North American oil and gas
industry of available surplus production equipment. This database,
coupled with our extensive refurbishing facilities and experience,
enables us to respond to customer requests for refurbished equipment
quickly and efficiently.

- Parts, Service and Training. We provide replacement parts for our own
equipment and for equipment manufactured by others. Each branch of our
marketing network also serves as a local parts and service business. We
offer operational and safety training to the oil and gas production
industry, which provides a marketing tool for our other products and
services.

ENGINEERED SYSTEMS

We design, engineer and manufacture engineered systems for large production
development projects throughout the world and provide start-up services for our
engineered products. Engineered systems typically require a significant amount
of technology, engineering and project management.

We market engineered systems through our direct sales forces based in
Houston, Texas; Calgary, Alberta, Canada; Camberley, England; Gloucester,
England; Caracas, Venezuela; and Tokyo, Japan, augmented by independent
representatives in other countries. We also use the unique oil testing
capabilities at our research and development facilities to market engineered
systems. This capability enables us to determine equipment specifications that
best suit customers' requirements.

Engineered systems include:

- Integrated Oil and Gas Processing Trains. These consist of multiple
units that process oil and gas from primary separation through
contaminant removal.

- Large Gas Processing Facilities. We provide large gas processing
facilities for the separation, heating, dehydration and removal of
liquids and contaminants to produce pipeline-quality natural gas. We also
design and manufacture gas-processing facilities that remove carbon
dioxide from hydrocarbon streams. These facilities use Cynara(R) membrane
technology, which provides the most cost-effective separation solution
for hydrocarbon streams containing high concentrations of carbon dioxide.
Primary markets for this application are production from gas wells, such
as those located in Southeast Asia, which have naturally occurring carbon
dioxide, and production fields that use CO(2) flood enhanced oil recovery
systems. We also design and supply systems for separation of H(2)S and
sulfur recovery, using Shell-Paques(TM) technology.

- Floating Production Systems. These consist of large skid-mounted
processing units used in conjunction with semi-submersible, converted
tankers and other floating production vessels. Floating production
equipment must be specially designed to overcome the detrimental effects
of wave motion on floating vessels. We pioneered and patented the first
wave-motion production vessel internals system and continue to advance
this technology at our research and development facility using a
wave-motion table, which simulates a variety of sea states. We also
utilize Computational Fluid

12

Dynamic modeling and Finite Element Analysis to ensure that these
facilities are optimally designed and are fabricated to meet the
durability requirements at defined sea states.

- Dehydration and Desalting Systems. Dehydration and desalting involves
the removal of water and salt from an oil stream. Desalting is a
specialized form of dehydration. In this process, water is injected into
an oil stream to dissolve the salt and the saltwater is then removed from
the stream. Large production projects often use electrostatic technology
to desalt oil. We believe that we are the leading developer of
electrostatic technologies for oil treating and desalting. One of our
dehydration and desalting systems, the Electro Dynamic(TM) Desalter, can
be used in oil refineries, where stringent desalting requirements have
grown increasingly important. These requirements have increased as crude
quality has declined and catalysts have become more sensitive and
sophisticated, requiring lower levels of contaminants. This technology
reduces the number and size of vessels employed by this system and is
particularly important in refinery and offshore applications where space
is at a premium.

- Water Injection Systems. We provide water injection systems used both
onshore and offshore to remove contaminants from water to be injected
into a reservoir during production so that the formation or its
production characteristics are not adversely affected. These systems may
involve media and cartridge filters, de-aeration, chemical injection and
sulfate removal. Offshore facilities to treat raw seawater involving use
of sulfate removal membranes can be and often are very large projects,
and are increasingly necessary for field development in locations such as
West Africa and Brazil. For example, during 2002, we designed,
manufactured and assembled SRM modules situated off the coast of West
Africa that are capable of treating 350,000 barrels per day of seawater.

- Produced Water Cleanup Systems. We design and engineer systems that,
through the use of liquid/liquid hydro-cyclone technology and induced or
dissolved gas flotation technology, remove oil and solids from a produced
water stream. Oily water cleanup is often required prior to the disposal
or re-injection of produced water.

- Other Proprietary Equipment. We design and supply a broad range of
proprietary equipment that may be part of a larger system or may be sold
separately to customers for application in an oil and gas field
development or retrofit. Such equipment includes wellhead desanders, sand
cleaning facilities, sand fluidization, specialty oil heaters and other
process equipment.

- Downstream Facilities. We offer several technologies that have crossover
applications in the refinery and petrochemical sectors. Most involve
aspects of oil treating and water treating. We discussed above the use in
refineries of one of our dehydration and desalting systems. Through our
subsidiary operation in Camberley, England, we also design and supply
process facilities for hydrogen generation and purification, for use in
refineries and petrochemical plants or by industrial gas suppliers. In
addition, we can provide DOX(TM) units to ethylene processors that clean
both heavy and light dispersed oil from water.

AUTOMATION AND CONTROL SYSTEMS

The primary market for automation and control systems is in offshore
applications throughout the world. We market and service these products through
our TEST subsidiary, with U.S. locations in Houston, Texas and Harvey and New
Iberia, Louisiana, and international locations in Kazahkstan and Nigeria. These
automation and control systems include:

- Control Systems. We design, assemble and install pneumatic, hydraulic,
electrical and computerized control panels and systems. These systems
monitor and change key parameters of oil and gas production systems. Key
parameters include wellhead flow control, emergency shutdown of
production and safety systems. A control system consists of a control
panel and related tubing, wiring, sensors and connections.

- Engineering and Field Services. We provide start-up support, testing,
maintenance, repair, renovation, expansion and upgrade of control systems
including those designed or installed by competitors,

13

for our customers in the U.S. and international locations. Our design and
engineering staff also provide contract electrical engineering services.

- SCADA Systems. Supervisory control and data acquisition ("SCADA")
systems provide remote monitoring and control of equipment, production
facilities, pipelines and compressors via radio, cellular phone,
microwave and satellite communication links. SCADA systems reduce the
number of personnel and frequency of site visits and allow for continued
production during periods of emergency evacuation, thereby reducing
operating costs.

MANUFACTURING FACILITIES

We operate seven primary manufacturing facilities ranging in size from
approximately 8,000 square feet to approximately 130,000 square feet of
manufacturing space. We own four of these facilities and lease the other three.
Our 51,000 square foot manufacturing facility in Covington, Louisiana was closed
in December 2003, as part of a restructuring effort in late 2003, and is
currently being held for sale.

Our major manufacturing facilities are located in:

- Electra, Texas. We produce various types of low- and high-pressure
production vessels, as well as skid-mounted packages at this 130,000
square foot facility.

- Calgary, Alberta, Canada. We produce heavy wall and cold weather
packaged equipment and systems primarily for the Canadian and Alaskan
markets at this 100,000 square foot facility.

- New Iberia, Louisiana. We fabricate packaged production systems for
delivery throughout the world at this 60,000 square foot and 16 acre
waterfront facility, which can handle large equipment systems. We
upgraded and expanded this facility in 2001.

- Magnolia, Texas. We fabricate various types of low-pressure production
vessels as skid packages at this 38,000 square foot facility. This
facility also refurbishes used equipment.

- Harvey, Louisiana. We fabricate control panels for delivery throughout
the world at this 12,000 square foot climate-controlled facility.

- Pittsburg, California. We manufacture the membranes for our bulk carbon
dioxide membrane separation equipment at this 8,000 square foot facility.

- Houston, Texas. We fabricate control panels for delivery throughout the
world at this 8,000 square foot climate-controlled facility.

Our manufacturing operations are vertically integrated. At most locations,
we are able to engineer, fabricate, heat treat, inspect and test our products.
Consequently, we are able to control the quality of our products and the cost
and schedule of our manufacturing activities.

Our New Iberia, Electra and Calgary facilities have been certified to ISO
9001 standards. This certification is an internationally recognized verification
system for quality management overseen by the International Standards
Organization based in Geneva, Switzerland. The certification is based on a
review of our programs and procedures designed to maintain and enhance quality
production and is subject to annual review and re-certification.

We fabricate to the standards of the American Petroleum Institute, the
American Welding Society, the American Society of Mechanical Engineers and
specific customer specifications. We use welding and fabrication procedures in
accordance with the latest technology and industry requirements. We have
instituted training programs to upgrade skilled personnel and maintain high
quality standards. We believe that these programs generally enhance the quality
of our products and reduce their repair rate.

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RESEARCH AND DEVELOPMENT

We believe we are an industry leader in the development of oil and gas
production equipment technology. We pioneered many of the original separation
technologies for converting unprocessed hydrocarbon fluids into salable oil and
gas. For example, we developed:

- the first high capacity oil and gas separator system;

- patented efficiencies for our cyclonic separation devices, including the
Porta-Test(R) Revolution(TM) and WhirlyScrub(TM) V's and I's
technologies;

- the first emulsion treating systems, which have been advanced through the
application of our Dual Polarity(TM), TriVolt(TM), TriGrid(TM),
TriGridmax(TM) and the EDD(TM) (ElectroDynamic Desalting(TM))
electrostatic oil treaters;

- a PC-based Load Responsive Controller(TM) (LRC(TM)) for controlling
electrostatic treaters within ranges that are conducive to effective
emulsion breaking;

- a composite electrostatic grid system for use in complex separation
applications;

- DOX(TM) and OSX(TM) water filtration systems, technologies that have many
years of successful testimonies and for which leading engineering
contractors specify by name;

- the Oilspin AV(TM) and the automatic turndown capable AVi(TM)
liquid/liquid hydro-cyclones;

- the Mozley Sandspin(TM) solid/liquid hydro-cyclones and the Mozley
Wellspin(TM) wellhead desander;

- the Mozley SandClean(TM) System for cleanup of sand prior to offshore
discharge;

- the Tridair(TM) Single Cell VersaFlo(TM) flotation unit;

- high pressure indirect and Controlled Heat Flux(TM) (CHF(TM)) heaters;

- internal system designs and devices used inside separators and other
vessels to compensate for wave motion;

- PERFORMAX(R) oil and water coalescing systems, which are recognized and
trusted internationally; and

- enhancements in Cynara(R) membrane fibers to allow for increased acid gas
separation efficiencies.

As of December 31, 2003, we held 37 active U.S. and equivalent foreign
patents and numerous U.S. and foreign trademarks. We also have applications
pending for nine additional U.S. patents. In addition, we are licensed under
several patents held by others.

We operate a research and development facility in Tulsa, Oklahoma, where we
conduct technology and product development studies that are tailored to the
needs of our customers. Such studies utilize our pilot facilities, including a
simulation loop capable of flowing 6 thousand barrels per day and 10 mmcf per
day of gas and a wave motion table that allows customers to validate 1/20(th)
scale performance internals in dynamic wave motion conditions. In many cases,
testing is applied to crude oil provided by our customers, resulting in an
increase in our customer's understanding and comfort with the actual performance
of our products.

At our manufacturing facility in Pittsburg, California, we are engaged in
active, ongoing research and development in the area of membrane technology. We
also have research and development operations at our facilities in the United
Kingdom, where we focus primarily on water treatment developments.

As a contracted service to our customers, we utilize Computational Fluid
Dynamic (CFD) Modeling to dynamically simulate the conditions of process
equipment both offshore and onshore. CFD studies have been key to validating
performance and durability of process equipment and are offered as a competitive
advantage to our hardware sales.

At December 31, 2003, NATCO had 16 employees engaged in research and
development and product commercialization activities.
15

MARKETING

Our products and services are marketed primarily through an internal sales
force augmented by technical applications specialists for specific customer
requirements. In addition, we maintain agency relationships in most energy
producing regions of the world to enhance our efforts in countries where we do
not have employees. Our traditional production equipment and services business
has 34 operating branches in the U.S. and Canada through which we sell
production equipment, spare parts and services directly to oil and gas
operators. Our engineered systems business typically involves a significant
pre-award effort during which we must provide technical qualifications, evaluate
the requirements of the specific project, design a conceptual solution that
meets the project requirements and estimate our cost to provide the system to
the customer in the time frame required. Our automation and control systems
business is primarily marketed through our internal sales force.

CUSTOMERS

We devote a considerable portion of our marketing time and effort to
developing and maintaining relationships with key customers. Some of these
relationships are project specific. However, our customer base ranges from
independent operators to major and national oil companies worldwide. In 2003,
ChevronTexaco Corp. and affiliates, ExxonMobil Corporation and affiliates and BP
and affiliates, provided 9%, 7% and 5% of our consolidated revenues,
respectively, with no other customer contributing more than 5% of total sales
for the year ended December 31, 2003. In 2002, ExxonMobil Corporation and
affiliates, BP and affiliates excluding CTOC, and ChevronTexaco Corp. and
affiliates, provided 10%, 6% and 5% of our consolidated revenues, respectively,
with no other customer providing more than 5% of our consolidated revenues
during 2002. In 2001, Anadarko and affiliates, ChevronTexaco Corp. and
affiliates, and BP and affiliates excluding CTOC, each provided 5% of our
consolidated revenue, with no other customer contributing more than 5% of total
revenues for the year ended December 31, 2001. Our level of technical expertise,
extensive distribution network and breadth of product offerings contributes to
the maintenance of good working relationships with our customers.

BACKLOG

Backlog consists of firm customer orders for which satisfactory credit or
financing arrangements have been made, authorization has been given to begin
work or purchase materials and a delivery date has been scheduled.

Our sales backlogs at December 31, 2003, 2002 and 2001, were $64.0 million,
$90.1 million and $101.3 million, respectively. The decline in backlog at
December 31, 2003 compared to December 31, 2002 was primarily due to the run-off
of backlog associated with several significant West African engineered systems
projects recorded as bookings in 2002, with fewer significant bookings for the
year ended December 31, 2003. Backlog at December 31, 2003 included $8.3 million
related to ExxonMobil Corporation and affiliates and $7.6 million related to an
Aker/Kvaerner joint venture. Backlog at December 31, 2002 included $28.7 million
related to ExxonMobil Corporation and affiliates, and $11.7 million for
ChevronTexaco Corp. Backlog at December 31, 2001 included $27.4 million for
ExxonMobil Corporation and affiliates, and $11.1 million for a North Sea
consortium.

Occasionally, a customer will cancel or delay a project for reasons beyond
our control. In the event of a project cancellation, we generally are reimbursed
for costs incurred but typically have no contractual right to the total revenues
reflected in our backlog. In addition, projects may remain in our backlog for
extended periods of time. If we were to experience significant cancellations or
delays of projects in our backlog, our results of operations and financial
condition could be materially adversely affected.

COMPETITION

Contracts for our products and services are generally awarded on a
competitive basis. The most important factors considered by customers in
awarding contracts include the availability and capabilities of equipment, the
ability to meet the customer's delivery schedule, price, reputation, experience
and safety record.
16

Historically, the existence of overcapacity in the industry has caused increased
price competition in many areas of the business. In addition, we may encounter
obstacles in our international operations that impair our ability to compete in
individual countries. These obstacles may include: subsidies granted in favor of
local companies; taxes, import duties and fees imposed on foreign operators;
lower wage rates in foreign countries; fluctuations in the exchange value of the
United States dollar compared with the local currency; and U.S. trade sanctions
against embargoed countries. Any or all these factors could adversely affect our
ability to compete and thus unfavorably affect our results of operations.

The primary competitors for our North American Operations business include
Hanover Compressor Co., Flint Energy Services and numerous privately held,
mainly regional companies. Competitors for our Engineered Systems business
include Petreco, Kvaerner Process Systems, UOP, Hanover Compressor Co., U.S.
Filter, Weir Techna and numerous engineering and construction firms. The primary
competitors for our Automation and Control Systems business are W Industries,
MMR-Radon, P2S/SECO and numerous privately held companies operating in the Gulf
Coast region.

We believe that we are one of the largest crude oil and natural gas
production equipment providers in North America and have one of the leading
market shares internationally. We further believe that our size, research and
development capabilities, brand names and marketing organization provide us with
a competitive advantage over the other participants in the industry.

ENVIRONMENTAL MATTERS

We are subject to environmental regulation by federal, state and local
authorities in the United States and in several foreign countries. Although we
believe that we are in substantial compliance with all applicable environmental
laws, rules and regulations ("laws"), the field of environmental regulation can
change rapidly with the enactment or enhancement of laws and stepped up
enforcement of these laws, either of which could require us to change or
discontinue certain business activities. We have been named as a potentially
responsible de minimis party in connection with two superfund sites. At present,
we are not involved in any material environmental matters of any nature and are
not aware of any material environmental matters threatened against us.

EMPLOYEES

At December 31, 2003, we had 1,664 employees. Of these, 131 Canadian
employees were represented under collective bargaining agreements that extend
through July 2005. We believe that our relationships with our employees are
satisfactory.

ITEM 2. PROPERTIES

We operate seven primary manufacturing plants ranging in size from
approximately 8,000 square feet to approximately 130,000 square feet of
manufacturing space. We also own and lease distribution and service centers,
sales offices and warehouses. We lease our corporate headquarters in Houston,
Texas. At December 31, 2003, we owned or leased approximately 1.0 million square
feet of facility of which approximately 485,000 square feet was leased, and
approximately 538,000 square feet was owned. Of the total manufacturing space,
approximately 218,000 square feet was located in the United States and
approximately 100,000 square feet was located in Canada. Our Covington
manufacturing facility was closed and held for sale, and our Edmonton
manufacturing facility was sublet to a new tenant as of December 31, 2003.
Square footage of manufacturing space at these facilities totaling 60,000 feet
and 51,000 feet, respectively, was excluded from total manufacturing space
above, but was included in total square footage owned or leased as of December
31, 2003.

17

The following chart summarizes the number of facilities owned or leased by
us by geographic region and business segment.

ITEM 3. LEGAL PROCEEDINGS

Magnum Transcontinental Corp. Arbitration and Related Matter. These
matters stem from an agreement among NATCO Group, Magnum Transcontinental
Corporation, the U.S. procurement arm of Petroserv S.A., and Zephyr Offshore,
Inc., a Petroserv subsidiary, to manufacture and install a processing plant on a
Petroserv rig, and Petroserv's agency agreement with NATCO for certain projects
in Brazil. NATCO claims Magnum owes it $418,990 under the plant manufacturing
agreement for additional work performed in excess of the days agreed in the
contract. NATCO submitted the matter to binding American Arbitration Association
arbitration on October 29, 2003. An arbitrator has been selected, and
arbitration is scheduled in Houston, Texas during August 2004. In the
arbitration, Magnum has counter-claimed for $4,685,000, alleging breach of
contract. NATCO disputes the amounts claimed by Magnum, and intends to
vigorously pursue its claims while defending against the counterclaim. After
NATCO filed its request for arbitration, Petroserv submitted a mediation request
under its representation agreement with NATCO, claiming unpaid agency fees on
several contracts, including the Magnum contract. No resolution resulted from
the mediation, which was held on January 23, 2004. NATCO believes any fees owed
to Petroserv under the agency agreement are offset by NATCO's claims against
Magnum. NATCO disputes that it owes any fees for the Magnum work or any work
obtained in Brazil after the representation agreement terminated in early 2003.
It is not presently known what, if any, further action Petroserv will take in
this regard.

NATCO and its subsidiaries are defendants or otherwise involved in a number
of other legal proceedings in the ordinary course of their business. While we
insure against the risk of these proceedings to the extent deemed prudent by our
management, we can offer no assurance that the type or value of this insurance
will meet the liabilities that may arise from any pending or future legal
proceedings related to our business activities. While we cannot predict the
outcome of any legal proceedings with certainty, in the opinion of management,
our ultimate liability with respect to these pending lawsuits is not expected to
have a significant or material adverse effect on our consolidated financial
position, results of operations or cash flows.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

There were no matters submitted to a vote of security holders during the
fourth quarter of 2003.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Our authorized common stock consists of 50,000,000 shares of common stock.
Prior to January 1, 2002, our common stock was divided into two classes
designated as "Class A common stock" and "Class B common stock." On January 1,
2002, all outstanding shares of Class B common stock automatically converted
into shares of Class A common stock, and the authorized common stock reverted to
a single class designated as "common stock." We had 15,922,661 shares
outstanding as of March 10, 2004, held by 82 record holders. The number of
record holders of our common stock does not include the stockholders for whom
shares are held in a "nominee" or "street" name. We had 5,000,000 shares of
preferred stock authorized at March 10, 2004, of

18

which 500,000 shares are designated Series A Junior Participating Preferred
Stock and 15,000 shares are designated Series B Convertible Preferred Stock. At
that date, there were no Series A preferred shares outstanding and 15,000 Series
B preferred shares outstanding, issued to one record holder. Our common stock is
traded on the New York Stock Exchange under the ticker symbol NTG.

The following table sets forth, for the calendar quarters indicated, the
high and low sales prices of our common stock reported by the NYSE for each of
the years ended December 31, 2003, 2002 and 2001.

Pursuant to the terms of our Series B preferred stock, we pay an annual
dividend to holders of such stock of 10% of the face value of the stock. We do
not intend to declare or pay any dividends on our common stock in the
foreseeable future, but rather intend to retain any future earnings in excess of
the preferred stock dividend amount for use in the business. Our credit facility
restricts our ability to pay dividends and other distributions.

In March 2003, we issued 15,000 shares of Series B Convertible Preferred
Stock ("Series B Preferred Shares") and warrants to purchase 248,800 shares of
our common stock, to Lime Rock Partners II, L.P., a private investment fund, for
an aggregate purchase price of $15.0 million. Approximately $99,000 of the
aggregate purchase price was allocated to the warrants. Proceeds from the
issuance of these securities, net of related estimated issuance costs of
approximately $800,000, were used to reduce our outstanding revolving debt
balances and for other general corporate purposes. These securities were issued
in a private offering to a single purchaser and were exempt from registration
under Section 4(2) of the Securities Act of 1933, as amended. The Series B
Preferred Shares and warrant are convertible into, or exercisable for, shares of
our common stock. The terms of conversion and exercise are disclosed in Note 3,
Capital Stock, Redeemable Convertible Preferred Stock and Equity, to the Notes
to our consolidated financials statements included in Item 8 of this document.

19

ITEM 6. SELECTED FINANCIAL DATA

The following summary consolidated historical financial information for the
periods and the dates indicated should be read in conjunction with our
consolidated historical financial statements.

- ---------------

(1) We recorded the cumulative effect of a change in accounting principles
associated with the adoption of Statement of Financial Accounting Standards
No. 143, "Accounting for Asset Retirement Obligations." See Note 13, Change
in Accounting Principle in the accompanying Notes to Consolidated Financial
Statements.

20

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

The following discussion of our historical results of operations and
financial condition should be read in conjunction with our consolidated
financial statements and notes thereto.

OVERVIEW

We offer products and services as either integrated systems or individual
components primarily through three business lines:

- traditional production equipment and services, through which we provide
standardized components, replacement parts and used components and
equipment servicing;

- engineered systems, through which we provide customized, large scale
integrated oil, gas and water production and processing systems; and

- automation and control systems, through which we provide control panels
and systems that monitor and control oil and gas production, as well as
repair, testing and inspection services for existing systems.

We report three separate business segments: North American Operations,
Engineered Systems and Automation and Control Systems.

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K, including Management's Discussion and
Analysis of Financial Condition and Results of Operations, includes
forward-looking statements within the meaning of Section 27A of the Securities
Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934,
as amended (each a "Forward-Looking Statement"). The words "believe," "expect,"
"plan," "intend," "estimate," "project," "will," "could," "may" and similar
expressions are intended to identify Forward-Looking Statements. Forward-Looking
Statements in this document include, but are not limited to, discussions of
accounting policies and estimates, indicated trends in the level of oil and gas
exploration and production and the effect of such conditions on our results of
operations (see "--Industry and Business Environment"), future uses of and
requirements for financial resources (see "--Liquidity and Capital Resources"),
and anticipated backlog levels for 2004. Our expectations about our business
outlook, customer spending, oil and gas prices and the business environment for
the industry, in general, and us, in particular, are only our expectations
regarding these matters. Actual results may differ materially from those in the
Forward-Looking Statements herein for reasons including, but not limited to:
market factors such as pricing and demand for petroleum related products, the
level of petroleum industry exploration and production expenditures, the effects
of competition, world economic conditions, the level of drilling activity, the
legislative environment in the United States and other countries, policies of
OPEC, conflict in major petroleum producing or consuming regions, acts of
terrorism, the development of technology which could lower overall finding and
development costs, weather patterns and the overall condition of capital markets
for countries in which we operate.

The following discussion should be read in conjunction with the financial
statements, related notes and other financial information appearing elsewhere in
this Annual Report on Form 10-K. Readers are also urged to carefully review and
consider the various disclosures advising interested parties of the factors that
affect us, including, without limitation, the disclosures made under the caption
"Risk Factors" and the other factors and risks discussed in this Annual Report
on Form 10-K and in subsequent reports filed with the Securities and Exchange
Commission. We expressly disclaim any obligation or undertaking to release
publicly any updates or revisions to any Forward-Looking Statement to reflect
any change in our expectations with regard thereto or any change in events,
conditions or circumstances on which any Forward-Looking Statement is based.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of our consolidated financial statements requires us to
make certain estimates and assumptions that affect the results reported in our
consolidated financial statements and accompanying notes.

21

These estimates and assumptions are based on historical experience and on our
future expectations that we believe to be reasonable under the circumstances.
Note 2 to our consolidated financial statements contains a summary of our
significant accounting policies. We believe the following accounting policies
are the most critical in the preparation of our consolidated financial
statements.

Revenue Recognition: Percentage-of-Completion Method. We recognize
revenues from significant contracts (contracts greater than $250,000 and longer
than four months in duration) and certain automation and controls contracts and
orders on the percentage of completion method of accounting. Earned revenue is
based on the percentage that costs incurred to date relate to total estimated
costs of the project, after giving effect to the most recent estimates of total
cost. The timing of costs incurred, and therefore recognition of revenue, could
be affected by various internal or external factors including, but not limited
to: changes in project scope (change orders), changes in productivity,
scheduling, the cost and availability of labor, the cost and availability of raw
materials, the weather, client delays in providing approvals at benchmark stages
of the project and the timing of deliveries from third-party providers of key
components. The cumulative impact of revisions in total cost estimates during
the progress of work is reflected in the period in which these changes become
known. Earned revenue reflects the original contract price adjusted for agreed
claims and change order revenues, if applicable. Losses expected to be incurred
on the jobs in progress, after consideration of estimated probable minimum
recoveries from claims and change orders, are charged to income as soon as such
losses are known. Claims for additional contract revenue are recognized if it is
probable that the claim will result in additional revenue and the amount can be
reliably estimated. We generally recognize revenue and earnings to which the
percentage-of-completion method applies over a period of two to six or more
quarters. In the event a project is terminated by our customer before
completion, our customer is liable for costs incurred under the contract. We
believe that our operating results should be evaluated over a term of several
years to evaluate our performance under long-term contracts, after all change
orders, scope changes and cost recoveries have been negotiated and realized. We
record revenues and profits on all other sales as shipments are made or services
are performed.

Impairment Testing: Goodwill. As required by Statement of Financial
Accounting Standards ("SFAS") No. 142, "Goodwill and Other Intangible Assets,"
we evaluate goodwill annually for impairment by comparing the fair value of
operating assets to the carrying value of those assets, including any related
goodwill. As required by SFAS No. 142, we identify separate reportable units for
purposes of this evaluation. In determining carrying value, we segregate assets
and liabilities that, to the extent possible, are clearly identifiable by
specific reportable unit. Certain corporate and other assets and liabilities,
that are not clearly identifiable by specific reportable unit, are allocated in
accordance with the standard. Fair value is determined by discounting projected
future cash flows at our cost of capital rate, as calculated. The fair value is
then compared to the carrying value of the reportable unit to determine whether
or not impairment has occurred at the reportable unit level. In the event an
impairment is indicated, an additional test is performed whereby an implied fair
value of goodwill is determined through an allocation of the fair value to the
reporting unit's assets and liabilities, whether recognized or unrecognized, in
a manner similar to a purchase price allocation, in accordance with SFAS No.
141, "Business Combinations." Any residual fair value after this purchase price
allocation would be assumed to relate to goodwill. If the carrying value of the
goodwill exceeded the residual fair value, we would record an impairment charge
for that amount. Net goodwill was $80.1 million at December 31, 2003. We tested
goodwill for impairment as required by SFAS No. 142 at December 31, 2003, and we
did not record an impairment charge as a result of this testing.

Deferred Income Tax Assets: Valuation Allowance. We account for income
taxes in accordance with SFAS No. 109, "Accounting for Income Taxes." SFAS No.
109 requires us to provide a valuation allowance for any net deferred income tax
assets that we believe will not be utilized through future operations. For the
most recent fiscal years, our Canadian subsidiary has recorded net losses, as
consolidated, partially due to certain restructuring efforts undertaken in late
2002 and early 2003, and the impact of certain foreign currency transactions. As
a result of these losses, we recorded a $349,000 valuation allowance at December
31, 2003 to fully reserve for the net deferred tax asset at this subsidiary. We
have a $258,000 valuation allowance related to the realizability of certain net
operating losses related to Axsia, and another $152,000 related to other foreign
operations. Based upon the level of historical taxable income and projected
future taxable income over

22

the periods to which our deferred tax assets are deductible, we believe it is
more likely than not that we will realize the benefits of these deductible
differences, net of the existing valuation allowances at December 31, 2003.
However, the amount of the deferred tax asset considered realizable, and thus
the amount of these valuation allowances, could change if future taxable income
differs from our projections.

ACQUISITIONS

In November 1998, we acquired all the outstanding common stock of The
Cynara Company ("Cynara"), a designer and manufacturer of specialized production
equipment utilizing membrane technology to separate bulk carbon dioxide from
natural gas streams, for approximately $15.5 million, 500,000 shares of our then
outstanding Class B Common Stock and the right to receive additional shares of
common stock based upon the financial performance of the Cynara assets.
Ultimately, we issued 752,501 additional shares, as Class B Common Stock to
former Cynara stockholders under this provision. All Class B Common Stock
automatically converted to common stock, on a share-for-share basis, on January
1, 2002.

In March 2001, we acquired all the outstanding share capital of Axsia
Holdings Limited, a privately held process and design company based in the
United Kingdom, for approximately $42.8 million, net of cash acquired. Axsia
specializes in the design and supply of equipment for water re-injection systems
for oil and gas fields, oily water treatment, oil separation, hydrogen
production and other oil and gas processing equipment systems. This acquisition
was financed with borrowings under our 2001 term loan and revolving credit
facility.

We accounted for each of the above transactions using the purchase method
of accounting.

INDUSTRY AND BUSINESS ENVIRONMENT

As a leading provider of wellhead process equipment, systems and services
used in the production of oil and gas, our revenues and results of operations
are closely tied to demand for oil and gas products and spending by oil and gas
companies for exploration and development of oil and gas reserves. These
companies generally invest more in exploration and development efforts during
periods of favorable oil and gas commodity prices, and invest less during
periods of unfavorable oil and gas prices. As supply and demand change,
commodity prices fluctuate producing cyclical trends in the industry. During
periods of lower demand, revenues for service providers such as NATCO generally
decline, as existing projects are completed and new projects are postponed.
During periods of recovery, revenues for service providers can lag behind the
industry due to the timing of new project awards.

Changes in commodity prices have impacted our business over the past
several years. The following table summarizes the price of domestic crude oil
per barrel and the wellhead price of natural gas per thousand cubic feet
("mcf"), as published by the U.S. Department of Energy, and the number of rotary
drilling rigs in operation, as published by Baker Hughes Incorporated, for the
most recent five years:

At December 31, 2003, the spot price of West Texas Intermediate crude oil
was $32.51 per barrel, the price of natural gas was $5.96 per mcf, and the U.S.
rig count was 1,114. At February 27, 2004, the spot price of West Texas
Intermediate crude oil was $36.08 per barrel, the price of Henry Hub natural gas
was $5.27 per mcf, as per the New York Mercantile Exchange, and the U.S. rig
count was 1,134, per Baker Hughes Incorporated. These spot prices reflect the
overall volatility of oil and gas commodity prices in the current and recent
years. Historically, we have viewed operating rig counts as a benchmark of
spending in the oil and gas industry for exploration and development efforts.
Our traditional equipment sales and services business generally correlates to
changes in rig activity, but tends to lag behind the North American rig count
trend. From a longer-term perspective, the U.S. Department of Energy estimates
that U.S. demand for and

23

consumption of petroleum and natural gas products will increase through 2025,
with higher consumption rates expected worldwide, driven by demand for refined
products and the use of natural gas to power plants that generate electricity.
As demand grows and reserves in the United States decline, producers and service
providers in the oil and gas industry may continue to rely more heavily on
global sources of energy and expansion into new markets. The industry continues
to seek more innovative and technologically efficient means to extract
hydrocarbons from existing fields, as production profiles change. As a result,
additional and more complex equipment may be required to produce oil and gas
from these fields, especially since many new oil and gas fields produce lower
quality or contaminated hydrocarbon streams, requiring more complex production
equipment. In general, these trends should increase the demand for our products
and services.

Our Engineered Systems business is impacted largely by the awarding and
completion of larger, more complex oil and gas projects, primarily for
international offshore locations. These projects typically have a longer
bidding, evaluation, awarding and construction period than our traditional
equipment and services business and are more subject to our customers' long-term
view of the oil and gas supply and demand outlook for the related region, as
well as expected commodity prices and political or governmental situations. In
recent periods, we have experienced the absence of, delays in, or lack of large
international projects with favorable economic terms, which has impacted our
Engineered Systems business results as well as our current level of project
bookings for this segment.

During the fourth quarter of 2002 and throughout 2003, we streamlined
certain of our operations to decrease excess capacity and be more responsive to
current market trends, including the closure and consolidation of manufacturing
facilities in Edmonton, Alberta, Canada, and Covington, Louisiana. Furthermore,
we reallocated certain internal resources, consolidated certain Engineered
Systems operations in the U.K., and closed an Engineered Systems business
development office in Singapore.

In December 2003, we placed into service an expansion of our gas-processing
facilities at Sacroc. This expansion will increase our operating capacity at
this facility from 180 mmcf per day to 367 mmcf per day. Our operating agreement
for this facility provides for daily processing minimums, and we project that
this operation will contribute significantly to earnings and cash flows for 2004
compared to 2003. Therefore, we expect a larger percentage of our revenues and
margins in 2004, compared to 2003, to be attributable to our CO(2)
gas-processing business, a component of our North American Operations segment.

The following discussion of our historical results of operations and
financial condition should be read in conjunction with our audited consolidated
financial statements and notes thereto.

RESULTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 2003 COMPARED TO YEAR ENDED DECEMBER 31, 2002

Revenues. Revenues for the year ended December 31, 2003 decreased $8.1
million, or 3%, to $281.5 million, from $289.5 million for the year ended
December 31, 2002. The overall decline in revenues was primarily attributable to
a slower than expected recovery in the oil and gas industry, following a
downturn in 2001, and the cyclical nature of the industry. The following table
summarizes revenues by business segment for the years ended December 31, 2003
and 2002, respectively:

Revenues from our North American Operations segment for the year ended
December 31, 2003 decreased $4.7 million, or 3%, to $132.7 million from $137.4
million for the year ended December 31, 2002. This decrease was related
primarily to a decline in the number of traditional equipment projects in
progress in 2003 compared to 2002, and a decline in revenues contributed by our
operations in Mexico and membrane replacement sales for the respective periods.
These declines were partially offset by higher parts and service sales, as well
as an increase in revenues derived from our CO(2) gas-processing business. The
increase in parts and service sales was directly attributable to an increase in
oilfield activity in 2003 compared to 2002, as the average U.S. rotary rig count
increased from 830 for the year ended December 31, 2002 to 1,030 for the year
ended December 31, 2003. Revenues from our Canadian operations increased during
2003 due to several large projects that were completed during the year. Canadian
rotary rig counts increased from an average of 263 for the year ended December
31, 2002 to 372 for the year ended December 31, 2003. Inter-segment revenues for
this business segment were approximately $1.4 million and $917,000 for the years
ended December 31, 2003 and 2002, respectively.

Revenues from our Engineered Systems segment for the year ended December
31, 2003 decreased $8.8 million, or 8%, to $98.3 million from $107.0 million for
the year ended December 31, 2002. This decrease was primarily due to a decline
in the number of large international production system jobs in 2003 relative to
2002, partially due to project delays and increased competition. Engineered
Systems revenues of $98.3 million for the year ended December 31, 2003 included
inter-segment revenues of $784,000, compared to $1.8 million of inter-segment
revenues for the year ended December 31, 2002.

Revenues from our Automation and Control Systems segment for the year ended
December 31, 2003 increased $4.5 million, or 9%, to $56.7 million from $52.1
million for the year ended December 31, 2002. The increase was primarily related
to a general increase in the number of jobs in progress during 2003 compared to

25

2002, and the completion of several larger projects in 2003. Inter-segment
revenues decreased from $4.3 million for the year ended December 31, 2002 to
$4.0 million for the year ended December 31, 2003.

The change in revenues for corporate and inter-segment eliminations
represents the elimination of inter-segment revenues discussed above.

Gross Profit. Gross profit for the year ended December 31, 2003 decreased
$4.2 million, or 6%, to $66.0 million from $70.2 million for the year ended
December 31, 2002. As a percentage of revenue, gross margins declined from 24%
for the year ended December 31, 2002 to 23% for the year ended December 31,
2003, largely due to the decline in margins associated with our North American
Operations business and an overall decline in sales for the respective periods.
The following table summarizes gross profit by business segment for the years
ended December 31, 2003 and 2002, respectively:

Gross profit from our North American Operations segment for the year ended
December 31, 2003 decreased $3.8 million, or 10%, to $33.8 million from $37.6
million for the year ended December 31, 2002. This decrease in gross profit was
primarily due to a 3% decline in sales for the segment for the respective
period, including a decline in more favorable margin sales related to our Latin
American operations and our membrane replacement sales, as several higher margin
membrane sales were completed in 2002. As a percentage of revenue, gross margins
for the segment were 25% and 27% for the years ended December 31, 2003 and 2002,
respectively.

Gross profit from our Engineered Systems segment for the year ended
December 31, 2003 decreased $688,000, or 3%, to $22.5 million from $23.2 million
for the year ended December 31, 2002. This decline in gross profit was primarily
related to an 8% decline in sales, partially offset by improved overall
performance. As a percentage of revenue, gross margins for this segment were 23%
and 22% for the years ended December 31, 2003 and 2002, respectively.

Gross profit from our Automation and Control Systems segment for the years
ended December 31, 2003 and 2002 increased $314,000, or 3%, to $9.7 million from
$9.4 million. This increase was primarily due to a 9% increase in sales for the
segment for the respective period, partially offset by an unfavorable mix of
projects in 2003 and increased competition for jobs in the Gulf of Mexico. As a
percentage of revenue, gross margins for this segment were 17% and 18% for the
years ended December 31, 2003 and 2002, respectively.

Selling, General and Administrative Expense. Selling, general and
administrative expense for the year ended December 31, 2003 decreased $2.5
million, or 5%, to $51.5 million from $53.9 million for the year ended December
31, 2002. This decrease was largely due to a decline in variable compensation
based on operating results and the impact of restructuring activities in Canada
during the fourth quarter of 2002 and other restructuring efforts in the U.S.
and U.K. during the last six months of 2003. These expense decreases were
partially offset by higher employee medical costs, workers' compensation
insurance claim costs, higher professional fees and other corporate insurance
policies. Overall headcount declined from 1,700 employees at December 31, 2002
to 1,664 employees at December 31, 2003.

Depreciation and Amortization Expense. Depreciation and amortization
expense for the year ended December 31, 2003 increased $111,000, or 2%, to $5.1
million from $5.0 million for the year ended December 31, 2002. The increase in
depreciation expense relates to the Sacroc gas processing facility expansions.
Amortization expense was approximately $100,000 for the years ended December 31,
2003 and 2002, and related primarily to patents and other intangible assets.

26

Closure and Other. Closure and other charges for the year ended December
31, 2003 of $2.1 million related to certain restructuring activities in the
third quarter of 2003 including the closure of a manufacturing facility in
Covington, Louisiana, the consolidation of operations in the U.K., and
post-employment benefits for terminated employees at these locations and at our
corporate office. In addition, costs were incurred related to the closure of our
Singapore marketing office in the fourth quarter of 2003, including certain
lease termination costs and post-employment benefits for terminated employees.
During the year ended December 31, 2002, we incurred costs of $548,000 related
to the closure of a manufacturing and engineering facility in Edmonton, Alberta,
Canada. Costs included the involuntary termination of certain employees,
relocation of equipment and certain personnel and the modification of related
operating lease arrangements. At December 31, 2002, our remaining accrued
liability related to this Canadian restructuring effort was $304,000, and we
incurred additional relocation and shop moving costs totaling $230,000 during
2003.

Interest Expense. Interest expense for the year ended December 31, 2003
decreased $442,000, or 10%, to $4.1 million from $4.5 million for the year ended
December 31, 2002. This decrease was due to a decline in outstanding debt from
$52.4 million at December 31, 2002 to $43.6 million at December 31, 2003. The
weighted average interest rate of our outstanding borrowings was approximately
4% for the years ended December 31, 2003 and 2002.

Interest Cost on Postretirement Benefit Liability. Interest cost on
postretirement benefit liability increased $366,000, or 78%, from $471,000 for
the year ended December 31, 2002 to $837,000 for the year ended December 31,
2003. This increase in interest cost was due to a decrease in the discount rate
used to actuarially determine the present value of our postretirement obligation
under this arrangement, consistent with a general decline in interest rates in
recent years.

Other Expense, net. Other expense, net of $1.2 million for the year ended
December 31, 2003, increased $811,000, or 203%, compared to the year ended
December 31, 2002. The change related primarily to net foreign currency losses
incurred through our operations in the United Kingdom and Canada, due to a
significant devaluation of the U.S. dollar relative to these foreign currencies
during the year ended December 31, 2003.

Provision for Income Taxes. Income tax expense for the year ended December
31, 2003 decreased $462,000, or 27%, to $1.2 million from $1.7 million for the
year ended December 31, 2002. This decline in income tax expense was primarily
due to a decrease in income before income taxes, which was $5.6 million for the
year ended December 31, 2002, compared to $1.4 million for the year ended
December 31, 2003. The increase in the effective tax rate from 30.5% for the
year ended December 31, 2002 to 90.2% for the year ended December 31, 2003, was
due primarily to the decline in pre-tax income, as permanent tax differences
represented a greater portion of total taxable income, and a valuation allowance
recorded as of December 31, 2003, to reserve for certain deferred tax assets
related to our Canadian operations.

Preferred Stock Dividends. We recorded preferred stock dividends totaling
$1.2 million for the year ended December 31, 2003 related to our Series B
Convertible Preferred Stock, issued to a private investment fund in March 2003.

27

YEAR ENDED DECEMBER 31, 2002 COMPARED TO YEAR ENDED DECEMBER 31, 2001

Revenues. Revenues for the year ended December 31, 2002 increased $3.0
million, or 1%, to $289.5 million, from $286.6 million for the year ended
December 31, 2001. The following table summarizes revenues by business segment
for the years ended December 31, 2002 and 2001, respectively:

Revenues from our North American Operations segment for the year ended
December 31, 2002 decreased $7.8 million, or 5%, to $137.4 million from $145.1
million for the year ended December 31, 2001. This decrease was directly related
to a decline in oilfield activity throughout 2002. The average North American
rotary rig count declined from 1,497 for the year ended December 31, 2001 to
1,093 for the year ended December 31, 2002. Although revenues for our
traditional equipment and finished goods declined, results for our Latin
American operations and CO2 gas-processing operations and field services
improved during 2002 relative to 2001. Revenues from our Canadian operations
decreased as Canadian rotary rig counts continued to decline from an average of
341 for the year ended December 31, 2001 to an average of 263 for the year ended
December 31, 2002. Inter-segment revenues for this business segment were
approximately $917,000 and $781,000 for the years ended December 31, 2002 and
2001, respectively.

Revenues from our Engineered Systems segment for the year ended December
31, 2002 increased $8.0 million, or 8%, to $107.0 million from $99.0 million for
the year ended December 31, 2001. This increase was primarily due to several
large projects, primarily in West Africa, that provided revenues of
approximately $31.0 million during 2002, offset by a decline in revenues from
our U.K.-based operations and a decline in revenues earned in Southeast Asia,
with the substantial completion of the CTOC project in late 2001. Engineered
systems revenues of $107.0 million for the year ended December 31, 2002 included
inter-segment revenues of $1.8 million, as compared to $748,000 of inter-segment
revenues for the year ended December 31, 2001.

Revenues from our Automation and Control Systems segment for the year ended
December 31, 2002 increased $4.4 million, or 9%, to $52.1 million from $47.7
million for the year ended December 31, 2001. The increase was due to higher
demand for our control equipment and field services, partially associated with
repair projects in the Gulf of Mexico following several tropical weather systems
in 2002. Inter-segment revenues increased from $3.8 million for the year ended
December 31, 2001 to $4.3 million for the year ended December 31, 2002.

The change in revenues for corporate and inter-segment eliminations
represents the elimination of inter-segment revenues as discussed above.

28

Gross Profit. Gross profit for the year ended December 31, 2002 decreased
$5.9 million, or 8%, to $70.2 million from $76.1 million for the year ended
December 31, 2001. As a percentage of revenue, gross margins declined from 27%
for the year ended December 31, 2001 to 24% for the year ended December 31,
2002. The following table summarizes gross profit by business segment for the
years ended December 31, 2002 and 2001, respectively:

Gross profit from our North American Operations segment for the year ended
December 31, 2002 increased $2.1 million, or 6%, to $37.6 million from $35.5
million for the year ended December 31, 2001. This increase in margin was
primarily due to the contribution of our Latin American operations and our CO(2)
gas-processing operations and field services, reflecting increased throughput
from the expansion at our Sacroc facility. As a percentage of revenue, gross
margins for the segment were 27% and 24% for the years ended December 31, 2002
and 2001, respectively.

Gross profit from our Engineered Systems segment for the year ended
December 31, 2002 decreased $8.0 million, or 26%, to $23.2 million from $31.2
million for the year ended December 31, 2001, despite an 8% increase in
revenues. This decline was due to the completion of several high-margin projects
during 2001 in Southeast Asia and within our U.K.-based operations, partially
offset by new projects for 2002 awarded at more traditional margins. As a
percentage of revenue, gross margins for this segment were 22% and 32% for the
years ended December 31, 2002 and 2001, respectively.

Gross profit from our Automation and Control Systems segment for the years
ended December 31, 2002 and 2001 remained constant, despite a 9% increase in
revenues for the period, primarily due to an increase in labor costs
attributable to higher medical benefit costs and an unfavorable mix of labor and
materials in 2002 compared to 2001. As a percentage of revenue, gross margins
for this segment were 18% and 20% for the years ended December 31, 2002 and
2001, respectively.

Selling, General and Administrative Expense. Selling, general and
administrative expense for the year ended December 31, 2002 increased $2.5
million, or 5%, to $53.9 million from $51.5 million for the year ended December
31, 2001. This increase was largely related to the following factors: one year
of operating expenses at Axsia during 2002 compared to nine months during fiscal
2001; additional costs associated with the start-up of the Singapore office in
March 2001; costs associated with the start-up of the Mexico marketing office
opened in late 2001; and additional costs associated with employee medical
claims.

Depreciation and Amortization Expense. Depreciation and amortization
expense for the year ended December 31, 2002 decreased $3.2 million, or 39%, to
$5.0 million from $8.1 million for the year ended December 31, 2001.
Depreciation expense for the year ended December 31, 2002 increased $764,000, or
19%, to $4.9 million from $4.1 million for the year ended December 31, 2001.
This increase was primarily due to the inclusion of depreciation expense on
assets acquired through the purchase of Axsia in March 2001, and depreciation on
assets placed in service in late 2001 and 2002, including a significant upgrade
of our drying plant facility in Pittsburg, California, and the expansion of our
gas-processing plant at the Sacroc field. Amortization expense for the year
ended December 31, 2002 decreased $3.9 million, or 98%, to $92,000 from $4.0
million for the year ended December 31, 2001. This decrease in amortization
expense was attributable to a change in accounting method prescribed by SFAS No.
142, "Goodwill and Other Intangible Assets." This pronouncement, adopted on
January 1, 2002, requires that goodwill no longer be amortized over a prescribed
period but rather intangible assets not assigned a useful life be evaluated
annually for impairment. See "--Recent Accounting Pronouncements." Therefore, no
goodwill amortization was recorded for the year

29

ended December 31, 2002, compared to $3.7 million for the year ended December
31, 2001. In addition, the results for the year ended December 31, 2001 include
amortization expense associated with certain employment contracts that were
fully amortized as of December 31, 2001.

Closure and Other. Closure and other charges for the year ended December
31, 2002 of $548,000 related to the closure of a manufacturing and engineering
facility in Edmonton, Alberta, Canada. Costs include the involuntary termination
of certain employees, relocation of equipment and certain personnel and the
modification of related operating lease arrangements. At December 31, 2002, our
remaining accrued liability related to this restructuring was $304,000, and we
expect to incur additional relocation and shop moving costs, which will expensed
as incurred through the second quarter of 2003. During the year ended December
31, 2001, we incurred a charge totaling $920,000 related to certain
restructuring costs to streamline activities and consolidate offices in
connection with the acquisition of Axsia in March 2001, and an additional
$680,000 related to our decision to withdraw a private debt offering.

Interest Expense. Interest expense for the year ended December 31, 2002
decreased $414,000, or 8%, to $4.5 million from $4.9 million for the year ended
December 31, 2001. This decrease was due to a decline in outstanding debt from
$58.6 million at December 31, 2001 to $52.4 million at December 31, 2002. The
weighted average interest rate of our outstanding borrowings remained constant
for the respective periods.

Interest Cost on Postretirement Benefit Liability. Interest cost on
postretirement benefit liability decreased $417,000, or 47%, from $888,000 for
the year ended December 31, 2001 to $471,000 for the year ended December 31,
2002. This decrease in interest cost was due to an amendment to the plan that
provides medical and dental coverage to retirees of a predecessor company. Under
the amended plan, retirees will bear more cost for coverages, thereby reducing
our projected liability and the related interest cost.

Interest Income. Interest income decreased $412,000, or 62%, from $660,000
for the year ended December 31, 2001 to $248,000 for the year ended December 31,
2002. This change in interest income was primarily due to interest earned on a
federal income tax refund paid during 2001 by the Canadian taxing authorities.

Other Expense, net. Other expense, net of $400,000 for the year ended
December 31, 2002, declined $29,000, or 7%, compared to the year ended December
31, 2001. The change relates primarily to foreign currency gains and losses
incurred through our operations in the United Kingdom and Canada.

Provision for Income Taxes. Income tax expense for the year ended December
31, 2002 decreased $2.2 million, or 56%, to $1.7 million from $3.9 million for
the year ended December 31, 2001. This decline in income tax expense was
primarily due to a decrease in income before income taxes, which was $5.6
million for the year ended December 31, 2002 as compared to $9.3 million for the
year ended December 31, 2001. The decrease in the effective tax rate from 42.1%
for the year ended December 31, 2001 to 30.5% for the year ended December 31,
2002, was due primarily to no longer recognizing non-deductible goodwill
amortization expense, as per SFAS No. 142, adopted January 1, 2002.

LIQUIDITY AND CAPITAL RESOURCES

As of January 31, 2004, we had cash and working capital of $2.0 million and
$34.6 million, respectively. As of December 31, 2003, we had cash and working
capital of $1.8 million and $34.6 million, respectively, as compared to $1.7
million and $36.3 million at December 31, 2002, respectively. The decline in
working capital is primarily due to the change in current maturities of
long-term debt related to our term loan and revolving credit facility. The
revolving credit facility portion of this loan was to mature on March 31, 2004.
Effective March 15, 2004, we replaced this facility with a new term loan and
revolving credit facility that matures on March 15, 2007, as described in more
detail below.

Net cash provided by operating activities for the years ended December 31,
2003, 2002 and 2001 was $12.6 million, $10.5 million and $19.9 million,
respectively. The increase in net cash provided by operating activities for
fiscal 2003 was primarily due to a decline in accounts receivable due to
increased collection efforts, and an increase in customer advance payments,
partially offset by lower net income and a decline in accrued liabilities. The
timing of accounts receivable billings or collections and the receipt of advance
30

payments depends upon agreed project benchmarks for jobs accounted for under the
percentage of completion method of accounting, and tends to fluctuate between
reporting periods.

Net cash used in investing activities for the years ended December 31,
2003, 2002 and 2001 was $10.8 million, $5.6 million and $57.7 million,
respectively. The primary use of funds for the year ended December 31, 2003 was
for capital expenditures of $11.5 million, the majority of which related to the
expansion of our Sacroc gas-processing facility, placed in service in December
2003. This cost was partially offset by the proceeds from the sale of a building
in the U.K. The primary use of funds for the year ended December 31, 2002 was
for capital expenditures of $5.3 million, largely related to the expansion at
Sacroc. The primary use of funds for the year ended December 31, 2001 was for
the acquisition of Axsia, which required the use of $48.3 million, and capital
expenditures of $10.0 million, which included the purchase of a manufacturing
facility in Magnolia, Texas, expansion of and improvement to our facilities in
New Iberia, Louisiana, and improvements to our Sacroc plant. Funds for the Axsia
acquisition were borrowed under a $50.0 million term loan facility. Capital
expenditures for fiscal 2001 were financed with borrowings under our revolving
credit facility and cash generated from current operations.

Net cash provided by (used in) financing activities for the years ended
December 31, 2003, 2002 and 2001 was ($1.8) million, ($6.2) million and $40.5
million, respectively. The primary use of funds for financing activities for the
year ended December 31, 2003 was the repayment of long-term debt and revolving
credit debt of $7.1 million and $2.1 million, respectively, as well as $1.6
million of net benefit costs under a postretirement benefit plan and $4.0
million of bank overdraft reductions. These uses of cash for financing
activities were largely offset by gross proceeds of $15.0 million less issuance
costs and fair value allocable to related stock warrants, or a net of $14.1
million, from the issuance of our Series B Convertible Preferred Stock, less
dividends paid on those shares of $1.2 million. The primary use of funds for the
year ended December 31, 2002 was the repayment of long-term debt of $7.1 million
and benefit payments under our postretirement benefit plan of $1.9 million,
partially offset by long-term borrowings of $1.5 million and a $1.9 million
increase in bank overdrafts. Proceeds from the issuance of our Series B
Convertible Preferred Stock were used for working capital needs and to fund
expansion of the Sacroc facility. The primary source of funds for financing
activities during the year ended December 31, 2001, was borrowings of $50.0
million under the term loan facility, partially offset by principal repayments
of $5.3 million under the term loan facility, net repayments of $747,000 under
the revolving credit facilities, payments on postretirement benefit liability of
$1.8 million and repayment of short-term notes of $1.0 million.

We maintain revolving credit and term loan facilities, as well as a working
capital facility for export sales. Our prior term loan, in effect during 2003,
provided an initial $50.0 million of borrowings and the revolving credit
facilities provide for up to $30.0 million of borrowings in the United States,
up to $10.0 million of borrowings in Canada and up to $10.0 million of
borrowings in the United Kingdom, subject to borrowing base limitations. The
term loan was to mature on March 31, 2006, and each of the revolving facilities
was to mature on March 31, 2004. These facilities were entered into in 2001, and
we refer to these facilities as the 2001 facilities.

On March 15, 2004, we replaced our 2001 term loan and revolving credit
facilities with a term loan and revolving credit arrangement that provides for a
term loan of $45.0 million, a U.S. revolving facility with a borrowing capacity
of $20.0 million, a Canadian revolving facility with a borrowing capacity of
$5.0 million, and a U.K. revolving credit facility with a borrowing capacity of
$10.0 million. All of the borrowing capacities under the revolving credit
facilities are subject to borrowing base limitations.

The 2004 term loan and revolving facilities provide for interest at a rate
based upon the ratio of funded debt to EBITDA, as defined in the credit facility
("EBITDA"), and ranging from, at our election, (1) a high of LIBOR plus 2.75% to
a low of LIBOR plus 2.00% or, (2) a high of a base rate plus 1.75% to a low of a
base rate plus 1.00%. NATCO will pay commitment fees related to this facility,
based upon the ratio of Funded Debt to EBITDA, on the undrawn portion of the
facility.

The 2004 term loan and revolving facilities require quarterly payments of
$1.6 million, beginning in June 2004, and mature on March 15, 2007. We intend to
borrow funds under the 2004 term loan and revolving

31

credit facilities to retire debt outstanding under the 2001 term loan and
revolving credit facilities as of March 15, 2004.

At December 31, 2003, we had borrowings outstanding under the term loan
facility of $30.8 million and borrowings of $10.9 million outstanding under the
revolving credit facilities and had issued $19.8 million in outstanding letters
of credit under these facilities. Amounts borrowed under the term loan portion
of the 2001 facility bore interest at a rate of 3.91% per annum. Amounts
borrowed under the revolving portion of the 2001 facility bore interest at a
rate based upon the ratio of Funded Debt to EBITDA, as defined in the credit
facility ("EBITDA"), and ranged from, at our election, (1) a high of LIBOR plus
2.50% to a low of LIBOR plus 1.75% or (2) a high of a base rate plus 1.0% to a
low of a base rate plus 0.25%.

Under the 2001 facilities, we were required to pay commitment fees of 0.30%
to 0.625% per year, depending upon the ratio of Funded Debt to EBITDA, on the
undrawn portion of the facility. As of December 31, 2003, our commitment fees
were calculated at a rate of 0.625%.

In July 2002, our lenders approved the amendment of various provisions of
the 2001 term loan and revolving credit facility agreement, effective April 1,
2002. This amendment revised certain restrictive debt covenants, modified
certain defined terms, allowed for future capital investment in our Sacroc CO(2)
processing facility in West Texas, facilitates the issuance of $7.5 million of
subordinated debt, increased the aggregate amount of operating lease expense
allowed during a fiscal year and permitted an increase in borrowings under the
export sales credit facility, without further consent, up to a maximum of $20.0
million. These modifications resulted in higher commitment fee percentages and
interest rates than in the original agreements, based on the Funded Debt to
EBITDA ratio, as defined in the underlying agreement, as amended.

In July 2003, our lenders approved an amendment of the 2001 term loan and
revolving credit facilities, effective April 1, 2003. The amendment modified
several restrictive covenant terms, including the Fixed Charge Coverage Ratio
and Funded Debt to EBITDA Ratio, each as defined in the agreement.

Under our 2001 term loan and revolving credit facilities agreement, certain
of our debt covenants became more restrictive during the fourth quarter of 2003.
In December 2003, the Company obtained a waiver to certain debt covenants
including those related to net worth, funded debt to EBITDA and fixed charge
coverage ratio through March 31, 2004, subject to meeting a minimum EBITDA
threshold. The Company met this threshold requirement as of December 31, 2003,
and was in compliance with all covenant requirements, as amended, as of that
date. The weighted average interest rate of our borrowings under the 2001 term
loan and revolving credit agreement on December 31, 2003 was 4.16%.

We and our operating subsidiaries guarantee our 2004 term loan and
revolving credit facilities, which are secured by a first lien or first priority
security interest in or pledge of substantially all of the assets of the
borrowers, including accounts receivable, inventory, equipment, intangibles,
equity interests in U.S. subsidiaries and 66 1/3% of the equity interest in
active, non-U.S. subsidiaries. Our assets and those of our active U.S.
subsidiaries secure the U.S., Canadian and U.K. facilities, assets of our
Canadian subsidiary also secure the Canadian facility and assets of our U.K.
subsidiaries also secure the U.K. facility. The U.S. facility is guaranteed by
each of our U.S. subsidiaries, while the Canadian and U.K. facilities are
guaranteed by us, each of our U.S. subsidiaries and the Canadian subsidiary or
the U.K. subsidiaries, as applicable.

The 2004 term loan and revolving credit facilities contain restrictive
covenants similar to those contained in the 2001 facilities, including, among
others, those that limit the amount of funded debt to EBITDA (as defined in the
2004 facilities), impose a minimum fixed charge coverage ratio, a minimum asset
coverage ratio and a minimum net worth requirement. These facilities also
restrict payment of dividends by us, other than those with respect to the Series
B Preferred Shares.

The export sales credit facility provides for aggregate borrowings of $10.0
million, subject to borrowing base limitations, of which $700,000 was
outstanding as of December 31, 2003. In addition, we had issued letters of
credit totaling $69,000 under the export facility as of that date. Fees related
to these letters of credit at December 31, 2003, were approximately 1% of the
outstanding balance. The export sales credit facility is

32

secured by specific project inventory and receivables and is partially
guaranteed by the Export-Import Bank of the United States. The export sales
credit facility loans mature in July 2004.

We borrowed $1.5 million under a long-term promissory note arrangement to
finance the purchase of a manufacturing facility in Magnolia, Texas in the
fourth quarter of 2001. This note accrues interest at the 90-day LIBOR plus
3.25% per annum, and requires quarterly payments of principal of approximately
$24,000 and interest for five years beginning May 2002. This promissory note is
collateralized by our manufacturing facility in Magnolia, Texas.

We had unsecured letters of credit and bonds totaling $584,000 and
performance guarantees totaling $7.9 million at December 31, 2003.

COMMITMENTS AND CONTINGENCIES

The following table summarizes our known contractual obligations as of
December 31, 2003.

- ---------------

(1) We have no capital lease arrangements as of December 31, 2003.

(2) Purchase obligations were pursuant to material and equipment purchase orders
placed in 2003, with delivery and billing scheduled in 2004. Approximately
$5.8 million of this balance related to one purchase order. No significant
purchase commitments extended beyond one year.

(3) Other long-term liabilities represent our postretirement benefit obligation
as of December 31, 2003. Benefit payments associated with the obligation
were estimated based upon actual experience for the year ended December 31,
2003. Changes in actuarial assumptions or medical trend rates in subsequent
years could cause our liability under this postretirement benefit plan to
change.

We have no special purpose entities or unconsolidated affiliates or
partnerships.

On March 25, 2003, we issued 15,000 shares of Series B Convertible
Preferred Stock ("Series B Preferred Shares") and warrants to purchase 248,800
shares of our common stock, to Lime Rock Partners II, L.P., a private investment
fund, for an aggregate sale price of $15.0 million. Approximately $99,000 of the
aggregate sale price was allocated to the warrants. Proceeds from the issuance
of these securities, net of related estimated issuance costs of approximately
$800,000, were used to reduce our outstanding revolving debt balances and for
other general corporate purposes.

Each of the Series B Preferred Shares has a face value of $1,000 and pays a
cumulative dividend of 10% per annum of face value, which is payable
semi-annually on June 15 and December 15 of each year, except the initial
dividend payment which was paid on July 1, 2003. Each of the Series B Preferred
Shares is convertible, at the option of the holder, into (i) a number of shares
of common stock equal to the face value of such Series B Preferred Share divided
by the conversion price, which was $7.805 (or an aggregate of 1,921,845 shares)
at December 31, 2003, and (ii) a cash payment equal to the amount of dividends
on such shares that have accrued since the prior semi-annual dividend payment
date. As of December 31, 2003, we had no accrued dividends payable related to
the Series B Preferred Shares. During 2003, we paid dividends of $1.2 million to
the holders of the Series B Preferred Shares.

33

In the event of a change in control, as defined in the certificate of
designations for the preferred shares, each holder of the Series B Preferred
Shares has the right to convert the Series B Preferred Shares into common stock
or to cause us to redeem for cash some or all of the Series B Preferred Shares
at an aggregate redemption price equal to the sum of (i) $1,000 (adjusted for
stock splits, stock dividends, etc.) multiplied by the number of shares to be
redeemed, plus (ii) an amount (not less than zero) equal to the product of $500
(adjusted for stock splits, stock dividends, etc.) multiplied by the aggregate
amount of dividends paid in cash since the issuance date, plus any gain on the
related stock warrants. If the holder of the Series B Preferred Shares converts
upon a change in control occurring on or before March 25, 2006, the holder would
also be entitled to receive cash in an amount equal to the dividends that would
have accrued through March 25, 2006 less the sum of the aggregate amount of
dividends paid in cash through the date of conversion, and the aggregate amount
of dividends accrued in prior periods but not yet paid.

We have the right to redeem the Series B Preferred Shares for cash on or
after March 25, 2008, at a redemption price per share equal to the face value of
the Series B Preferred Shares plus the amount of dividends that have been
accrued but not paid since the most recent semi-annual dividend payment date.

We adopted SFAS No. 150, "Accounting for Certain Instruments with
Characteristics of both Liabilities and Equity," on July 1, 2003. Under SFAS No.
150, the Series B Preferred Shares would be classified as permanent equity.
However, due to the cash redemption features upon a change in control as
described above, the Series B Preferred Shares do not qualify for permanent
equity treatment in accordance with the Emerging Issues Task Force Topic D-98:
"Classification and Measurement of Redeemable Securities," which specifically
requires that permanent equity treatment be precluded for any security with
redemption features that are not solely within the control of the issuer.
Therefore, we have accounted for the Series B Preferred Shares as temporary
equity in the accompanying balance sheet, and have not assigned any value to its
right to redeem the Series B Preferred Shares on or after March 25, 2008.

If the Series B Preferred Shares are converted under contingent redemption
features, any redemption amount greater than carrying value would be recorded as
a reduction of income available to common shareholders when the event becomes
probable.

If we fail to pay dividends for two consecutive periods or any redemption
price due with respect to the Series B Preferred Shares for a period of 60 days
following the payment date, we will be in default under the terms of such
shares. During a default period, (1) the dividend rate on the Series B Preferred
Shares would increase to 10.25%, (2) the holders of the Series B Preferred
Shares would have the right to elect or appoint a second director to the Board
of Directors and (3) we would be restricted from paying dividends on, or
redeeming or acquiring our common or other outstanding stock, with limited
exceptions. If we fail to set aside or make payments in cash of any redemption
price due with respect to the Series B Preferred Shares, and the holders elect,
our right to redeem the shares may be terminated.

The warrants issued to Lime Rock Partners II, L.P. have an exercise price
of $10.00 per share of common stock and expire on March 25, 2006. We can force
exercise of the warrants if our common stock trades above $13.50 per share for
30 consecutive days. The warrants contain a provision whereby the holder could
require us to make a net-cash settlement for the warrants in the case of a
change in control. The warrants were deemed to be derivative instruments and,
therefore, the warrants were recorded at fair value as of the issuance date.
Fair value, as agreed with the counter-party to the agreement, was calculated by
applying a pricing model that included subjective assumptions for stock
volatility, expected term that the warrants would be outstanding, a dividend
rate of zero and an overall liquidity factor. The resulting liability,
originally recorded at $99,000, was increased to $154,000 as of December 31,
2003, as a result of the change in fair value of the warrants. Similarly,
changes in fair value in future periods will be recorded in net income during
the period of the change.

At January 31, 2004, available borrowing capacity under the 2001 term loan
and revolving credit agreement and the export sales credit agreement were $19.8
million and $981,000, respectively.

Although no assurances can be given, we believe that our operating cash
flow, supported by our borrowing capacity, will be adequate to fund operations
for the next twelve months. Should we decide to pursue

34

acquisition opportunities, the determination of our ability to finance these
acquisitions will be a critical element of the analysis of the opportunities.

RELATED PARTY TRANSACTIONS

We do not own a minority interest in or guarantee obligations for any
related party, other than our majority-owned subsidiaries. There are no debt
obligations of related parties, for which we have responsibility, excluded from
our balance sheet.

We pay Capricorn Management, G.P., an affiliate company of Capricorn
Holdings, Inc., for administrative services, which included office space and
parking in Connecticut for our Chief Executive Officer, reception, telephone,
computer services and other normal office support relating to that space. Mr.
Herbert S. Winokur, Jr., one of our directors, is the Chairman and Chief
Executive Officer of Capricorn Holdings, Inc. and the Managing Director of
Capricorn Holdings LLC, the general partner of Capricorn Investors II, L.P., a
private investment partnership, and directly or indirectly controls
approximately 31% of our outstanding common stock. In addition, our Chief
Executive Officer, Mr. Gregory, is a non-salaried member of Capricorn Holdings
LLC. Capricorn Investors II, L.P. controls approximately 19% of our common
stock. Fees paid to Capricorn Management totaled $115,000, $115,000 and $85,000,
for the years ended December 31, 2003, 2002 and 2001, respectively. Commencing
October 1, 2001, the fee increased to $28,750 quarterly due primarily to an
upward adjustment in Capricorn Management's underlying lease for office space;
this increase was reviewed and approved by the Audit Committee of our Board of
Directors. The arrangement is terminable by either party on 90 days notice.

Under the terms of an employment agreement in effect prior to 1999, we
loaned our Chief Executive Officer $1.2 million in July 1999 to purchase 136,832
shares of common stock. During February 2000, after we completed the initial
public offering of our Class A common stock, also pursuant to the terms of that
employment agreement, we paid this executive officer a bonus equal to the
principal and interest accrued under this note arrangement and recorded
compensation expense of $1.3 million. The officer used the proceeds of this
settlement, net of tax, to repay us approximately $665,000. In addition, on
October 27, 2000, our board of directors agreed to provide a full recourse loan
to this executive officer to facilitate the exercise of certain outstanding
stock options. The amount of the loan was equal to the cost to exercise the
options plus any personal tax burdens that resulted from the exercise. The
maturity of these loans was July 31, 2003, and interest accrued at rates ranging
from 6% to 7.8% per annum. As of June 30, 2002, these outstanding notes
receivable totaled $3.4 million, including principal and accrued interest.
Effective July 1, 2002, the notes were reviewed by our board and amended to
extend the maturity dates to July 31, 2004, and to require interest to be
calculated at an annual rate based on LIBOR plus 300 basis points, adjusted
quarterly, applied to the notes balances as of June 30, 2002, including
previously accrued interest. As of December 31, 2003, the balance of the notes
(principal and accrued interest) due from this officer under these loan
arrangements was $3.6 million. These loans to this executive officer, which were
made on a full recourse basis in prior periods to facilitate direct ownership of
our common stock, are currently subject to and in compliance with provisions of
the Sarbanes-Oxley Act of 2002.

As previously agreed in 2001, we loaned an employee who is an executive
officer and director $216,000 on April 15, 2002, under a full-recourse note
arrangement which accrues interest at 6% per annum and was to mature on July 31,
2003. The funds were used to pay the exercise cost and personal tax burdens
associated with stock options exercised during 2001. Effective July 1, 2002, the
note was amended to extend the maturity date to July 31, 2004, and to require
interest to be calculated at an annual rate based on LIBOR plus 300 basis
points, adjusted quarterly, applied to the note balance as of June 30, 2002,
including previously accrued interest. As of December 31, 2003, the balance of
the note (principal and interest) due from this officer under this loan
arrangement was approximately $233,000. This loan to this executive officer,
which was made on a full recourse basis in prior periods to facilitate direct
ownership of our common stock, is currently subject to and in compliance with
provisions of the Sarbanes-Oxley Act of 2002.

35

INFLATION AND CHANGES IN PRICES

The costs of materials (e.g., steel) for our products rise and fall with
their value in the commodity markets. Generally, increases in raw materials and
labor costs are passed on to our customers. In late 2003, the cost of steel
increased significantly. This cost increase, if sustained, may have an impact on
our future operations and increase the cost to produce our goods and services.

RECENT ACCOUNTING PRONOUNCEMENTS

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." This standard provides guidance on reporting and
accounting for obligations associated with the retirement of long-lived tangible
assets and the related retirement costs. This standard was effective for
financial statements issued for fiscal years beginning after June 15, 2002. On
January 1, 2003, we adopted this pronouncement and recorded a loss of $34,000,
net of tax effect, as the cumulative effect of change in accounting principle.
In addition, we recorded an asset retirement obligation liability and asset cost
of $96,000, associated with an obligation to remove certain leasehold
improvements upon termination of lease arrangements, including concrete pads and
equipment. We will depreciate the asset cost over the remaining useful life of
the related assets.

In October 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." This statement replaces SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of," and standardizes the accounting model to be used for
asset dispositions and related implementation issues. This pronouncement became
effective for financial statements issued for fiscal years beginning after
December 15, 2001. We adopted this pronouncement on January 1, 2002, resulting
in an immaterial impact on our financial condition and results of operations.

In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections."
This statement provides guidance for income statement classification of gains
and losses on extinguishment of debt and accounting for certain lease
modification that have economic effects that are similar to sale-leaseback
transactions. SFAS No. 145 became effective and was adopted on January 1, 2003,
with no material effect on our financial condition or results of operations.

In June 2002, the FASB issued SFAS No. 146, "Accounting for Exit or
Disposal Activities," which addresses significant issues regarding the
recognition, measurement and reporting of costs that are associated with exit
and disposal activities, including restructuring activities that were previously
accounted for pursuant to the guidance set forth in EITF Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity." SFAS No. 146 became effective on January 1, 2003. The
adoption of SFAS No. 146 had no material impact on our financial condition or
results of operations.

In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness to Others, an interpretation of FASB Statements No.
5, 57 and 107 and a rescission of FASB Interpretation No. 34." This
interpretation elaborates on the disclosures to be made by a guarantor in its
interim and annual financial statements about its obligations under guarantees
issued. The interpretation also clarifies that a guarantor is required to
recognize, at the inception of a guarantee, a liability for the fair value of
the obligation taken. The initial recognition and measurement provisions of the
interpretation are applicable to guarantees issued or modified after December
31, 2002. Application of this interpretation did not have a material impact on
our financial condition or results of operations.

In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation--Transition and Disclosure, an amendment to FASB Statement No.
123." This statement amends FASB Statement No. 123, "Accounting for Stock-Based
Compensation," to provide alternative methods to transition, on a
volunteer-basis, to the fair value method of accounting for stock-based employee
compensation. Additionally, this statement amends the disclosure requirements of
SFAS No. 123 to require prominent disclosures in both annual and interim
financial statements. Certain disclosure modifications were required for

36

fiscal years ending after December 15, 2002, if a transition to SFAS No. 123 is
elected. We have not yet elected to transition to SFAS No. 123.

In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." This statement provides
additional guidance to account for derivative instruments, including certain
derivative instruments embedded in other contracts as well as hedging activities
under SFAS No. 133. This pronouncement becomes effective for new contract
arrangements and hedging transactions entered into after June 30, 2003, with
exceptions for certain SFAS No. 133 implementation issues begun prior to June
15, 2003. We adopted this pronouncement on July 1, 2003, with no material impact
on our financial condition or results of operations.

In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity." This
statement provides guidance on how to classify and measure certain financial
instruments that have characteristics of both liabilities and equity, and
generally requires treatment of these instruments as liabilities, including
certain obligations that the issuer can or must settle by issuing its own equity
securities. This pronouncement, which was effective for all financial
instruments entered into or modified after May 31, 2003, and otherwise became
effective on July 1, 2003, required cumulative effect of a change in accounting
principle treatment upon adoption. We adopted this pronouncement on July 1,
2003, with no material impact on our financial condition or results of
operations.

In December 2003, the FASB issued an amendment of SFAS No. 132, "Employers'
Disclosures about Pensions and Other Postretirement Benefits." This amendment,
which was effective at December 31, 2003, requires additional annual disclosures
about pension or postretirement plan assets and liabilities, as well as
investment policies and strategies for plan assets, basis for expected rate of
return on assets and total accumulated benefit obligation. In addition, this
amendment requires interim disclosures of the components of net periodic benefit
cost in tabular format and contributions paid or expected to be paid during the
current fiscal year. Effective December 31, 2004, we will be required to
disclose benefits expected to be paid in each of the next five years under each
pension or postretirement plan, and an aggregate amount expected to be paid for
the succeeding five year period under these arrangements. We adopted this
amendment to SFAS No. 132 on December 31, 2003, and the required disclosures are
included in this Annual Report on Form 10-K. See Note 15, Pension and Other
Postretirement Benefits in the accompanying Notes to Consolidated Financial
Statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our operations are conducted around the world in a number of different
countries. Accordingly, our earnings are exposed to changes in foreign currency
exchange rates. The majority of our foreign currency transactions relate to
operations in Canada and the U.K. In Canada, most contracts are denominated in
Canadian dollars, and most of the costs incurred are in Canadian dollars, which
mitigates risks associated with currency fluctuations. In the U.K., many of our
sales contracts and material purchases are denominated in a currency other than
British pounds sterling, primarily U.S. dollars and euros, whereas our
engineering and overhead costs are principally denominated in British pounds
sterling. We attempt to minimize our exposure to foreign currency exchange rate
risk by requiring settlement in our functional currencies, when possible.
However, we do not enter into forward contracts or other currency-related
derivative hedge arrangements, and we do not currently intend to enter into such
contracts or arrangements as part of our currency risk management strategy.

The warrants issued to the holders of our Series B Preferred Shares provide
for a net-cash settlement in the event of a change in control, as defined in the
warrants. Consequently, we use derivative accounting to record the warrant
transaction. The liability representing the fair value of this derivative
arrangement was recorded at $99,000 as of March 31, 2003, and was adjusted to
$154,000 as of December 31, 2003, to reflect the projected change in fair value
of the warrants during the period, resulting in a $55,000 revaluation loss for
the period from inception to December 31, 2003. Fair value, as agreed with the
counter-party to the agreement, was based on a pricing model that included
subjective assumptions concerning the volatility of our common stock, the
expected term that the warrants would be outstanding, an expected dividend rate
of zero

37

and an overall liquidity factor. At each reporting date, the liability will be
adjusted to current fair value with any changes in fair value reported in
earnings during the period of change. As such, we may be exposed to certain
income fluctuations based upon changes in the fair market value of this
liability due to changes in the price of our common stock, as well as other
factors.

Our financial instruments are subject to changes in interest rates,
including our revolving credit and term loan facilities, our working capital
facility for export sales and our long-term facility secured by our Magnolia
manufacturing plant. At December 31, 2003, we had borrowings of $30.8 million
outstanding under the term loan portion of the 2001 revolving credit and term
loan facilities, at an interest rate of 3.91%. Borrowings, which bear interest
at floating rates, outstanding under the 2001 revolving credit agreement at
December 31, 2003, totaled $10.9 million. As of December 31, 2003, the weighted
average interest rate of our borrowings under the 2001 revolving credit
facilities was 4.88%. Borrowings of $700,000 were outstanding under the working
capital facility for export sales at December 31, 2003, and accrue interest at
4.00%. Borrowings under the long-term arrangement secured by our Magnolia
manufacturing facility totaled $1.3 million and accrued interest at 4.40%.

Based on past market movements and possible near-term market movements, we
do not believe that potential near-term losses in future earnings, fair values
or cash flows from changes in interest rates are likely to be material. Assuming
our current level of borrowings, as of December 31, 2003, a 100 basis point
increase in interest rates under our variable interest rate facilities would
decrease net income and cash flow from operations by $275,000 and $436,000,
respectively. In the event of an adverse change in interest rates, we could take
action to mitigate our exposure. However, due to the uncertainty of actions that
could be taken and the possible effects, this calculation assumes no such
actions. Furthermore, this calculation does not consider the effects of a
possible change in the level of overall economic activity that could exist in
such an environment.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

To follow are our consolidated financial statements for the years ended
December 31, 2003, 2002 and 2001, as applicable, along with the Independent
Auditors' report.

38

INDEPENDENT AUDITORS' REPORT
The Board of Directors
NATCO Group Inc.:

We have audited the accompanying consolidated balance sheets of NATCO Group
Inc. and subsidiaries as of December 31, 2003 and 2002, and the related
consolidated statements of operations, stockholders' equity and comprehensive
income, and cash flows for each of the years in the three-year period ended
December 31, 2003. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of NATCO Group
Inc. and subsidiaries as of December 31, 2003 and 2002 and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 2003, in conformity with accounting principles generally
accepted in the United States of America.

As discussed in Note 13 to the consolidated financial statements, effective
January 1, 2003, the Company changed its method of accounting for asset
retirement obligations. As discussed in Note 2 to the consolidated financial
statements, effective January 1, 2002, the Company changed its method of
accounting for goodwill and other intangible assets.

KPMG LLP

Houston, Texas
February 23, 2004 except as to
Note 10, which is as of March 15, 2004

39

NATCO GROUP INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)

See accompanying notes to consolidated financial statements.

40

NATCO GROUP INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)

See accompanying notes to consolidated financial statements.

41

NATCO GROUP INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND
COMPREHENSIVE INCOME
(IN THOUSANDS, EXCEPT SHARE DATA)

See accompanying notes to consolidated financial statements.

42

NATCO GROUP INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

See accompanying notes to consolidated financial statements.

43

NATCO GROUP INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) ORGANIZATION

NATCO Group Inc. (formerly known as Cummings Point Industries, Inc.) was
formed in June 1988 by Capricorn Investors, L.P., which led a group of investors
who provided capital for the Company to acquire several businesses from
Combustion Engineering, Inc. ("C-E"). In June 1989, the Company acquired from
C-E all of the outstanding common stock of National Tank Company and certain
other businesses that were subsequently divested or distributed to shareholders.

On June 30, 1997, NATCO acquired Total Engineering Services Team, Inc.
("TEST"), and on November 18, 1998, NATCO acquired The Cynara Company
("Cynara"). The Company acquired Porta-Test International, Inc. ("Porta-Test")
on January 24, 2000.

On January 27, 2000, the Company completed an initial public offering of
7,500,000 shares of its Class A common stock at a price of $10.00 per share
(4,053,807 shares newly issued by the Company and 3,446,193 existing shares sold
by selling stockholders). On February 3, 2000, the underwriter exercised its
over-allotment option that resulted in the issuance by the Company of 1,125,000
additional shares of Class A common stock.

On February 8, 2000 and April 4, 2000, NATCO acquired Modular Production
Equipment, Inc. ("MPE") and Engineering Specialties, Inc. ("ESI"), respectively.

On March 19, 2001, NATCO acquired Axsia Group Limited ("Axsia"), a
privately held process and design company based in the United Kingdom.

The accompanying consolidated financial statements and all related
disclosures include the results of operations of the Company and its
wholly-owned subsidiaries for the years ended December 31, 2003, 2002 and 2001.
Furthermore, certain reclassifications have been made to fiscal 2002 and fiscal
2001 amounts in order to present these results on a comparable basis with
amounts for fiscal 2003.

References to "NATCO" and "the Company" are used throughout this document
and relate collectively to NATCO Group Inc. and its consolidated subsidiaries.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation. The consolidated financial statements include
the accounts of the Company and all of its wholly-owned subsidiaries.
Significant inter-company accounts and transactions have been eliminated in
consolidation.

Concentration of Credit Risk. Concentrations of credit risk with respect
to trade receivables are limited due to the large number of customers comprising
the Company's customer base and their geographic dispersion. For the year ended
December 31, 2003, no customer provided 10% or more of the Company's
consolidated revenues. For the year ended December 31, 2002, one customer,
ExxonMobil Corporation and affiliates, through its general contractor, Hyundai
Heavy Industries, Co., provided 10% of the Company's consolidated revenues. No
customer provided 10% or more of consolidated revenues for the year ended
December 31, 2001. See Note 19, Industry Segments and Geographic Information.

Cash Equivalents. The Company considers all highly liquid investment
instruments with original maturities of three months or less to be cash
equivalents.

Trade Accounts Receivable. Trade accounts receivable is recorded at the
invoiced amount. An allowance for doubtful accounts is provided to estimate
probable losses resulting from bad debt. The Company reviews the allowance for
doubtful accounts each month, and individually investigates past due balances
over 90 days in order to assess collectibility of the receivable. Trade accounts
receivable balances are charged to the allowance for doubtful accounts if
collectibility is determined to be remote.

44

Inventories. Inventories are stated at the lower of cost or market. Cost
is determined using the last in, first out ("LIFO") method for NATCO domestic
inventories, average cost for TEST inventories and the first in, first out
("FIFO") method for all other inventories.

Property, Plant and Equipment. Property, plant and equipment are stated at
cost less an allowance for depreciation. Depreciation on plant and equipment is
calculated using the straight-line method over the assets' estimated useful
lives. Maintenance and repair costs are expensed as incurred; renewals and
betterments are capitalized. Upon the sale or retirement of properties, the
accounts are relieved of the cost and the related accumulated depreciation, and
any resulting profit or loss is included in income. The carrying values of
property, plant and equipment by location are reviewed annually and more often
if there are indications that these assets may be impaired.

Goodwill. Prior to the adoption on January 1, 2002, of Statement of
Financial Accounting Standards ("SFAS") No. 142, "Goodwill and Other Intangible
Assets", goodwill was being amortized on a straight-line basis over periods of
20 to 40 years. In accordance with SFAS No. 142, the Company ceased amortization
of goodwill and began to evaluate goodwill on an impairment basis. As required
by SFAS No. 142, the Company identifies separate reportable units for purposes
of evaluating goodwill impairment. In determining carrying value, the Company
segregates assets and liabilities that, to the extent possible, are clearly
identifiable by specific reportable unit. Certain corporate and other assets and
liabilities, that are not clearly identifiable by specific reportable unit, are
allocated in accordance with the standard. Fair value is determined by
discounting projected future cash flows at the Company's cost of capital rate,
as calculated. The fair value is then compared to the carrying value of the
reportable unit to determine whether or not impairment has occurred at the
reportable unit level. In the event an impairment is indicated, an additional
test is performed whereby an implied fair value of goodwill is determined
through an allocation of the fair value to the reporting unit's assets and
liabilities, whether recognized or unrecognized, in a manner similar to a
purchase price allocation, in accordance with SFAS No. 141, "Business
Combinations." Any residual fair value after this purchase price allocation
would be assumed to relate to goodwill. If the carrying value of the goodwill
exceeded the residual fair value, the Company would record an impairment charge
for that amount. Net goodwill was $80.1 million at December 31, 2003, and was
tested for impairment as required by SFAS No. 142. Based on this testing, the
Company's management believes that no impairment of goodwill exists at December
31, 2003. See Note 21, Goodwill Impairment Testing. Amortization expense for the
year ended December 31, 2001 was $3.7 million.

Other Assets, Net. Other assets include deferred financing fees, patents,
long-term deposits and prepaid pension assets. Deferred financing costs and
covenants not to compete are being amortized over the term of the related
agreements. Amortization and interest expense was $847,000, $840,000 and
$932,000, for the years ended December 31, 2003, 2002 and 2001, respectively.

Environmental Remediation Costs. The Company accrues environmental
remediation costs based on estimates of known environmental remediation
exposure. Such accruals are recorded when the cost of remediation is probable
and estimable, even if significant uncertainties exist over the ultimate cost of
the remediation. Ongoing environmental compliance costs, including maintenance
and monitoring costs, are expensed as incurred.

Revenue Recognition. Revenues from significant contracts (NATCO contracts
greater than $250,000 and longer than four months in duration and certain TEST
contracts and orders) are recognized on the percentage of completion method.
Earned revenue is based on the percentage that incurred costs to date bear to
total estimated costs after giving effect to the most recent estimates of total
cost. The cumulative impact of revisions in total cost estimates during the
progress of work is reflected in the year in which the changes become known.
Earned revenue reflects the original contract price adjusted for agreed claims
and change order revenues, if any. Losses expected to be incurred on jobs in
progress, after consideration of estimated minimum recoveries from claims and
change orders, are charged to income as soon as such losses are known. Customers
typically retain an interest in uncompleted projects. Other revenues and related
costs are recognized when products are shipped or services are rendered.

Stock-Based Compensation. SFAS No. 123, "Accounting for Stock-Based
Compensation," permits entities to recognize as expense over the vesting period
the fair value of all stock-based awards on the date of
45

grant. Alternatively, SFAS No. 123 allows entities to continue to apply the
provisions of Accounting Principles Board ("APB") Opinion No. 25 and provide pro
forma net income and earnings per share disclosures for employee stock option
grants made in 1995 and future years as if the fair-value-based method defined
in SFAS No. 123 had been applied. In December 2002, SFAS No. 148, "Accounting
for Stock-Based Compensation--Transition and Disclosure, an amendment to FASB
Statement No. 123," was issued and provides alternative methods to transition to
the fair value method of accounting for stock-based compensation, on a volunteer
basis, and requires additional disclosures at both annual and interim periods.
The Company has elected to continue to apply the provision of APB Opinion No. 25
and provide the pro forma disclosure requirements of SFAS No. 123.

The Company's pro forma net income and earnings per share data for the
years ended December 31, 2003, 2002 and 2001 as per SFAS No. 123, were as
follows:

Research and Development. Research and development costs are charged to
operations in the year incurred. The cost of equipment used in research and
development activities, which has alternative uses, is capitalized as equipment
and not treated as an expense of the period. Such equipment is depreciated over
estimated lives of 5 to 10 years. Research and development expenses totaled $1.9
million, $2.0 million and $2.1 million for the years ended December 31, 2003,
2002 and 2001, respectively.

Warranty Costs. Estimated future warranty obligations related to products
are charged to cost of goods sold in the period in which the related revenue is
recognized. Additionally, the Company provides some of its customers with
letters of credit covering potential warranty claims. At December 31, 2003 and
2002, the Company had $6.9 million and $6.0 million, respectively, in
outstanding letters of credit related to warranties.

Income Taxes. Deferred tax assets and liabilities are recognized for
future tax consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their
respective tax bases. Deferred tax assets and liabilities are measured using
enacted tax rates expected to apply to taxable income in the years in which
those temporary differences are expected to be recovered or settled. The effect
on deferred tax assets and liabilities of a change in tax rates is recognized in
income in the period that includes the enactment date.

In assessing the realizability of deferred tax assets, management considers
whether it is more likely than not that some portion or all of the deferred tax
assets will not be realized. The ultimate realization of deferred tax assets is
dependent upon the future generation of taxable income during the periods in
which those temporary differences become deductible. Management has considered
the scheduled reversal of deferred tax liabilities, projected future taxable
income and tax planning strategies in making this assessment.

Derivative Arrangements. Assets and liabilities associated with and
underlying derivative arrangements which do not qualify for hedge value
accounting are recorded at fair market value as of the balance sheet date

46

with any changes in fair value charged to income in the current period, in
accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities." The Company recorded a charge of $249,000 to exit certain
derivative arrangements that were acquired with the purchase of Axsia in March
2001. At December 31, 2003, the Company had issued 248,800 warrants to purchase
shares of NATCO common stock associated with the issuance of its Series B
Preferred Stock. These warrants were recorded at fair market value of $154,000
as of December 31, 2003. Any changes in fair market value of derivative
arrangements will be recorded to net income in the period of the change.

Translation of Foreign Currencies. Financial statement amounts related to
foreign operations that have functional currencies other than the U.S. dollar
are translated into their U.S. dollar equivalents at exchange rates as follows:
(1) balance sheet accounts at year-end exchange rates, and (2) statement of
operations accounts at the weighted average exchange rate for the period. The
gains or losses resulting from such translations are deferred and included in
accumulated other comprehensive loss as a separate component of stockholders'
equity. Gains or losses from foreign currency transactions are reflected in the
consolidated statements of operations.

Use of Estimates. The Company's management has made estimates and
assumptions relating to the reported amounts of assets and liabilities and the
disclosure of contingent assets and liabilities and the amounts of revenues and
expenses recognized during the period to prepare these financial statements in
conformity with generally accepted accounting principles. Actual results could
differ from those estimates.

Earnings per Common Share. Basic earnings per share excludes the dilutive
effect of common stock equivalents. The diluted earnings per common and
potential common share are computed by dividing net income (loss) available to
common stockholders by the weighted average number of common and potential
common shares outstanding. Net income (loss) available to common stockholders at
December 31, 2003, represented net income before cumulative effect of change in
accounting principle less preferred stock dividends accrued and paid. The
weighted average number of common and potential common shares outstanding was
derived from applying the if-converted method to determine any incremental
shares associated with convertible preferred stock, warrants and restricted
stock outstanding. The Company recorded a loss available to common stockholders
for the year ended December 31, 2003, and therefore, all common stock
equivalents related to employee stock options, convertible preferred stock,
warrants and restricted stock were deemed anti-dilutive and excluded from the
calculation of weighted average shares. For the years ended December 31, 2002
and 2001, potentially dilutive employee stock options were included in the
earnings per share calculations, as applicable. Anti-dilutive stock options were
excluded from the calculation of potential common shares for all years
presented. The impact of these anti-dilutive shares would have been a reduction
of 495,000 shares, 314,000 shares and 145,000 shares for the years ended
December 31, 2003, 2002 and 2001, respectively.

47

The following table presents earnings per common share amounts computed
using SFAS No. 128:

(3) CAPITAL STOCK, REDEEMABLE CONVERTIBLE PREFERRED STOCK AND EQUITY

On November 18, 1998, the Company's charter was amended to divide its
common stock into two classes: Class A Common Stock (45,000,000 shares) and
Class B Common Stock (5,000,000 shares). The two classes of common stock have
the same relative rights and preferences except the holders of the Class B
common stock have the right, voting separately as a class, to elect one member
of the Company's Board of Directors. Class B shares may be converted by the
holder to Class A shares at any time. In February 2001, the Company issued 8,520
Class B shares to the former shareholders of Cynara, in connection with the
achievement of certain performance criteria defined in the November 1998
purchase agreement. Goodwill was increased $85,000 in 2001, as a result of this
transaction. Total shares issued to former Cynara stockholders under this
earn-out arrangement were 752,501 shares. On January 1, 2002, all outstanding
shares of the Company's Class B Common Stock, 334,719 shares, were converted
automatically to Class A Common

48

Stock, on a share for share basis, in accordance with the terms under which the
Class B Common Stock was originally issued, resulting in a single class that was
re-designated "Common Stock."

In October 2000, the Company's board of directors approved a stock
repurchase plan under which up to 750,000 shares of the Company's Class A common
stock could be acquired. During fiscal 2001, the Company reacquired
approximately 118,000 shares of its Class A common stock under this repurchase
agreement for $867,000, an average cost of $7.32 per share. The cost to
reacquire these shares was recorded as treasury stock at December 31, 2003 and
2002, respectively.

On March 25, 2003, the Company issued 15,000 shares of Series B Convertible
Preferred Stock ("Series B Preferred Shares") and warrants to purchase 248,800
shares of NATCO's common stock, to Lime Rock Partners II, L.P., a private
investment fund, for an aggregate sale price of $15.0 million. Approximately
$99,000 of the aggregate sale price was allocated to the warrants. Proceeds from
the issuance of these securities, net of related estimated issuance costs of
approximately $800,000, were used to reduce the Company's outstanding revolving
debt balances and for other general corporate purposes.

Each of the Series B Preferred Shares has a face value of $1,000 and pays a
cumulative dividend of 10% per annum of face value, which is payable
semi-annually on June 15 and December 15 of each year, except the initial
dividend payment which was payable on July 1, 2003. Each of the Series B
Preferred Shares is convertible, at the option of the holder, into (i) a number
of shares of common stock equal to the face value of such Series B Preferred
Share divided by the conversion price, which was $7.805 (or an aggregate of
1,921,845 shares) at December 31, 2003, and (ii) a cash payment equal to the
amount of dividends on such shares that have accrued since the prior semi-annual
dividend payment date. During 2003, the Company paid dividends of $1.2 million
to the holders of the Series B Preferred Shares.

In the event of a change in control, as defined in the certificate of
designations for the preferred shares, each holder of the Series B Preferred
Shares has the right to convert the Series B Preferred Shares into common stock
or to cause the Company to redeem for cash some or all of the Series B Preferred
Shares at an aggregate redemption price equal to the sum of (i) $1,000 (adjusted
for stock splits, stock dividends, etc.) multiplied by the number of shares to
be redeemed, plus (ii) an amount (not less than zero) equal to the product of
the aggregate amount of dividends paid in cash since the issuance date, plus any
gain on the related stock warrants. If the holder of the Series B Preferred
Shares converts upon a change in control occurring on or before March 25, 2006,
the holder would also be entitled to receive cash in an amount equal to the
dividends that would have accrued through March 25, 2006 less the sum of the
aggregate amount of dividends paid in cash through the date of conversion, and
the aggregate amount of dividends accrued in prior periods but not yet paid.

The Company has the right to redeem the Series B Preferred Shares for cash
on or after March 25, 2008, at a redemption price per share equal to the face
value of the Series B Preferred Shares plus the amount of dividends that have
been accrued but not paid since the most recent semi-annual dividend payment
date.

The Company adopted SFAS No. 150, "Accounting for Certain Instruments with
Characteristics of both Liabilities and Equity," on July 1, 2003. Under SFAS No.
150, the Series B Preferred Shares would be classified as permanent equity.
However, due to the cash redemption features upon a change in control as
described above, the Series B Preferred Shares do not qualify for permanent
equity treatment in accordance with the Emerging Issues Task Force Topic D-98:
"Classification and Measurement of Redeemable Securities," which specifically
requires that permanent equity treatment be precluded for any security with
redemption features that are not solely within the control of the issuer.
Therefore, the Company has accounted for the Series B Preferred Shares as
temporary equity in the accompanying balance sheet, and has not assigned any
value to its right to redeem the Series B Preferred Shares on or after March 25,
2008.

If the Series B Preferred Shares are converted under contingent redemption
features, any redemption amount greater than carrying value would be recorded as
a reduction of income available common shareholders when the event becomes
probable.

If the Company fails to pay dividends for two consecutive periods or any
redemption price due with respect to the Series B Preferred Shares for a period
of 60 days following the payment date, the Company will
49

be in default under the terms of such shares. During a default period, (1) the
dividend rate on the Series B Preferred Shares would increase to 10.25%, (2) the
holders of the Series B Preferred Shares would have the right to elect or
appoint a second director to the Board of Directors and (3) the Company would be
restricted from paying dividends on, or redeeming or acquiring its common or
other outstanding stock, with limited exceptions. If the Company fails to set
aside or make payments in cash of any redemption price due with respect to the
Series B Preferred Shares, and the holders elect, the Company's right to redeem
the shares may be terminated.

The warrants issued to Lime Rock Partners II, L.P., have an exercise price
of $10.00 per share of common stock and expire on March 25, 2006. The Company
can force the exercise of the warrants if NATO's common stock trades above
$13.50 per shares for 30 consecutive days. The warrants contain a provision
whereby the holder could require the Company to make a net-cash settlement for
the warrants in the case of a change in control. The warrants were deemed to be
derivative instruments and, therefore, the warrants were recorded at fair value
as of the issuance date. Fair value, as agreed with the counter-party to the
agreement, was calculated by applying a pricing model that included subjective
assumptions for stock volatility, expected term that the warrants would be
outstanding, a dividend rate of zero and an overall liquidity factor. The
Company recorded the resulting liability of $99,000 as of the issuance date.
This liability was increased to $154,000 as of December 31, 2003, as a result of
the change in fair value of the warrants. Similarly, changes in fair value in
future periods will be recorded in net income during the period of the change.

On December 31, 2003, the Company recorded an adjustment to beginning
retained earnings of $400,000, which represented the elimination of a reserve to
indemnify a former affiliate for any tax ramifications that may result from a
tax-free spin-off of the former subsidiary in 1997. The reserve associated with
the indemnification was recorded in 1999. As of December 31, 2003, the statute
of limitations had expired for review by the appropriate taxing authorities, and
the reserve was deemed unnecessary. Since the original transaction did not
result in a gain or loss, the reversal of this reserve has been recorded as an
adjustment to retained earnings, rather than a component of net income for the
year ended December 31, 2003.

(4) ACQUISITIONS

On March 19, 2001, the Company acquired all the outstanding share capital
of Axsia, for approximately $42.8 million, net of cash acquired. Axsia
specializes in the design and supply of water re-injection systems for oil and
gas fields, oily water treatment, oil separation, hydro-cyclone technology,
hydrogen production and other process equipment systems. This acquisition was
financed with borrowings under NATCO's term loan facility and was accounted for
using the purchase method of accounting. Results of operations for Axsia have
been included in NATCO's consolidated financial statements since the date of
acquisition. The purchase price of $45.0 million was allocated as follows: $2.2
million of cash acquired, $38.4 million of current assets excluding cash, $2.0
million of long-term assets excluding goodwill and $46.0 million of current
liabilities. The excess of the purchase price over the fair value of the net
assets acquired was being amortized over a twenty-year period, prior to the
adoption of SFAS No. 142, "Goodwill and Other Intangible Assets," on January 1,
2002. Goodwill and accumulated amortization expense related to the Axsia
acquisition were $47.4 million and $1.9 million, respectively, at December 31,
2003.

50

Assuming the Axsia acquisition occurred on January 1 of the respective
year, the unaudited pro forma results of the Company for the twelve months ended
December 31, 2001 would have been as follows:

These pro forma results assume debt service costs associated with the Axsia
acquisition, net of tax effect, calculated at the Company's effective tax rate
for the applicable period, and nondeductible goodwill amortization. Although
prepared on a basis consistent with NATCO's consolidated financial statements,
these pro forma results do not purport to be indicative of the actual results
which would have been achieved had the acquisition been consummated on January 1
of the respective year, and are not intended to be a projection of future
results.

Effective January 8, 2001, the Company entered into a Compromise Settlement
Agreement with the former owner of TEST, which resulted in a cash payment of
$1.5 million to NATCO on May 31, 2001, to settle certain contingencies related
to NATCO's acquisition of TEST in 1997. The proceeds of this payment, net of
related costs, were used to reduce goodwill associated with the TEST
acquisition.

(5) CLOSURE AND OTHER

In September 2003, the Company's management approved a restructuring plan
that included the involuntary termination of certain administrative and
operating personnel in connection with the closure of a manufacturing facility
in Covington, Louisiana, the Company's corporate headquarters, the Company's
research and development facility in Tulsa, Oklahoma, and the consolidation of
operations in the U.K. As a result of this restructuring plan, the Company
recorded expense of $1.2 million, of which approximately $756,000 related to
post-employment costs for terminated employees, as provided by the Company's
severance policy, and accounted for in accordance with SFAS No. 112, "Employers'
Accounting for Post-employment Benefits, an amendment of FASB Statements No. 5
and 43," and $427,000 related to consultant's fees, equipment moving costs and
employee relocations. The Company had an accrual of $95,000 related to this
restructuring plan as of December 31, 2003, and does not expect to incur
additional costs related to this restructuring in 2004.

In December 2003, the Company's management approved additional
restructuring costs including a plan to close an Engineered Systems location in
Singapore and recorded closure and other expense of $692,000, of which $515,000
related to severance, $35,000 related to the termination of a lease arrangement
and $142,000 related to the relocation of an employee. The Company had an
accrual of $560,000 related to this restructuring plan as of December 31, 2003,
and does not expect to incur additional costs related to this office closure in
2004.

51

As of December 31, 2002, the Company had recorded a liability totaling
$304,000, related to certain restructuring costs incurred in connection with the
closure of a manufacturing facility in Edmonton, Alberta, Canada. As of December
31, 2003, this liability totaled $88,000. The following table summarizes changes
to the restructuring liability by cost type:

The portion of the accrual related to lease termination and other during
the twelve months ended December 31, 2003, was reduced by approximately
$239,000, of which $113,000 related to amounts paid, and $126,000 related to a
change in the Company's assessment of liability under the lease arrangement for
this facility.

During 2003, the Company recorded closure and other expense associated with
this Canadian restructuring plan of $230,000, related to equipment moving costs
and employee relocations, including severance costs of $129,000 that had not
been not identified as restructuring costs as of the plan measurement date.

In June 2001, the Company recorded a charge of $1.6 million that consisted
of $920,000 pursuant to an approved plan to close and merge an existing NATCO
office into the operations of Axsia, as well as other streamlining actions
associated with the acquisition. This charge included costs for severance,
office consolidation and other expenses. The Company also withdrew a public debt
offering in 2001 and recorded a charge of $680,000 for costs incurred related to
the proposed offering.

(6) INVENTORIES

Inventories consisted of the following amounts:

At December 31, 2003 and 2002, inventories valued using the LIFO method and
included above amounted to $28.6 million and $26.3 million, respectively.
Reductions in LIFO layers resulted in a $59,000 decrease in net income for the
year ended December 31, 2002. There were no reductions in LIFO layers for the
years ended December 31, 2003 and 2001.

52

(7) COST AND ESTIMATED EARNINGS ON UNCOMPLETED CONTRACTS

Cost and estimated earnings on uncompleted contracts were as follows:

(8) PROPERTY, PLANT AND EQUIPMENT, NET

The components of property, plant and equipment, were as follows:

Pursuant to a September 2003 restructuring plan, the Company closed a
manufacturing facility in Covington, Louisiana during the fourth quarter of 2003
and transferred all equipment and inventory to other branch or manufacturing
locations. As of December 31, 2003, this manufacturing facility had a net book
value of $714,000, and was classified as held for sale. The Company's management
expects to sell the facility within one year. The facility was included in the
North American Operations business segment at December 31, 2003 and 2002.

Depreciation expense was $5.0 million, $4.9 million and $4.1 million,
respectively, for the years ended December 31, 2003, 2002 and 2001. The Company
leases certain machinery and equipment to its customers under short-term
operating lease arrangements, generally for periods of one month to one year.
The Company recorded depreciation expense related to these leased assets of
$433,000, $380,000 and $354,000, for the years ended December 31, 2003, 2002 and
2001, respectively. These operating lease arrangements are for short-term
periods of one month to one year, and often result in the sale of the equipment
within one year. While these assets are under lease, the Company records
depreciation expense based upon the assets' estimated useful life. Net book
value of leased assets was recorded at $1.4 million and $1.7 million at December
31, 2003 and 2002, respectively, and has been included in the accompanying
balance sheet under the caption "Other Current Assets," since the Company
intends to sell the assets within one year, or place the assets in used
inventory upon return from the lessee. Lease and rental income of $1.5 million,
$1.3 million and $1.2 million, was

53

included in revenues for the North American Operations business segment for the
years ended December 31, 2003, 2002 and 2001, respectively.

(9) ACCRUED EXPENSES AND OTHER

Accrued expense and other consisted of the following:

(10) LONG-TERM DEBT

The consolidated borrowings of the Company were as follows:

The aggregate future maturities of long-term debt for the next five years
ended December 31 are as follows: 2004--$5.6 million; 2005--$6.5 million;
2006--$6.5 million; and 2007--$25.0 million, with all debt maturing prior to
2008.

On March 16, 2001, the Company entered into a credit facility that
consisted of a $50.0 million term loan, a $35.0 million U.S. revolving facility,
a $10.0 million Canadian revolving facility and a $5.0 million U.K. revolving
facility. The term loan matures on March 31, 2006, and each of the revolving
facilities matures on March 31, 2004. The revolving credit and term loan
facilities contain restrictive covenants which, among other things, limit the
amount of Funded Debt to EBITDA, imposes a minimum fixed charge coverage ratio,
a minimum asset coverage ratio and a minimum net worth requirement. In October
2001, the Company amended this revolving credit agreement to reduce the
borrowing capacity in the U.S. from $35.0 million to

54

$30.0 million, and to increase its borrowing capacity in the U.K. from $5.0
million to $10.0 million. No other material modifications were made to the
agreement at that time.

Borrowings of $50.0 million under the term loan facility were used
primarily for the acquisition of Axsia. The remaining borrowings, along with
additional borrowings under the revolving credit facility, were used to repay
$16.5 million outstanding under a predecessor revolving credit and term loan
facility.

In July 2002, the Company's lenders approved the amendment of various
provisions of the term loan and revolving credit facility agreement, effective
April 1, 2002. This amendment revised certain restrictive debt covenants,
modified certain defined terms, allowed for future capital investment in the
Company's Sacroc CO(2) processing facility in West Texas, facilitates the
issuance of up to $7.5 million of subordinated indebtedness, increased the
aggregate amount of operating lease expense allowed during a fiscal year and
permitted an increase in borrowings under the export sales credit facility,
without further consent, up to a maximum of $20.0 million. These modifications
resulted in higher commitment fee percentages and interest rates than in the
original loan agreement, based on the Funded Debt to EBITDA ratio, as defined in
the underlying agreement, as amended.

In July 2003, the Company's lenders approved an amendment of the existing
term loan and revolving credit facility, effective April 1, 2003. The amendment
modified several restrictive covenant terms, including the Fixed Charge Coverage
Ratio and Funded Debt to EBITDA Ratio, each as defined in the agreement. Under
the Company's term loan and revolving credit facility agreement, certain debt
covenants became more restrictive during the fourth quarter of 2003, and the
Company was required to obtain a waiver of the covenants related to net worth,
funded debt to EBITDA ratio and fixed charge coverage ratio through March 31,
2004, subject to the Company meeting a minimum EBITDA threshold (which was
subsequently achieved), in order to remain in compliance with the governing
agreement, as amended.

In December 2003, the Company obtained a waiver to certain debt covenants
including those related to net worth, funded debt to EBITDA and fixed charge
coverage ratio through March 31, 2004, subject to meeting a minimum EBITDA
threshold. The Company met this threshold requirement as of December 31, 2003,
and was in compliance with all covenant requirements, as amended, as of that
date.

Amounts borrowed under the term loan bear interest at a rate of 3.91% per
annum as of December 31, 2003. Amounts borrowed under the revolving portion of
the facility bear interest as follows:

- until April 1, 2002, at a rate equal to, at the Company's election,
either (1) the London Interbank Offered Rate ("LIBOR") plus 2.25% or (2)
a base rate plus 0.75%; and

- on and after April 1, 2002, at a rate based upon the ratio of funded debt
to EBITDA, as defined in the credit facility ("EBITDA"), and ranging
from, at the Company's election, (1) a high of LIBOR plus 3.00% to a low
of LIBOR plus 1.75% or, (2) a high of a base rate plus 1.50% to a low of
a base rate plus 0.25%.

NATCO paid commitment fees of 0.50% per year until April 1, 2002, and is
required to pay commitment fees of 0.30% to 0.625% per year following 2002,
depending upon the ratio of Funded Debt to EBITDA, on the undrawn portion of the
facility. As of December 31, 2003, the Company's commitment fees were calculated
at a rate of 0.625%.

On March 15, 2004, the Company replaced its 2001 term loan and revolving
credit facilities with a term loan and revolving credit arrangement, called the
2004 term loan and revolving facilities, that provides for a term loan of $45.0
million, a U.S. revolving facility with a borrowing capacity of $20.0 million, a
Canadian revolving facility with a borrowing capacity of $5.0 million, and a
U.K. revolving credit facility with a borrowing capacity of $10.0 million. All
of the borrowing capacities under the 2004 revolving credit facilities are
subject to borrowing base limitations.

The 2004 term loan and revolving facilities provide for interest at a rate
based upon the ratio of funded debt to EBITDA, as defined in the credit facility
("EBITDA"), and ranging from, at the Company's election, (1) a high of LIBOR
plus 2.75% to a low of LIBOR plus 2.00% or, (2) a high of a base rate plus 1.75%
to a

55

low of a base rate plus 1.00%. NATCO will pay commitment fees related to this
facility, based upon the ratio of Funded Debt to EBITDA, on the undrawn portion
of the facility.

The 2004 term loan and revolving facilities require quarterly payments of
$1.6 million, beginning in June 2004, and mature on March 15, 2007. The Company
intends to borrow funds under the 2004 term loan and revolving credit facilities
to retire debt outstanding under the 2001 term loan and revolving credit
facilities as of March 15, 2004 and as a result has classified the current
installments and five year repayments on its bank debt at December 31, 2003
based on the repayment terms of the 2004 term loan and revolving facilities.

The 2004 term loan and revolving credit facilities are guaranteed by the
Company and its operating subsidiaries and are secured by a first lien or first
priority security interest in or pledge of substantially all of the assets of
the borrowers, including accounts receivable, inventory, equipment, intangibles,
equity interests in U.S. subsidiaries and 66 1/3% of the equity interest in
active, non-U.S. subsidiaries. Assets of the Company and its active U.S.
subsidiaries secure the U.S., Canadian and U.K. facilities, assets of the
Company's Canadian subsidiary also secure the Canadian facility and assets of
the Company's U.K. subsidiaries also secure the U.K. facility. The U.S. facility
is guaranteed by each U.S. subsidiary of the Company, while the Canadian and
U.K. facilities are guaranteed by NATCO Group Inc., each of its U.S.
subsidiaries and the Canadian subsidiary or the U.K. subsidiaries, as
applicable.

The 2004 term loan and revolving credit facilities contain restrictive
covenants similar to those contained in the 2001 facilities, including, among
others, those that limit the amount of funded debt to EBITDA (as defined in the
2004 facilities), impose a minimum fixed charge coverage ratio, a minimum asset
coverage ratio and a minimum net worth requirement.

The Company maintains a working capital facility for export sales that
provides for aggregate borrowings of $10.0 million, subject to borrowing base
limitations, under which borrowings of $700,000 were outstanding at December 31,
2003. Letters of credit outstanding under the export sales credit facility as of
December 31, 2003 totaled $69,000. Fees related to these letters of credit at
December 31, 2003, were approximately 1% of the outstanding balance. The export
sales credit facility is secured by specific project inventory and receivables,
and is partially guaranteed by the EXIM Bank. Loans under this facility mature
in July 2004, and require renewal annually.

NATCO had letters of credit outstanding under the revolving credit
facilities totaling $19.8 million at December 31, 2003. Fees related to these
letters of credit at December 31, 2003, ranged from approximately 1% to 3.25% of
the outstanding balance. These letters of credit support contract performance
and warranties and expire at various dates through April 2007.

The Company had unsecured letters of credit and bonds totaling $584,000 and
guarantees totaling $7.9 million at December 31, 2003.

On February 6, 2002, the Company borrowed $1.5 million under a long-term
promissory note to finance the purchase of a manufacturing facility in Magnolia,
Texas. This note accrues interest at the 90-day LIBOR plus 3.25% per annum, and
requires quarterly payments of principal of approximately $24,000 and interest
for five years beginning May 2002, with a final balloon payment due February
2007. This promissory note is collateralized by a manufacturing facility in
Magnolia, Texas acquired in the fourth quarter of 2001.

With respect to the 2004 term loan and revolving credit facilities, NATCO
has agreed that it will not make any distributions of any property or cash to
the Company or its stockholders except dividends required under the Series B
Preferred Stock provisions. No dividends were declared or paid to common
stockholders during the years ended December 31, 2003, 2002 and 2001. Dividends
totaling $1.2 million were declared and paid to holders of the Company's Series
B Preferred Stock during the year ended December 31, 2003.

56

(11) INCOME TAXES

Income tax expense (benefit) before the cumulative effect of change in
accounting principle consisted of the following components:

Temporary differences related to the following items that give rise to
deferred tax assets and liabilities were as follows:

At December 31, 2003 and 2002, the Company recorded a valuation allowance
of $759,000 and $258,000, respectively, which included a valuation allowance of
$258,000 related to certain deferred tax assets acquired with the purchase of
Axsia in March 2001, and an additional valuation allowance in 2003 of $349,000
related

57

to certain deferred tax assets in Canada and $152,000 related to other foreign
affiliates. The Company had net operating loss carry-forwards for federal income
tax purposes of $3.6 million for federal income tax purposes as of December 31,
2003, which were available to offset future federal income tax through 2023. Net
foreign tax credit and research and development tax credit carryforwards begin
to expire December 2005 and December 2019, respectively.

Based upon historical taxable income and projected future taxable income
over the periods in which the Company's deferred tax assets are deductible,
management believes it is more likely than not that the Company will realize the
benefits of these deductible differences, net of the existing valuation
allowances at December 31, 2003. However, the amount of the deferred tax asset
considered realizable could change if future taxable income differs from the
Company's projections.

Income tax expense differs from the amount computed by applying the U.S.
federal income tax rate of 34% to income from continuing operations before
income taxes, as per the following reconciliation:

Cumulative undistributed earnings of foreign subsidiaries totaled $6.0
million as of December 31, 2003. The Company considers earnings from these
foreign subsidiaries to be indefinitely reinvested and accordingly, no provision
for U.S. foreign or state income taxes has been made for these earnings. Upon
distribution of foreign subsidiary earnings in the form of dividends or
otherwise, such distributed earnings would be reportable for U.S. income tax
purposes (subject to adjustment for foreign tax credits).

Federal income tax returns for fiscal years beginning with 2000 are open
for review by the appropriate taxing authorities.

(12) STOCKHOLDERS' EQUITY

On July 1, 1997, the Board of Directors of the Company approved the
exchange of certain stock appreciation rights outstanding under a subsidiary's
plan for individual options to purchase common stock of the Company.
Compensation expense was recognized to the extent that the projected fair market
value of the stock on the exchange date exceeded the exercise price of the
options. Furthermore, additional stock options were granted under this plan with
an exercise price equal to the fair market value of the shares on the date of
grant. Accordingly, no compensation expense was recorded for these additional
grants. The individual stock options granted on July 1, 1997 vested ratably over
a period of three or four years. The maximum term of these options was 10 years.
At December 31, 2003, 2002 and 2001, options relating to an aggregate of 477,700
shares, 527,701 shares, and 527,701 shares, respectively, remained outstanding
under this plan.

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In January 1998 and February 1998, the Company adopted the Directors
Compensation Plan and the 1998 Employee Stock Incentive Plan. These plans
authorize the issuance of options to purchase up to an aggregate of 760,000
shares of the Company's common stock. The options vest over periods of up to
four years. The maximum term under these options is ten years. At December 31,
2003, 2002 and 2001, options relating to an aggregate of 628,217 shares, 731,587
shares and 743,920 shares, respectively, were outstanding under these plans.

In November 2000, the Board of Directors of the Company approved and
authorized the issuance of up to 300,000 shares of the Company's common stock
under the 2000 Employee Stock Option Plan. On May 24, 2001, the Company's
stockholders approved the NATCO Group Inc. 2001 Stock Incentive Plan, which
superceded and replaced the 2000 Plan in its entirety, and increased the number
of shares as to which options or awards may be granted under the plan to a
maximum of 1,000,000 shares. At December 31, 2003, 2002 and 2001, options
relating to an aggregate of 879,422 shares, 807,326 shares and 795,826 shares,
respectively, were outstanding under this plan.

Pursuant to the NATCO Group Inc. Directors Compensation Plan, as amended,
and the NATCO Group Inc. 2001 Stock Incentive Plan, the Company granted 2,500
restricted shares to each of its five non-employee directors during June 2003.
These restricted shares vest 100% on June 3, 2006, but are forfeitable if
service discontinues prior to this date (other than for death, disability or
retirement). The Company will recognize expense of $85,000 related to these
grants ratably over the vesting period. In addition, the Company granted each of
these non-employee directors options to purchase 2,500 shares of the Company's
common stock at the fair market value on the date of grant. These options vest
100% following one year of service, on the anniversary date of their issuance.

Transactions pursuant to the Company's stock option plans for the years
ended December 31, 2003, 2002 and 2001, include:

Pro forma information regarding net income and earnings per share is
required by SFAS No. 123, and has been determined by applying the Black-Scholes
Single Option--Reduced Term valuation method. This valuation model requires
management to make highly subjective assumptions about volatility of NATCO's
common stock, the expected term of outstanding stock options, the Company's
risk-free interest rate and expected dividend payments during the contractual
life of the options. Volatility of stock prices was evaluated based upon
historical data from the New York Stock Exchange from the date of the initial
public offering, January 28, 2000, to December 31, 2003. Volatility was
calculated at 49% as of December 31, 2003, but was stepped-down by 10% per year
for the next year to reflect expected stabilization. The following table
summarizes other assumptions used to determine pro forma compensation expense
under SFAS No. 123 as of December 31, 2003:

Risk-free rates were determined based upon U.S. Treasury obligations as of
the option date and outstanding for a similar term. The Company does not intend
to pay dividends on its common stock during the term of the options outstanding
as of December 31, 2003.

For purposes of pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options' vesting period. For the
Company's pro forma net earnings and earnings per share for the years ended
December 31, 2003, 2002 and 2001, see Note 2, Summary of Significant Accounting
Policies.

At December 31, 2003, pursuant to equity compensation plans approved by the
Company's security holders, 1,985,339 shares of common stock could be issued
upon exercise of employee stock options, at an average price of $8.21 per share,
and 12,500 shares of restricted stock, at an average price of $6.80. An
additional 238,195 shares remain available for issuance under the Company's
stock option plans at December 31, 2003.

If Series B Convertible Preferred Shares were converted to common stock at
December 31, 2003, an additional 1,921,845 shares of common stock would be
issued, along with 248,800 shares related to stock warrants. The issuance of the
Series B Convertible Preferred Shares and related stock warrants was not
approved by security holders.

PREFERRED STOCK PURCHASE RIGHTS

In May 1998, the Board of Directors of the Company declared a dividend of
one preferred share purchase right for each outstanding share of common stock
and for each share of common stock thereafter issued prior to the time the
rights become exercisable. When the rights become exercisable, each right will
entitle the holder to purchase one one-hundredth of one share of Series A Junior
Participating Preferred Stock at a price of $72.50 in cash. Until the rights
become exercisable, they will be evidenced by the certificates or ownership of
NATCO's common stock, and they will not be transferable apart from the common
stock.

The rights will become exercisable following the tenth day after a person
or group announces acquisition of 15% or more of the Company's common stock (20%
or more in the case of Lime Rock Partners II, L.P.) or announces commencement of
a tender offer, the consummation of which would result in ownership by the
person or group of 15% or more of the Company's common stock. If a person or
group were to acquire 15% or

60

more of the Company's common stock (20% or more in the case of Lime Rock
Partners II, L.P.), each right would become a right to buy that number of shares
of common stock that would have a market value of two times the exercise price
of the right. Rights beneficially owned by the acquiring person or group would,
however, become void.

At any time prior to the time the rights become exercisable, the board of
directors may redeem the rights at a price of $0.01 per right. At any time after
the acquisition by a person or group of 15% (20% or more in the case of Lime
Rock Partners II, L.P.) or more but less than 50% of the common stock, the board
may redeem all or part of the rights by issuing common stock in exchange for
them at the rate of one share of common stock for each two shares of common
stock for which each right is then exercisable. The rights will expire on May
15, 2008 unless previously extended or redeemed.

(13) CHANGE IN ACCOUNTING PRINCIPLE

Effective January 1, 2003, the Company recorded the cumulative effect of
change in accounting principle related to the adoption of SFAS No. 143,
"Accounting for Asset Retirement Obligations." This standard required the
Company to record the fair value of an asset retirement obligation as a
liability in the period in which a legal obligation associated with the
retirement of tangible long-lived assets that result from acquisition,
construction, development and/or normal use of the assets, was incurred. In
addition, the standard requires the Company to record a corresponding asset that
will be depreciated over the life of the asset that gave rise to the liability.
Subsequent to the initial measurement of the asset retirement obligation, the
Company will be required to adjust the related liability at each reporting date
to reflect changes in estimated retirement cost and the passage of time. A loss
of $34,000, net of tax, was recorded as of January 1, 2003, as a result of this
change in accounting principle. The related asset retirement obligation and
asset cost of $96,000, associated with an obligation to remove certain leasehold
improvements upon termination of lease arrangements, including concrete pads and
equipment. The asset cost will be depreciated over the remaining useful life of
the related assets. There was no significant change in the asset or liability
during the year ended December 31, 2003.

(14) PENSION AND OTHER POSTRETIREMENT BENEFITS

The Company has adopted SFAS 132, "Employer's Accounting for Pensions and
Other Postretirement Benefits," which revised disclosures about pension and
other postretirement benefit plans. Disclosures regarding pension benefits
represent the plan for certain union employees of a foreign subsidiary.
Disclosures regarding postretirement benefits represent health care and life
insurance benefits for employees who were retired when the Company was acquired
from C-E.

On May 1, 2001, the Company amended a postretirement benefit plan that
provided medical and dental coverage to retirees of a predecessor company. Under
the amended plan, retirees bear additional costs of coverage. Significant plan
changes include higher deductibles, prescription coverage under a drug card
program and the elimination of dental benefits. As of July 1, 2001, the Company
obtained a third-party valuation of its liability under this plan arrangement,
as amended. Based upon this valuation, the effect of this amendment was a $6.4
million reduction in the Company's postretirement benefit liability. As of
December 31, 2001, a cumulative unrecognized loss of $3.6 million existed
related to this postretirement benefit plan. In accordance with SFAS No. 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions," the
benefit associated with the plan amendment will be amortized to income as a
prior service cost adjustment over the remaining life expectancy of the plan
participants. Additionally, the cumulative unrecognized loss will be amortized
to expense over the remaining life expectancy of the plan participants.

In November 2001, the Company agreed to maintain benefits at pre-amendment
levels for a specified class of retirees in exchange for expense reimbursement
from the former sponsor of the postretirement benefit plan. The agreement
requires reimbursement of $79,000 per year for each of the four succeeding
years. Pursuant to this arrangement, the Company received $157,000 and $79,000
as reimbursement of postretirement benefit expenses for the years ended December
31, 2003 and 2002, respectively, and recorded a receivable for the remaining
benefit at December 31, 2003.

61

In August 2001, the participants of the Canadian pension plan voted to
terminate contributions to the plan and receive actuarially determined cash
distributions. As of December 31, 2002, the Company had formally terminated the
pension plan and benefit payments were distributed, except amounts due to
certain retirees, who had not yet replied to notification of pending
distributions. In February 2003, the Company paid $245,000 to purchase an
annuity contract from The Canada Life Assurance Company, who assumed liability
for future pension payments under the NATCO Canada Boilermaker Union Employees'
Pension Plan, effective April 1, 2003. The components of net periodic benefit
cost under this pension plan were calculated for the period January 1, 2003
through March 31, 2003, and no benefit obligation or fair value of net assets
existed under this arrangement as of December 31, 2003.

On December 8, 2003, the President of the United States signed into law the
Medicare Prescription Drug Improvement and Modernization Act of 2003. The Act's
impact has not been reflected in any amounts disclosed in the Company's
financial statements or accompany notes. The Company is currently reviewing the
effects the Act will have on our plans and expect to complete that review during
2004. In addition, the Company is waiting for guidance from the United States
Department of Health and Human Services on how the employer subsidy provision
will be administered and from the Financial Accounting Standards Board on how
the impact of the Act should be recognized in the Company's financial
statements.

62

The following table sets forth the plan's benefit obligation, fair value of
plan assets, and funded status at December 31, 2003 and 2002.

63

In December 2003, the Company adopted an amendment to SFAS No. 132, that
required various disclosures concerning the Company's postretirement benefit
plans and pensions at December 31, 2003 and 2002, including the plan's
measurement date, employer's estimated contributions for the next fiscal year,
the percentage of fair value of plan assets at the measurement date, data
concerning specific assets which contribute to the long-term rate of return
used, investment policies and strategies by plan asset category and the basis
upon which a long-term rate of return on plan assets was determined.

The Company measured plan assets and liabilities as of December 31, 2003
and 2002. No employer contributions are expected under the Company's pension
plan for the year ended December 31, 2004, since the plan was terminated and all
assets distributed as of December 31, 2003. The Company expects to provide
contributions of approximately $1.8 million related to a postretirement benefit
plan for the year ended December 31, 2004. The Company held no assets related to
these pension and postretirement plans as of December 31, 2003, and, therefore,
the Company neither calculated a long-term rate of return applicable to plan
assets, nor devised investment strategies to manage plan assets.

Defined Contribution Plans. The Company and its subsidiaries each have
defined contribution pension plans covering substantially all nonunion hourly
and salaried employees who have completed three months of service. Employee
contributions of up to 3% of each covered employee's compensation are matched
100% by the Company, with an additional 2% of covered employee's compensation
matched at 50%. In addition, the Company may make discretionary contributions as
profit sharing contributions. Company contributions to the plan totaled $1.5
million, $1.4 million and $1.8 million for the years ended December 31, 2003,
2002 and 2001, respectively.

(15) OPERATING LEASES

The Company and its subsidiaries lease various facilities and equipment
under non-cancelable operating lease agreements. These leases expire on various
dates through March 2018, excluding a lease arrangement for a facility at Axsia
that requires lease commitments until the facility is sublet to another party.
Future minimum lease payments required under operating leases that have
remaining non-cancelable lease terms in excess of one year at December 31, 2003,
were as follows: 2004--$3.7 million, 2005--$1.6 million, 2006--$1.4 million,
2007--$1.1 and 2008--$828,000. Total expense for operating leases for the years
ended December 31, 2003, 2002 and 2001 was $5.4 million, $5.8 million and $5.3
million, respectively.

For a discussion of lease and rental income, see Note 8, Property, Plant
and Equipment, net.

(16) RELATED PARTIES

The Company pays Capricorn Management G.P., an affiliate company of
Capricorn Holdings, Inc., for administrative services, which included office
space and parking in Connecticut for the Company's Chief Executive Officer,
reception, telephone, computer services and other normal office support relating
to that space. Mr. Herbert S. Winokur, Jr., one of the Company's directors, is
the Chairman and Chief Executive Officer of Capricorn Holdings, Inc. and the
Managing Director of Capricorn Holdings LLC, the general partner of Capricorn
Investors II, L.P., a private investment partnership, and directly or indirectly
controls approximately 31% of the Company's outstanding common stock. In
addition, the Company's Chief Executive Officer, Mr. Gregory, is a non-salaried
member of Capricorn Holdings LLC. Capricorn Investors II, L.P. controls
approximately 19% of the Company's common stock. Fees paid to Capricorn
Management totaled $115,000, $115,000 and $85,000 for the years ended December
31, 2003, 2002 and 2001, respectively. Commencing October 1, 2001, the fee
increased to $28,750 per quarter due primarily to upward adjustments in
Capricorn Management's underlying lease for office space; this increase was
reviewed and approved by the Audit Committee of the Company's Board of
Directors. The arrangement is terminable by either party on 90 days notice.

Under the terms of an employment agreement in effect prior to 1999, the
Company loaned its Chief Executive Officer $1.2 million in July 1999 to purchase
136,832 shares of common stock. During February 2000, after the Company
completed the initial public offering of its Class A common stock, also pursuant
to the terms of that employment agreement, the Company paid this executive
officer a bonus equal to the
64

principal and interest accrued under this note arrangement and recorded
compensation expense of $1.3 million. The officer used the proceeds of this
settlement, net of tax, to repay the Company approximately $665,000. In
addition, on October 27, 2000, the Company's board of directors agreed to
provide a full recourse loan to this executive officer to facilitate the
exercise of certain outstanding stock options. The amount of the loan was equal
to the cost to exercise the options plus any personal tax burdens that resulted
from the exercise. The maturity of these loans was July 31, 2003, and interest
accrued at rates ranging from 6% to 7.8% per annum. As of June 30, 2002, these
outstanding notes receivable totaled $3.4 million, including principal and
accrued interest. Effective July 1, 2002, the notes were reviewed by the
Company's board and amended to extend the maturity dates to July 31, 2004, and
to require interest to be calculated at an annual rate based on LIBOR plus 300
basis points, adjusted quarterly, applied to the notes balances as of June 30,
2002, including previously accrued interest. As of December 31, 2003, the
balance of the notes (principal and accrued interest) due from this officer
under these loan arrangements was $3.6 million. These loans to this executive
officer, which were made on a full recourse basis in prior periods to facilitate
direct ownership in the Company's common stock, are currently subject to and in
compliance with provisions of the Sarbanes-Oxley Act of 2002.

As previously agreed in 2001, the Company loaned an employee who is an
executive officer and director $216,000 on April 15, 2002, under a full-recourse
note arrangement which accrues interest at 6% per annum and matures on July 31,
2003. The funds were used to pay the exercise cost and personal tax burdens
associated with stock options exercised during 2001. Effective July 1, 2002, the
note was amended to extend the maturity date to July 31, 2004, and to require
interest to be calculated at an annual rate based on LIBOR plus 300 basis
points, adjusted quarterly, applied to the note balance as of June 30, 2002,
including previously accrued interest. As of December 31, 2003, the balance of
the note (principal and interest) due from this officer under this loan
arrangement was approximately $233,000. This loan to this executive officer,
which was made on a full recourse basis from time to time in prior periods to
facilitate direct ownership in the Company's common stock, is currently subject
to and in compliance with provisions of the Sarbanes-Oxley Act of 2002.

(17) COMMITMENTS AND CONTINGENCIES

The Porta-Test purchase agreement, executed in January 2000, contains a
provision to calculate a payment to certain former stockholders of Porta-Test
Systems, Inc. for a three-year period ended January 23, 2003, based upon sales
of a limited number of specified products designed by or utilizing technology
that existed at the time of the acquisition. Liability under this arrangement
was contingent upon attaining certain performance criteria, including gross
margins and sales volumes for the specified products. If applicable, payment is
required annually. In April 2001, the Company paid $226,000 under this
arrangement related to the twelve-month period ended January 23, 2001. In August
2002, the Company paid $197,000 under this arrangement related to the
twelve-month period ended January 23, 2002, resulting in an increase in
goodwill. Because the performance criteria was not met, the Company did not
record additional liability under this arrangement for the twelve-month period
ended January 23, 2003.

(18) LITIGATION

Magnum Transcontinental Corp. Arbitration and Related Matter. These
matters stem from an agreement among NATCO Group, Magnum Transcontinental
Corporation, the U.S. procurement arm of Petroserv S.A., and Zephyr Offshore,
Inc., a Petroserv subsidiary, to manufacture and install a processing plant on a
Petroserv rig, and Petroserv's agency agreement with NATCO for certain projects
in Brazil. NATCO claims Magnum owes it $418,990 under the plant manufacturing
agreement for additional work performed in excess of the days agreed in the
contract. NATCO submitted the matter to binding American Arbitration Association
arbitration on October 29, 2003. An arbitrator has been selected, and
arbitration is scheduled in Houston, Texas during August 2004. In the
arbitration, Magnum has counter-claimed for $4,685,000, alleging breach of
contract. NATCO has not recorded an accrual related to this matter at December
31, 2003. NATCO disputes the amounts claimed by Magnum, and intends to
vigorously pursue its claims while defending against the counterclaim. After
NATCO filed its request for arbitration, Petroserv submitted a mediation request
under its representation agreement with NATCO, claiming unpaid agency fees

65

on several contracts, including the Magnum contract. No resolution resulted from
the mediation, which was held on January 23, 2004. NATCO believes any fees owed
to Petroserv under the agency agreement are offset by NATCO's claims against
Magnum. NATCO disputes that it owes any fees for the Magnum work or any work
obtained in Brazil after the representation agreement terminated in early 2003.
It is not presently known what, if any, further action Petroserv will take in
this regard.

The Company and its subsidiaries are defendants or otherwise involved in a
number of other legal proceedings in the ordinary course of business. While the
Company insures against the risk of these proceedings to the extent deemed
prudent by management, NATCO can offer no assurance that the type or value of
this insurance will meet the liabilities that may arise from any pending or
future legal proceedings related to business activities. While the Company
cannot predict the outcome of any legal proceedings with certainty, in the
opinion of management, ultimate liability with respect to these pending lawsuits
is not expected to have a significant or material adverse effect on the
Company's consolidated financial position, results of operations or cash flows.

(19) INDUSTRY SEGMENTS AND GEOGRAPHIC INFORMATION

The Company has adopted the provisions of SFAS No. 131, "Disclosures About
Segments of an Enterprise and Related Information." The Company's business units
have separate management teams and infrastructures that offer different products
and services. The business units have been aggregated into three reportable
segments (described below) since the long-term financial performance of these
reportable segments is affected by similar economic conditions.

North American Operations: This segment consists of the U.S. Sales and
Service business unit, the Company's Canadian and Venezuelan subsidiaries, Latin
American operations and CO(2) gas-processing operations. The U.S. Sales and
Service business unit designs, engineers, manufactures, and provides start-up
services for production equipment, which is generally less complex than those
units provided by Engineered Systems, and provides replacement parts, field and
shop servicing of equipment, and used equipment refurbishing. NATCO Canada
provides design, engineering, manufacturing and start-up services for production
equipment, as well as replacement parts, field and shop servicing of equipment
and used equipment refurbishing. NATCO Canada also provides manufacturing
services for the Engineered Systems segment. Latin American operations generally
provide replacement parts to service customers in Latin America. The CO2
gas-processing operations include on-going service at two gas-processing plants
in the United States. The principal market for the U.S. Sales and Service
business unit is the U.S. onshore and offshore market and the international
market. Customers include major multi-national, independent and national or
state-owned companies. The principal markets for NATCO Canada are the oil and
gas producing regions of Canada. Customers include major multi-national and
independent companies.

Engineered Systems: This segment consists of three business units: U.S.
Engineered Systems, NATCO Japan and Axsia, that provide design, engineering,
manufacturing and start-up services for engineered process systems. The
principal markets for this segment include all major oil and gas producing
regions of the world including North America, South America, Europe, the Middle
East, Africa and the Far East. Customers include major multi-national,
independent and national or state-owned companies.

Automation and Control Systems: TEST is the sole business unit reported in
this segment. This unit designs, manufactures, installs and services
instrumentation and electrical control systems. The principal markets for this
segment include all major oil and gas producing regions of the world including
North America, South America, Europe, Kazakhstan, Africa and the Far East.
Customers include major multi-national, independent and national or state-owned
companies. This segment was formerly named instrumentation and electrical
systems.

The accounting policies of the reportable segments are the same as those
described in Note 2. The Company evaluates the performance of its operating
segments based on income before net interest expense, income taxes, depreciation
and amortization expense, closure and other, other, net and accounting changes.

66

In September 2003, the Company changed the presentation of its reportable
segments by reclassifying certain research and development costs and bonus
expenses among the business segments from the "Corporate and Other" segment. In
addition, Other, net was excluded from the determination of segment profit
(loss). These changes were made as a result of a change in management's internal
reporting to better state total costs and profits of each segment and have been
retroactively reflected in all periods presented.

Consistent with the recent restructuring in late 2003 and to more closely
align the Company's segment presentation to the internal reporting presentation
used by the Company's management, the Company changed the presentation of its
reportable segments in December 2003, by reclassifying certain manufacturing
plants and related assets, totaling $5.6 million, from the Engineered Systems
segment to the North American Operations segment. As a result of this
reclassification, capital expenditures and depreciation and amortization expense
increased for the North American Operations segment by $77,000 and $751,000,
respectively, with corresponding decreases in the Engineered Systems segment.
Similar reclassifications were made for 2002 of $12.5 million, $303,000 and
$945,000, related to total assets, capital expenditures and depreciation and
amortization expense, respectively, and in 2001 of $12.8 million, $2.1 million
and $569,000, respectively. Presentation of these assets and the associated
impact on capital expenditures and depreciation and amortization expense was
retroactively reflected in all periods presented below.

Summarized financial information concerning the Company's reportable
segments is shown in the following table.

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The following table reconciles total segment profit to net income before
cumulative effect of change in accounting principle:

The impact of the change in measurement method used to determine segment
profit (loss) for each of the years ended December 31, 2003, 2002 and 2001, was
as follows:

The Company's geographic data for continuing operations for the years ended
December 31, 2003, 2002 and 2001 were as follows:

Equipment for large international projects is generally manufactured in the
United States. Therefore, revenues and results of operations related to these
projects were presented as derived from the United States for purposes of this
geographic presentation.

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(20) QUARTERLY DATA

The following tables summarize unaudited quarterly information for the
years ended December 31, 2003, 2002 and 2001:

(21) GOODWILL IMPAIRMENT TESTING

The FASB approved SFAS No. 142, "Goodwill and Other Intangible Assets" in
June 2001. This pronouncement requires that intangible assets with indefinite
lives, including goodwill, cease being amortized and be evaluated for impairment
on an annual basis. Intangible assets with a defined term, such as patents,
would continue to be amortized over the useful life of the asset.

70

The Company adopted SFAS No. 142 on January 1, 2002. Intangible assets
subject to amortization under the pronouncement as of December 31, 2003 and 2002
were summarized in the following table:

Amortization and interest expense of $847,000, $840,000 and $932,000 were
recognized related to these assets for the years ended December 31, 2003, 2002
and 2001, respectively. The estimated aggregate amortization and interest
expense for these assets for each of the following five fiscal years is:
2004--$462,000; 2005--$414,000; 2006--$129,000; 2007--$45,000; and
2008--$28,000. For segment reporting purposes, these intangible assets and the
related amortization expense were recorded under "Corporate and Eliminations."

Goodwill was the Company's only intangible asset that required no periodic
amortization as of the date of the adoption of SFAS No. 142. Net goodwill at
December 31, 2003 and 2002 was $80.1 million and $79.0 million, respectively.
The pro forma impact of applying SFAS No. 142 to operating results for the year
ended December 31, 2001 would have been a reduction of amortization expense of
$3.7 million resulting in net income of $9.0 million. The pro forma increase in
basic and diluted earnings per share in 2001 would have been $.23 and $.23,
respectively.

In accordance with SFAS No. 142, the Company tested impairment of goodwill
by comparing the fair value of its operating units to the carrying value of
those assets, including any related goodwill. As required in the pronouncement,
the Company identified separate reporting units for purposes of this evaluation.
In determining carrying value, the Company segregated assets and liabilities
that, to the extent possible, were clearly identifiable by specific reporting
unit. Certain corporate and other assets and liabilities, that were not clearly
identifiable by specific reporting unit, were allocated in accordance with the
standard. Fair value was determined by discounting projected future cash flows
at the Company's weighted average cost of capital rate. The resulting fair value
was then compared to the carrying value of the reporting unit to determine
whether or not an impairment had occurred at the reporting unit level. No
impairment was indicated and, in accordance with the pronouncement, no
additional tests were required.

Net goodwill was $22.4 million, $54.2 million, $4.4 million and $159,000 at
December 31, 2003 for the North American Operations segment, Engineered Systems
segment, Automation and Control Systems segment and the Corporate and Other
segment, respectively, and $20.2 million, $54.2 million, $4.4 million and
$159,000, respectively, at December 31, 2002. The change in the value of
goodwill between December 31, 2003 and 2002 was due entirely to the impact of
exchange rate changes.

Since no impairment of goodwill was indicated based upon the testing
performed, no impairment charge was recorded under SFAS No. 142 as of December
31, 2003 and 2002. Goodwill will be tested for impairment on December 31 on an
annual basis.

(22) NEW ACCOUNTING PRONOUNCEMENTS

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." This standard provides guidance on reporting and
accounting for obligations associated with the retirement of long-lived tangible
assets and the related retirement costs. This standard was effective for
financial statements issued for fiscal years beginning after June 15, 2002. On
January 1, 2003, we adopted this pronouncement and recorded a loss of $34,000,
net of tax effect, as the cumulative effect of change in accounting principle.
In addition, we recorded an asset retirement obligation liability and asset cost
of $96,000, associated with an obligation to remove certain leasehold
improvements upon termination of lease arrangements, including

71

concrete pads and equipment. We will depreciate the asset cost over the
remaining useful life of the related assets.

In October 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." This statement replaces SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of," and standardizes the accounting model to be used for
asset dispositions and related implementation issues. This pronouncement became
effective for financial statements issued for fiscal years beginning after
December 15, 2001. The Company adopted this pronouncement on January 1, 2002,
resulting in no material effect on financial condition or results of operations.

In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections."
This statement amends existing guidance on reporting gains and losses on
extinguishment of debt, prohibiting the classification of the gain or loss as
extraordinary. SFAS No. 145 also amends SFAS No. 13 to require sale-leaseback
accounting for certain lease modifications that have economic effects similar to
sale-leaseback arrangements. The provisions of the statement related to the
rescission of Statement No. 4 will be applied for the fiscal year beginning
after May 14, 2002, with early adoption encouraged. The provisions of the
statement related to Statement No. 13 were effective for transactions occurring
after May 15, 2002, with early adoption encouraged. SFAS No. 145 has been
adopted as of January 1, 2003, with no material effect on the Company's
financial condition or results of operations.

In June 2002, the FASB issued SFAS No. 146, "Accounting for Exit or
Disposal Activities," which addresses financial accounting and reporting for
costs associated with exit and disposal activities, including restructuring
activities that are currently accounted for pursuant to the guidance set forth
in EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination
Benefits and Other Costs to Exit an Activity." SFAS No. 146 is effective for
exit or disposal activities that are initiated after December 31, 2002, with
early adoption encouraged. The provisions of this pronouncement were applied to
any exit or disposal activities on January 1, 2003, with no material effect on
the Company's financial condition or results of operations.

In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness to Others, an interpretation of FASB Statements No.
5, 57 and 107 and a rescission of FASB Interpretation No. 34." This
interpretation elaborates on the disclosures to be made by a guarantor in its
interim and annual financial statements about its obligations under guarantees
issued. The interpretation also clarifies that a guarantor is required to
recognize, at the inception of a guarantee, a liability for the fair value of
the obligation taken. The initial recognition and measurement provisions of the
Interpretation are applicable to guarantees issued or modified after December
31, 2002. The Company adopted this Interpretation on January 1, 2003 with no
material effect on the Company's financial condition or results of operations.

In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation--Transition and Disclosure, an amendment to FASB Statement No.
123." This statement amends FASB Statement No. 123, "Accounting for Stock-Based
Compensation," to provide alternative methods to transition, on a
volunteer-basis, to the fair value method of accounting for stock-based employee
compensation. Additionally, this statement amends the disclosure requirements of
SFAS No. 123 to require prominent disclosures in both annual and interim
financial statements. Certain disclosure modifications are required for fiscal
years ending after December 15, 2002, if a transition to SFAS No. 123 is
elected. The Company has not elected to transition to SFAS No. 123 as of
December 31, 2002. See Note 12, Stockholders' Equity.

In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." This statement provides
additional guidance to account for derivative instruments, including certain
derivative instruments embedded in other contracts as well as hedging activities
under SFAS No. 133. This pronouncement becomes effective for new contract
arrangements and hedging transactions entered into after June 30, 2003, with
exceptions for certain SFAS No. 133 implementation issues begun prior to June
15, 2003. We adopted this pronouncement on July 1, 2003, with no material impact
on our financial condition or results of operations.
72

In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of both Liabilities and Equity." This
statement provides guidance on how to classify and measure certain financial
instruments that have characteristics of both liabilities and equity, and
generally requires treatment of these instruments as liabilities, including
certain obligations that the issuer can or must settle by issuing its own equity
securities. This pronouncement, which was effective for all financial
instruments entered into or modified after May 31, 2003, and otherwise became
effective on July 1, 2003, required cumulative effect of a change in accounting
principle treatment upon adoption. We adopted this pronouncement on July 1,
2003, with no material impact on our financial condition or results of
operations.

In December 2003, the FASB issued an amendment of SFAS No. 132, "Employers'
Disclosures about Pensions and Other Postretirement Benefits." This amendment,
which was effective at December 31, 2003, requires additional annual disclosures
about pension or postretirement plan assets and liabilities, as well as
investment policies and strategies for plan assets, basis for expected rate of
return on assets and total accumulated benefit obligation. In addition, this
amendment requires interim disclosures of the components of net periodic benefit
cost in tabular format and contributions paid or expected to be paid during the
current fiscal year. Effective December 31, 2004, we will be required to
disclose benefits expected to be paid in each of the next five years under each
pension or postretirement plan, and an aggregate amount expected to be paid for
the succeeding five year period under these arrangements. We adopted this
amendment to SFAS No. 132 on December 31, 2003, and the required disclosures
were included in this Annual Report on Form 10-K. See Note 14, Pension and Other
Postretirement Benefits.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

There are no changes or disagreements with accountants on accounting and
financial disclosure matters during the periods for which consolidated financial
statements have been presented within this document.

ITEM 9A. CONTROLS AND PROCEDURES

CONTROLS AND PROCEDURES

Members of our management team, including our Chief Executive Officer and
our Chief Financial Officer, have reviewed our disclosure controls and
procedures, as defined by the Securities and Exchange Commission in Rule
13a-15(e) of the Securities Exchange Act of 1934, as of December 31, 2003, in an
effort to evaluate the effectiveness of the design and operation of these
controls. Based upon this review, our management has determined that, as of the
end of the period covered by this Annual Report on Form 10-K, our disclosure
controls and procedures operate such that important information is collected in
a timely manner, provided to management and made known to our Chief Executive
Officer and Chief Financial Officer to allow timely decisions regarding
disclosure in our public filings.

Furthermore, no significant changes have been made to our internal controls
and procedures during the three months ended December 31, 2003, or prior to
filing this Annual Report on Form 10-K, and no corrective actions are
anticipated, as we noted no significant deficiencies or material weaknesses in
our internal control structure.

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PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

EXECUTIVE OFFICERS AND DIRECTORS

- ---------------

(1) Appointed by the holders of the Series B Convertible Preferred Stock on
March 25, 2003.

Nathaniel A. Gregory. Chairman of the Board and Chief Executive Officer
since April 1993. Prior to joining NATCO, Mr. Gregory held a number of positions
in the engineering and construction industry and in investment banking.

Patrick M. McCarthy. Director since February 1998 and President since
December 1997. Mr. McCarthy served as Executive Vice President of NATCO, with
marketing and operations responsibilities, from November 1996 to December 1997
and as Senior Vice President--Marketing from June 1994 to November 1996. Prior
to joining us in June 1994, Mr. McCarthy was Vice President--Worldwide Oil and
Gas at ABB Lummus Crest, an engineering and construction company.

Keith K. Allan. Chairman of the Audit Committee and Director since
February 1998. Mr. Allan was a director of NATCO (U.K.) Ltd. from October 1996
to January 1998. From February 1993 to August 1996,

74

he was Technical Director in the North Sea for Shell U.K. Exploration and
Production. From 1965 to February 1993, he served in a number of positions for
Royal Dutch/Shell Group.

Thomas R. Bates, Jr. Director since March 2003. Managing Director of Lime
Rock Partners, Houston, Texas, a partnership that invests in growth capital
equity for oilfield service companies, since October 2001. Mr. Bates previously
served as Senior Vice President, then President, of the Discovery Group of Baker
Hughes, Inc. (June 1998 to January 2000), as CEO and President of Weatherford
Enterra, Inc. (June 1997 to May 1998) and as President of the Anadrill Division
of Schlumberger Ltd. (March 1992 to May 1997). Mr. Bates currently serves as the
chairman and a member of the executive committee of Rotary Steerable Tools
(BVI), Inc. (a manufacturer of drilling tools), chairman and a member of the
compensation committee of vMonitor, Inc. (a provider of web-based technology for
remote monitoring of assets in the oil and gas industry) and a director of New
Patriot Drilling.

John U. Clarke. Director since February 2000, Chairman of the GNC
Committee since December 2002. Mr. Clarke has been President of Concept Capital
Group, a financial and strategic advisory firm originally founded by Mr. Clarke
in 1995 since May 2001. Immediately prior to reestablishing the firm, Mr. Clarke
was a Managing Director of SCF Partners, a private equity investment firm. From
1999 to June 2000, Mr. Clarke was Executive Vice President of Dynegy, Inc. where
he was also an Advisory Director and member of the Office of the Chairman. Mr.
Clarke joined Dynegy in April 1997 as Senior Vice President and Chief Financial
Officer. Prior to joining Dynegy, Mr. Clarke was a managing director of Simmons
& Company International. From 1995 to 1997, he served as president of Concept
Capital Group. Mr. Clarke was Executive Vice President and Chief Financial and
Administrative Officer with Cabot Oil and Gas from 1993 to 1995. He was with
Transco Energy from 1981 to 1993, last serving as Senior Vice President and
Chief Financial Officer. Mr. Clarke is a director and member of the audit
committee of Harvest Natural Resources, a publicly traded international oil and
gas company, and a director and chairman of the audit committee of The Houston
Exploration Company, a publicly traded oil and gas exploration and production
company. He also is a director of FuelQuest.com, a market service provider to
petroleum marketers.

George K. Hickox, Jr. Director since November 1998. Mr. Hickox has served
as Chairman and Chief Executive Officer of The Wiser Oil Company, a publicly
traded, independent oil and gas exploration and production company, since May
2000, and as a general partner of Heller Hickox & Co., a partnership
specializing in energy investments, since September 1991. Mr. Hickox also served
as a director of Cynara prior to its acquisition by NATCO in November 1998. He
presently serves as an officer and director of several privately held companies.

Herbert S. Winokur, Jr. Director since 1989. Mr. Winokur is Chairman and
Chief Executive Officer of Capricorn Holdings, Inc. (a private investment
company), and Managing General Partner of Capricorn Investors II, L.P. and
Capricorn Investors III, L.P., private investment partnerships concentrating on
investments in restructure situations, organized by Mr. Winokur in 1987, 1994
and 1999, respectively. He is also a Managing Member of Capricorn Holdings, LLC
and Capricorn Holdings III, LLC (which are General Partners of Capricorn
Investors II, L.P. and Capricorn Investors III, L.P., respectively.) Prior to
his current appointment, Mr. Winokur was Senior Executive Vice President and
director of Penn Central Corporation. Mr. Winokur is also a director of Mrs.
Fields' Companies, Inc., CCC Information Services Group, Inc. and Holland Series
Fund, Inc.

James F. Crittall. President of NATCO Canada since November 1996. Mr.
Crittall served as Vice President of Technical Operations for NATCO Canada from
December 1992 to October 1996. Mr. Crittall joined National Tank Company in 1971
and has served in several managerial positions, including Manager of Engineering
and Sales and Manager of Engineering for NATCO Canada, Ltd.

Robert A. Curcio. Senior Vice President--Technology and Product
Development since May 1998. Mr. Curcio spent 20 years at Exxon Corporation and
its affiliates in marketing, engineering and manufacturing management. Mr.
Curcio served as Global Markets Director--Heavy Duty Diesel Additives of Exxon
Chemical's PARAMINS division from February 1996 to May 1998, Global Markets
Manager--Specialty and Niche Additives of PARAMINS from January 1995 to February
1996 and PARAMINS Product Manager--Large Engine Additives from July 1992 to
January 1995.
75

Katherine P. Ellis. Senior Vice President, General Counsel and Secretary
since March 2003. Ms. Ellis held various counsel positions for Nabors Industries
from December 1996 to December 2002, serving most recently as General Counsel.
From 1987 to 1996 she was associated with the law firm of Baker & Botts LLP in
Houston, Texas.

Richard W. FitzGerald. Senior Vice President and Chief Financial Officer
of the company since May 2003. Mr. FitzGerald was Senior Vice President and
Chief Financial Officer of Universal Compression, Inc., a publicly traded gas
compression rental and fabrication company, from 1999 to March 2003. From 1998
to 1999, he served as Vice President--Financial Services of KN Energy. Since
1982, he served in a number of finance and accounting positions at companies in
the gas marketing and transportation industry, including various units of
Occidental Petroleum Corporation and Peoples Energy.

Ryan S. Liles. Vice President and Controller since April 2000. Mr. Liles
was Controller of Dailey International Inc., an oilfield services company, from
October 1994 to April 2000. He served as an Assistant Controller at USPCI, a
hazardous waste disposal company, from November 1989 to October 1994.

Peter G. Michaluk. Senior Vice President--Europe, Africa and Middle East
since March 2001. Since 1994, Mr. Michaluk served as Managing Director of Axsia.
He joined Axsia in 1978 as a process engineer and held various technical and
managerial positions of increasing responsibility prior to assuming his current
position.

Richard D. Peters. Senior Vice President and Director--Gas Membrane
Systems since September 2002, Senior Vice President--Americas from March 2001 to
August 2002, and Senior Vice President--Engineering from July 2000 to March
2001. From November 1997 to July 2000, he served as President of Cynara. Mr.
Peters served as Chief Financial Officer of Cynara from June 1996 to October
1997 and as Project Manager and Accounting Coordinator of Cynara from February
1991 to May 1996.

C. Frank Smith. Executive Vice President--NATCO Group Inc. since January
2002. Mr. Smith was President of NATCO's U.S. operations from January 1998 until
January 2002, and served as Senior Vice President--Sales and Service from
September 1993 to December 1997 and as the Northern Region Director of Sales and
Service Centers from April 1992 to September 1993.

David R. Volz, Jr. President of TEST since its acquisition in June 1997.
Mr. Volz joined TEST in 1976 as a Technical Specialist and held a number of
positions of increasing responsibility prior to serving as President.

Joseph H. Wilson. Senior Vice President--Marketing since April 1999. Prior
to joining us, Mr. Wilson served as Strategic Accounts Manager of Baker Hughes
Inc., with responsibilities for strategic business development, from January
1999 to April 1999. From January 1997 to January 1999, Mr. Wilson served as Gulf
Coast Region Manager of Baker Hughes INTEQ's fluids, directional drilling and
MWD business. From January 1994 to January 1997, Mr. Wilson was Director of
Sales and Systems Marketing for all of INTEQ. Prior to January 1994, Mr. Wilson
held a number of positions in sales, operations and marketing with Baker Hughes
INTEQ, Baker Sand Control and BJ Services, each an oilfield service company.

Certain Arrangements. Pursuant to our restated certificate of
incorporation, as amended, so long as more than 50% of the Series B Preferred
Shares remain outstanding, the holders of the Series B Preferred Shares have the
right, voting separately as a class with one vote per share, to elect or appoint
one director at any annual or special meeting of stockholders or pursuant to
written consent. On March 25, 2003, the holders of the Series B Preferred Shares
acting by written consent elected Mr. Thomas R. Bates, Jr. to serve as a
director of the company pursuant to this right. Mr. Bates will continue to serve
as a director at the pleasure of the holders of Series B preferred shares for so
long as such right continues. Following certain defaults related to the payment
of dividends on or the redemption price for the Series B Preferred Shares, the
holders of such stock would be entitled to elect a second director, also voting
separately as a class with one vote per share.

Section 16(a) Beneficial Ownership Reporting Compliance. The Securities
Exchange Act of 1934 requires our executive officers and directors, among
others, to file certain beneficial ownership reports with the Securities and
Exchange Commission. During 2003, Mr. Thomas R. Bates, Jr. submitted one late
filing related to his election as a director of the company, which occurred on
March 25, 2003 and was reported on

76

May 2, 2003; and Lime Rock Partners II, LP submitted one late filing related to
the issuance of the Series B Preferred Shares, which occurred on March 25, 2003
and was reported on April 25, 2003.

Identification of Audit Committee; Audit Committee Financial Expert. Keith
K. Allan (Chairman), John U. Clarke and George K. Hickox, Jr. serve on the audit
committee of our board of directors. This is a separately designated standing
audit committee established in accordance with section 3(a)(58)(A) of the
Securities Exchange Act of 1934, as amended. Our board of directors has
determined that it has at least one audit committee financial expert, as defined
pursuant to applicable law and regulation, serving on its audit committee, Mr.
Clarke.

Code of Ethics and Governance Matters. NATCO Group Inc. has adopted the
Business Ethics Policy, a code of business ethics for directors, officers and
employees, and Corporate Governance Guidelines. Our Audit Committee and
Governance, Nominating and Compensation Committee have adopted Charters
governing their activities. All of these documents are available free of charge
through our website, www.natcogroup.com, under "Investor Relations/Corporate
Governance." Stockholders may request free copies of these documents from our
corporate headquarters in Houston, Texas, located at 2950 North Loop West, 7th
Floor, Houston, Texas 77092, Attention: Corporate Secretary.

ITEM 11. EXECUTIVE COMPENSATION

Except as specified in the following sentence, the information called for
by this item will be contained in our 2004 annual meeting proxy statement or an
amendment to this document to be filed within 120 days of December 31, 2003 and
is incorporated into this document by reference. Information in our 2004 proxy
statement not deemed to be "soliciting material" or "filed" with the Securities
and Exchange Commission under its rules, including the Report of the
Compensation Committee on Executive Compensation, the Report of the Audit
Committee and the Five Year Stock Performance Graph, is not deemed to be
incorporated by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS

SECURITY OWNERSHIP OF MANAGEMENT AND PRINCIPAL STOCKHOLDERS

The following table sets forth certain information regarding the beneficial
ownership of our common stock as of March 10, 2004 by (i) each person known by
us to be the beneficial owner of more than 5% of our common stock, (ii) each
director, (iii) each of the Named Executive Officers (as defined in "Executive
Compensation" below), and (iv) all directors and executive officers as a group.
Unless otherwise indicated, each person has sole voting and dispositive power
over the shares indicated as owned by such person.

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* Indicates beneficial ownership of less than one percent of outstanding common
stock

(1) Shares are considered "beneficially owned," for purposes of this table, if
the person directly or indirectly has sole or shared voting and investment
power with respect to such shares, and/or if a person has the right to
acquire shares within 60 days of March 10, 2004. Shares that are indicated
as beneficially owned in the table above which meet this 60-day criteria
include: (1) Mr. Allan, 13,334; (2) Capricorn Investors II, L.P., 9,334; (3)
Mr. Clarke, 8,536; (4) Mr. Curcio, 80,843; (5) Mr. Gregory, 305,239; (6) Mr.
Hickox, 6,667; (7) Mr. McCarthy, 94,817; (8) Mr. Michaluk, 60,676; (9) Mr.
Smith, 74,984; and (10) all Directors and executive officers as a group,
869,489.

(2) As reported in a Schedule 13G filed with the Securities and Exchange
Commission.

(3) Of the shares indicated as being beneficially owned by Mr. Winokur,
3,096,355 of the shares are owned directly by Capricorn Investors II, LP. Mr
Winokur is the Manager of Capricorn Holdings LLC, which in turn serves as
the general partner of Capricorn Investors II. As such Mr. Winokur may be
deemed to have dispositive voting power over the shares owned by Capricorn
Investors II. Of the remaining 1,862,379 shares, Mr. Winokur has sole voting
and sole dispositive power with respect to such shares.

(4) Lime Rock Partners II, LP holds 15,000 shares of our Series B Convertible
Preferred Stock, representing 100% of the issued and outstanding shares of
such series, which would be convertible to 1,921,845 shares of our common
stock if converted at December 31, 2003. In addition, Lime Rock Partners II,
LP holds immediately exercisable warrants to purchase 248,800 shares of our
common stock.

(5) Heartland Advisors, Inc. and William J. Nasgovitz in its capacity as
investment adviser to its clients holding shares of NATCO common stock, has
shared voting power with respect to 1,422,500 of the 1,621,000 shares it
beneficially owns and shares investment power with respect to all of such
shares.

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(6) Of the shares indicated as being beneficially owned by Mr. Gregory,
3,096,355 of such shares are owned directly by Capricorn Investors II, L.P.
Mr. Gregory is a member of Capricorn Holdings LLC, which serves as general
partner in Capricorn Investors II. Mr. Gregory disclaims beneficial
ownership of such shares exceeding his pecuniary interest.

(7) All of the shares indicated as being beneficially owned by Mr. Bates are
owned directly by Lime Rock Partners II, LP. Mr. Bates has an economic
interest in such shares though the general partner of Lime Rock Partners II,
LP, and is a member of a six-member investment committee that advises the
persons who have voting and investment power with respect to the shares
owned by Lime Rock. Mr. Bates disclaims beneficial ownership of the shares
owned by Lime Rock Investors II, LP.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

CERTAIN RELATIONSHIPS AND TRANSACTIONS

Under the terms of an employment agreement in effect prior to 1999, we
loaned our Chief Executive Officer $1.2 million in July 1999 to purchase 136,832
shares of common stock. During February 2000, after we completed the initial
public offering of our Class A common stock, also pursuant to the terms of that
employment agreement, we paid this executive officer a bonus equal to the
principal and interest accrued under this note arrangement and recorded
compensation expense of $1.3 million. The officer used the proceeds of this
settlement, net of tax, to repay the company approximately $665,000. In
addition, on October 27, 2000, our Board of Directors agreed to provide a full
recourse loan to this executive officer to facilitate the exercise of certain
outstanding stock options. The amount of the loan was equal to the cost to
exercise the options plus any personal tax burdens that resulted from the
exercise. The maturity of these loans was July 31, 2003, and interest accrued at
rates ranging from 6% to 7.8% per annum. As of June 30, 2002, the outstanding
principal and interest on these notes receivable totaled $3.4 million. Effective
July 1, 2002, the notes were reviewed by our board and amended to extend the
maturity dates to July 31, 2004, and to require interest to be calculated at an
annual rate based on the London Inter-Bank Offered Rate ("LIBOR") plus 300 basis
points, adjusted quarterly, applied to the notes balances as of June 30, 2002,
including previously accrued interest. As of December 31, 2002, the outstanding
principal and interest due from this officer under these notes was $3.6 million.
These loans, which were made on a full recourse basis in prior periods to
facilitate direct ownership in our common stock, are currently subject to and in
compliance with provisions of the Sarbanes-Oxley Act of 2002.

As previously agreed in 2001, we loaned our President $216,000 on April 15,
2002, under a full-recourse note arrangement which accrues interest at 6% per
annum and matured on July 31, 2003. The funds were used to pay the exercise cost
and personal tax burdens associated with the stock options exercised during
2001. Effective July 1, 2002, the note was amended to extend the maturity date
to July 31, 2004, and to require interest to be calculated at an annual rate
based on LIBOR plus 300 basis points, adjusted quarterly, applied to the note
balance as of June 30, 2002, including previously accrued interest. As of
December 31, 2002, the outstanding principal and interest on the note was
approximately $233,000. This loan, which was made on a full recourse basis to
facilitate direct ownership in our common stock, is currently subject to and in
compliance with provisions of the Sarbanes-Oxley Act of 2002.

We pay Capricorn Management G.P., an affiliate company of Capricorn
Holdings, Inc., for administrative services, which include office space and
parking in Connecticut for our Chief Executive Officer, reception, telephone,
computer services and other normal office support relating to that space. Mr.
Herbert S. Winokur, Jr., one of our directors, is the Chairman and Chief
Executive Officer of Capricorn Holdings, Inc., and the Managing Partner of
Capricorn Holdings LLC, which is the general partner of Capricorn Investors II,
L.P., a private investment partnership, and directly or indirectly controls
approximately 31% of our outstanding common stock. In addition, our Chief
Executive Officer, Mr. Gregory, is a non-salaried member of Capricorn Holdings
LLC. Capricorn Investors II, LP controls approximately 19% of our common stock.
Fees paid to Capricorn Management for these administrative services totaled
$115,000, $115,000 and $85,000 for the years ended December 31, 2003, 2002 and
2001, respectively. Commencing October 1, 2001, the fee

79

increased to $28,750 quarterly due primarily to an upward adjustment in
Capricorn Management's underlying lease for the office; this increase was
reviewed and approved by the Audit Committee of our Board of Directors. The
arrangement is terminable by either party on 90 days notice.

We recorded revenues of $91,000 for the year ended December 31, 2003,
related to equipment sold to the Wiser Oil Company. One of our Directors, Mr.
George K. Hickox, Jr., is the Chief Executive Officer of Wiser Oil Company.
These sales constituted less than one percent of NATCO's consolidated gross
revenues. NATCO purchased no equipment from Wiser Oil Company during 2003.

We recorded revenues of $859,000 for the year ended December 31, 2003,
related to equipment sold to The Houston Exploration Company. One of our
Directors, Mr. John U. Clarke, is a director of The Houston Exploration Company,
a publicly traded oil and gas exploration and production company.

EMPLOYMENT, TERMINATION AND CHANGE IN CONTROL ARRANGEMENTS

Mr. Gregory serves as our Chairman and Chief Executive Officer under an
employment agreement entered into in December 2002, which replaced his prior
employment agreement. The current agreement is for a term of three years unless
sooner terminated by Mr. Gregory or by us in accordance with its terms. The
agreement automatically extends for additional one-year periods unless we notify
Mr. Gregory 90 days prior to the termination date of the agreement that we do
not wish to renew the agreement. Under his agreement, Mr. Gregory is entitled to
receive an annual salary (currently $436,000), an annual bonus with a target
award of 75% of Mr. Gregory's base salary based on our financial performance and
certain other criteria as are determined annually by our Board of Directors, and
such additional bonus payments as the Board may determine in its sole
discretion. He is also entitled to participate in our fringe benefit and
insurance plans and to reimbursement of certain costs and expenses.

If, prior to a change in control, we terminate Mr. Gregory's employment for
any reason other than cause, or Mr. Gregory terminates his employment for good
reason (as defined in the agreement), Mr. Gregory will be entitled to severance
pay in accordance with any severance plan or policy that we may then have in
effect and any bonus compensation earned under the bonus plan that has
previously been deferred under the bonus plan. If, during the 36-month period
following a change in control, Mr. Gregory terminates his employment agreement
for good reason or we terminate Mr. Gregory, other than for cause, Mr. Gregory
will be entitled to salary and accrued vacation through the date of termination,
annual bonus earned through the date of termination, three times his base salary
and target bonus at the time of notice of termination or of a change in control,
whichever is greater; continuation of health, dental and life insurance benefit
for a period of three years following the date of termination; and all deferred
bonus compensation under the bonus plan. In addition, Mr. Gregory's stock
options shall immediately vest on the date of a change in control and the period
for exercising certain of these options may be extended.

Mr. McCarthy serves as our President under an employment agreement entered
into in December 2002. The terms of Mr. McCarthy's employment agreement are
substantially similar to those of Mr. Gregory under his employment agreement,
except that, under Mr. McCarthy's agreement, he is entitled to receive an annual
salary (currently $300,000), an annual bonus with a target award of 60% of Mr.
McCarthy's base salary, based on our financial performance and certain other
criteria which are determined annually by our Board of Directors, and such
additional bonus payments as the Board may determine in its sole discretion. If,
during the 36-month period following a change in control, Mr. McCarthy
terminates his employment agreement for a good reason (as defined in the
agreement) or we terminate Mr. McCarthy other than for cause, Mr. McCarthy will
be entitled to the same payment, benefits and treatment of his stock options as
described above for Mr. Gregory, except that the payment for his base salary
shall be two times his base salary at the time of notice of termination or
change in control, whichever is greater. Mr. McCarthy also will be entitled to
receive a payment equal to one year of his base salary in exchange for an
agreement not to compete with the Company.

In December 2002, we entered into Senior Management Change in Control
Agreements with our executive officers, including the other three named
executive officers, two of whom have since resigned from the company.
Substantially similar agreements were entered into with Mr. FitzGerald and Ms.
Ellis in August
80

2003. These agreements are for an initial term of three years, but renew for
successive one-year periods unless terminated earlier as provided in the
agreement. If, during the 24-month period following a change in control, the
executives employment is terminated by us other than for cause, or by the
executive for good reason (as defined in the respective agreements), we are
obligated to pay the executive's salary and accrued vacation through the date of
termination, annual bonus earned through the date of termination, an amount
equal to the product of two time the executive's base salary at the time of
termination or of notice of a change in control, whichever is greater,
continuation of health, dental and life insurance benefits for a period of two
years following the date of termination. These payments are in lieu of any other
severance to which the executive may be entitled under other severance
arrangements of the company, and are in addition to any stock options of the
executive. These stock options shall vest immediately upon the occurrence of a
change in control, and certain of these options may have extended exercise
periods.

For purposes of the above-referenced employment and change in control
agreements, the extent that any benefit, payment or distribution by the company
under the agreement would be subject to the excise tax imposed by Section 4999
of the U.S. internal revenue code, then such amount will be reduced to the
extent necessary to avoid the imposition of the excise tax.

Compensation policies in the event of a change-in-control are reviewed
regularly to ensure that the policies reflect terms and conditions consistent
with those adopted by comparable companies and that are in our best interests.
The Board of Directors or the GNC Committee may change such policies as the
facts and circumstances dictate.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Audit Fees. We paid audit fees to our independent public accountants, KPMG
LLP, totaling $543,547 and $433,945 for the years ended December 31, 2003 and
2002, respectively, for professional services rendered for the audit or our
annual financial statements.

Audit-Related Fees. We paid audit-related fees to KPMG LLP, totaling
$47,521 and $23,000 for the years ended December 31, 2003 and 2002,
respectively, related primarily to the audit of financial statements of an
employee benefit plan.

Tax Fees. We paid tax fees to KPMG LLP, totaling $72,587 and $30,523 for
the years ended December 31, 2003 and 2002. The fees paid related primarily to
tax compliance and consultation related to tax issues in the U.S., Canada and
the U.K.

All Other Fees. We paid other fees to KPMG LLP, totaling $2,750 and $2,750
for the years ended December 31, 2003 and 2002, respectively, related to the
preparation of an information return associated with our employee benefit plan.

POLICY ON AUDIT COMMITTEE PRE-APPROVAL OF AUDIT AND NON-AUDIT SERVICES OF
INDEPENDENT AUDITOR

The Audit Committee's policy is to pre-approve all audit and non-audit
services provided by the independent public accountants and auditors. These
services may include audit services, audit-related services, tax services and
other services. Pre-approval is generally provided for up to one year, is
detailed as to the particular service or category of services and is generally
subject to a specific budget. The Audit Committee has delegated to its chairman
authority to pre-approve engagements of our independent auditor or other
accountants to perform audit or non-audit services in amounts of up to $100,000
per engagement, subject to his subsequently reporting to the committee as to any
engagement he approves. The independent public accountants and auditors and
management are required to periodically report to the full Audit Committee
regarding the extent of services provided by the independent public accountants
and auditors in accordance with this pre-approval, and the fees for the services
performed to date. None of the services provided by the independent public
accountants and auditors under the categories Audit-Related, Tax and All Other
Fees described above were approved by the Audit Committee pursuant to the waiver
of pre-approval provisions set forth in Rule 2-01(c) of Regulation S-X.

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) Index to Financial Statements, Financial Statement Schedules and
Exhibits

(2) Financial Statement Schedules
No schedules have been included herein because the
information required to be submitted has been included
in our Consolidated Financial Statements or notes
thereto, or the required information is inapplicable.

(3) Index of Exhibits
(a) See index of Exhibits for a list of those exhibits
filed herewith, which index also includes and
identifies management contracts or compensatory
plans or arrangements required to be filed as
exhibits to this Form 10-K by Item 601 (10) (iii)
of Regulation S-K.
(b) Reports on Form 8-K. We filed a report on Form 8-K
on November 3, 2003, to announce our operating
results for the third quarter of 2003. We filed a
report on Form 8-K on February 24, 2004 to announce
our operating results for the fourth quarter of
2003. No other reports were filed on Form 8-K
during the fourth quarter of 2003.
(c) Index of Exhibits

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* Included with this Annual Report.

** Management contracts or compensatory plans or arrangements.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Act
of 1934, the Registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized, in the City of Houston, State of
Texas, on the 15th day of March 2004.

NATCO GROUP INC.
(Registrant)

By: /s/ NATHANIEL A. GREGORY
------------------------------------
Nathaniel A. Gregory
Chief Executive Officer and
Chairman of the Board of Directors

Pursuant to the requirements of the Securities Act of 1934, this report has
been signed below by the following persons in the capacities indicated, on March
15th, 2004.

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EXHIBIT INDEX

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* Included with this Annual Report.
** Management contracts or compensatory plans or arrangements.