KCS ENERGY INC - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NUMBER 1-11698

KCS ENERGY, INC.
(Exact name of registrant as specified in its charter)

DELAWARE 22-2889587
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

5555 SAN FELIPE ROAD, HOUSTON, TEXAS 77056
(Address of principal executive offices) (Zip Code)

REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
(713) 877-8006

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

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

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 10K.

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

The aggregate market value of the 31,656,301 shares of the Common Stock
held by non-affiliates of the registrant at the $1.75 closing price on June 28,
2002 (the last business day of the most recently completed second quarter) was
$55,398,527.

APPLICABLE ONLY TO REGISTRANTS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING
THE PRECEDING FIVE YEARS: Indicate by check mark whether the registrant has
filed all documents and reports required to be filed by Section 12, 13 or 15(d)
of the Securities Exchange Act of 1934 subsequent to the distribution of
securities under a plan confirmed by a court. Yes: [ ] No [ ]

Not applicable. Although the registrant was involved in bankruptcy
proceedings during the preceding five years, the registrant did not distribute
securities under its plan of reorganization.

Number of shares of Common Stock outstanding as of the close of business on
March 12, 2003: 38,008,028

DOCUMENTS INCORPORATED BY REFERENCE

Part III incorporates information by reference from the registrant's Proxy
Statement for the 2003 Annual Meeting of Shareholders to the extent indicated
herein.
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KCS ENERGY, INC.

FORM 10-K
REPORT FOR THE YEAR ENDED DECEMBER 31, 2002

PART I

ITEM 1. BUSINESS

GENERAL DEVELOPMENT OF BUSINESS

KCS Energy, Inc., a Delaware Corporation ("KCS" or the "Company"), is an
independent oil and gas company engaged in the acquisition, exploration and
production of natural gas and crude oil with operations predominately in the
Mid-Continent and onshore Gulf Coast regions. The Company was formed in 1988 in
connection with the spin-off of the non-utility businesses of NUI Corporation, a
New Jersey-based natural gas distribution company that had been engaged in the
oil and gas exploration and production business as well as numerous other
businesses since the late 1960s.

The Company's main objective in 2002 was to position itself to meet its
Senior Note obligations due January 15, 2003. In order to meet this objective,
KCS curtailed its drilling and overall capital expenditure programs and sold
certain non-core assets. These actions positioned the Company to reduce its debt
and negotiate the financing necessary to pay off the remaining portion of the
maturing Senior Notes during a difficult period in the capital markets. Although
the asset sales and curtailed drilling and capital expenditure programs resulted
in lower production and reserves in 2002, the Company exited the year in a
stronger financial position, with increased financial flexibility, a focused
asset base in its core areas, and a quality multi-year drilling prospect
inventory.

On January 14, 2003, the Company completed the arrangements necessary to
amend and restate its existing credit agreement with a group of institutional
lenders. The amended facility provides $90.0 million of borrowing capacity,
$40.0 million in the form of a term loan and $50.0 million in revolving
facilities, and matures on October 3, 2005. Initial proceeds of $69.3 million
were used primarily to pay off the balance of the maturing Senior Note
obligations, leaving $20.7 million of available borrowing capacity under the
facility.

The Company reduced lifting costs (lease operating expenses and production
taxes) by 20% and general and administrative expenses by 7% in 2002 and expects
further reductions in 2003. With the completion of the financing and the
implementation of this cost reduction program, the Company believes it is
positioned to capitalize on the strong natural gas price environment and to
focus on developing its prospect inventory to grow reserves and production in
its core areas.

Overall, KCS has reduced its debt from a peak of $425 million in early 1999
to $194.3 million on January 15, 2003 and is committed to further debt
reduction.

OIL AND GAS OPERATIONS

All of the Company's exploration and production activities are located
within the United States. The Company competes with major oil and gas companies,
other independent oil and gas concerns and individual producers and operators in
reserve and leasehold acquisitions, and the exploration, development, production
and marketing of oil and gas, as well as contracting for equipment and hiring of
personnel. Oil and gas prices have been volatile historically and are expected
to be volatile in the future. Prices for oil and gas are subject to wide
fluctuation in response to relatively minor changes in the supply of and demand
for oil and gas, market uncertainty and a variety of additional factors that are
beyond the Company's control. These factors include political conditions in the
Middle East and elsewhere, the foreign supply of oil and gas, the price of
foreign imports, the level of consumer product demand, weather conditions,
domestic and foreign government regulations and taxes, the price and
availability of alternative fuels and overall economic conditions.

1

EXPLORATION AND PRODUCTION ACTIVITIES

During the three-year period ended December 31, 2002, the Company
participated in drilling 255 gross (111.7 net) wells, of which 82% were
successful. In 2002, the Company participated in drilling 53 gross (22.1 net)
wells, of which 74% were successful. This included 34 (15.4 net) development
wells and 19 (6.7 net) exploration wells with success rates of 85% and 53%,
respectively.

In 2002, the Company concentrated its drilling programs predominately in
the Mid-Continent and Gulf Coast regions. In the Mid-Continent region, the
Company explores in Oklahoma (Anadarko and Arkoma basins), north Louisiana, west
Texas and Michigan. During 2002, the Company drilled 29 gross (16.7 net) wells
in this region with an 86% success ratio.

Thirteen of the wells drilled in 2002 were in the north Louisiana core
area, including six wells in the Elm Grove Field, a discovery in the Stockman
Creek Field, a step-out location in the South Drew Field and three development
wells in the Simsboro Field. The Company has a multi-year inventory of locations
in north Louisiana and anticipates a significant portion of its 2003 program to
be focused on this area.

Eight wells were drilled in Oklahoma in 2002, including the Talihina Field
discovery in Latimer County. The Company also had excellent results in extension
drilling in the Panola Field.

KCS curtailed its drilling to an aggregate of only five wells in the Sawyer
Canyon Field in west Texas and the West Shugart Field in New Mexico in order to
conserve cash. A substantial increase in drilling is expected in the Sawyer
Canyon Field in 2003.

In the Gulf Coast region, the Company explores in south Texas and the
Mississippi salt basin. During 2002, the Company drilled 24 gross (5.4 net)
wells with a 58% success ratio in this region.

In south Texas, the Company participated in 17 wells, including discoveries
in the Dolan and La Reforma fields. The Guerra C-1 in the La Reforma Field
appears to be the most significant discovery of the year with follow-up drilling
anticipated in 2003.

The Company also made four small acquisitions of reserves, all with future
drilling potential.

A larger inventory of drilling prospects and higher levels of expected
internally generated cash flow should result in increased drilling and workover
activity in 2003.

VOLUMETRIC PRODUCTION PAYMENT PROGRAM

From August 1994 through December 31, 2002, the Company augmented its
working interest ownership of properties with a VPP program, a method of
acquiring oil and gas reserves scheduled to be delivered in the future at a
discount to the then current market price in exchange for an up-front cash
payment. A VPP acquisition entitles the Company to a priority right to a
specified volume of oil and gas reserves scheduled to be produced and delivered
on an agreed delivery schedule. Typically, the estimated proved reserves of the
properties underlying a VPP are substantially greater than the specified reserve
volumes required to be delivered pursuant to the production payment. Although
specific terms of its VPPs varied, the Company was generally entitled to receive
delivery of its scheduled oil and gas volumes at agreed delivery points, free of
drilling and lease operating costs and free of state severance taxes. The
Company believes that its VPP program diversified its reserve base while
achieving attractive rates of return and minimizing exposure to certain
development, operating and reserve volume risks.

From the inception of the VPP program in August 1994, the Company invested
$213.6 million under the VPP program and acquired proved reserves of 120.3 Bcfe
of natural gas and oil. Through December 31, 2002, the Company realized
approximately $293.9 million from the sale of oil and gas acquired under the
program and 10.6 Bcfe of a VPP which was converted to a working interest after
its acquisition. Due to limited capital availability, the Company made only
minimal VPP investments after 1999, and did not make any VPP investments in 2001
or 2002. As a result, final deliveries under the Company's VPP acquisition
program were received in December 2002. The Company is considering the use of
joint venture partnerships or similar arrangements with third parties to fund
another VPP acquisition program in the future.

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PRODUCTION PAYMENT

In connection with its emergence from bankruptcy in 2001, the Company sold
a 43.1 Bcfe (38.3 Bcf of gas and 797,000 barrels of oil) production payment to
be delivered in accordance with an agreed schedule over a five-year period for
net proceeds of approximately $175 million (the "Production Payment"). See Notes
1 and 2 to Consolidated Financial Statements. Amortization of deferred revenue
attributable to volumes delivered under the Production Payment comprised 38% and
36% of the Company's oil and gas revenue in 2002 and 2001, respectively. Other
than this amortization of deferred revenue, no customer accounted for more than
10% of the Company's revenues in 2002, 2001 or 2000.

RAW MATERIALS

The Company obtains its raw materials from various sources, which are
presently considered adequate. While the Company regards the various sources as
important, it does not consider any one source to be essential to its business
as a whole.

PATENTS AND LICENSES

There are no patents, trademarks, licenses, franchises or concessions held
by the Company, the expiration of which would have a material adverse effect on
its business.

SEASONALITY

Demand for natural gas and oil is seasonal, principally related to weather
conditions and access to pipeline transportation.

OIL AND GAS RISK FACTORS

As described below, the Company's oil and gas operations make it subject to
a variety of risks.

Volatile Nature of Oil and Gas Markets; Fluctuation in Prices. The
Company's future financial condition and operating results are highly dependent
on the demand for and prices received for the Company's oil and gas production
and on the costs of acquiring, exploring for, developing and producing reserves.
Oil and gas prices have been, and are expected to continue to be, volatile.
Prices for oil and gas fluctuate widely in response to relatively minor changes
in the supply of and demand for oil and gas, market uncertainty, and a variety
of additional factors beyond the Company's control. These factors include:

- worldwide political conditions (especially in the Middle East and other
oil-producing regions);

- the domestic and foreign supply of oil and gas;

- the level of consumer demand;

- weather conditions;

- domestic and foreign government regulations and taxes; and

- the price and availability of alternative fuels and overall economic
conditions.

A decline in oil or gas prices may adversely affect the Company's cash
flow, liquidity and profitability. Lower oil or gas prices also may reduce the
quantity of the Company's oil and gas that can be produced economically. It is
impossible to predict future oil and gas price movements with any certainty.
Under the full cost method of accounting, capitalized costs of oil and gas
properties, net of accumulated depreciation, depletion and amortization ("DD&A")
and related deferred taxes, are limited to the sum of the present value of
estimated future net revenues from proved oil and gas reserves at current prices
discounted at 10%, net of related tax effects plus the lower of cost or fair
value of unproved properties. To the extent that the capitalized costs exceed
this "ceiling" limitation at the end of any quarter, such excess is expensed.
Given the volatility of oil and gas prices, it is possible that the Company's
estimate of discounted future net cash flows from proved

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oil and gas reserves could change in the near term. If oil and gas prices
decline significantly, even if only for a short period of time, it is possible
that non-cash writedowns of oil and gas properties could occur.

Dependence on Acquiring and Finding Additional Reserves. The Company's
prospects for future growth and profitability depend primarily on its ability to
replace oil and gas reserves through acquisitions, development and exploratory
drilling. Acquisitions may not be available at attractive prices. The decision
to purchase, explore or develop a property depends in part on geophysical and
geological analyses and engineering studies, which are often inconclusive or
subject to varying interpretations. Consequently, there can be no assurance that
the Company's acquisition, development and exploration activities will result in
significant additional reserves, nor can there be any assurance that the Company
will be successful in drilling economically productive wells. Without
acquisition, development or discovery of additional reserves, the Company's
proved reserves and revenues will decline.

Reliance on Estimates of Reserves and Future Net Cash Flows. This Form
10-K includes estimates by independent petroleum engineers of the Company's oil
and gas reserves and future net cash flows. There are numerous uncertainties
inherent in estimating quantities of oil and gas reserves, including many
factors beyond the Company's control. Reserve engineering is a subjective
process of estimating underground accumulations of oil and gas that cannot be
measured in an exact manner. To estimate oil and gas reserves and future net
cash flow, reserve engineers make a number of assumptions, which may vary
considerably from actual results. These assumptions include:

- the effects of regulation by government agencies;

- future oil and gas prices;

- operating costs;

- severance and excise taxes; and

- development costs.

For these reasons, reserve estimates, classifications of reserves based on
risk of recovery, and estimates of future net cash flows prepared by different
engineers, or by the same engineers at different times, may vary significantly.
Actual production, revenues and expenditures with respect to the Company's
reserves likely will vary from estimates, possibly materially. The Company's
projected reserves and future cash flows may be subject to revisions based upon
production history, oil and gas prices, performance of counterparties under the
Company's contracts, operating and development costs and other factors.

This Form 10-K refers to the present value of future net revenues ("PV-10
value") of the Company's reserves. The PV-10 value of reserves means the present
value of estimated future net revenues, computed by applying year-end prices to
estimated future production from the reserves, deducting estimated future
expenditures, and applying a discount factor of ten percent (10%). The PV-10
values referred to in this Form 10-K should not be construed as the current
market value of the Company's estimated oil and gas reserves. In accordance with
applicable requirements of the Securities and Exchange Commission ("SEC"), PV-10
value is generally based on prices and costs as of the date of the estimate,
whereas actual future prices and costs may be materially higher or lower. Actual
future net cash flows also will be affected by factors such as (i) the amount
and timing of actual production and expenditures to develop and produce
reserves, (ii) the supply and demand for oil and gas, and (iii) changes in
government regulations or taxation. In addition, the 10% discount factor, which
the SEC requires to be used to calculate present value for reporting purposes,
is not necessarily the most appropriate discount factor based on interest rates
in effect from time to time and risks associated with the Company and its
properties or the oil and gas industry in general.

Exploration Risks. Exploratory drilling activities are subject to many
risks, and there can be no assurance that new wells drilled by the Company will
be productive or that the Company will recover all or any portion of its
investment. Drilling for oil and gas may be unprofitable due to a number of
risks, including:

- wells may not be productive, either because commercially productive
reservoirs were not encountered or for other reasons;

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- wells that are productive may not provide sufficient net revenues to
return a profit after drilling, operating and other costs; and

- the costs of drilling, completing and operating wells are often
uncertain.

In addition, the Company's drilling operations may be curtailed, delayed or
canceled as a result of numerous factors, many of which are beyond the Company's
control. These factors may include title problems, weather conditions,
compliance with government requirements, pressure or irregularities in
formations, equipment failures or accidents, and shortages or delays in the
delivery of equipment and services.

Marketing Risks. The Company's ability to market oil and gas at
commercially acceptable prices depends on, among other factors, the availability
and capacity of gathering systems and pipelines, federal and state regulation of
production and transportation, general economic conditions and changes in supply
and demand. The Company's inability to respond appropriately to changes in these
factors could negatively effect the Company's profitability.

Acquisition Risks. Acquisitions of oil and gas businesses and properties
have been an important element of the Company's business, and the Company will
continue to pursue acquisitions in the future. Even though the Company performs
a review (including review of title and other records) of the major properties
it seeks to acquire that it believes is consistent with industry practices, such
reviews are inherently incomplete. It is generally not feasible for the Company
to review in-depth every property and all records involved in each acquisition.
Even an in-depth review may not reveal existing or potential problems or permit
the Company to become familiar enough with the properties to assess fully their
deficiencies and potential. The success of any acquisition will depend on a
number of factors, including the ability to estimate accurately the recoverable
volumes of reserves, rates of future production and future net revenues
attainable from the reserves and to assess possible environmental liabilities.
Even when problems are identified, the Company may assume certain environmental
and other risks and liabilities in connection with acquired businesses and
properties.

Operating Risks. The Company's operations are subject to numerous
operating risks inherent in the oil and gas industry which could result in
substantial losses to the Company. These risks include, for example, fires,
explosions, well blow-outs, pipe failure, oil spills, natural gas leaks or
ruptures, or other discharges of toxic gases or other pollutants. The occurrence
of these risks could result in substantial losses to the Company due to personal
injury, loss of life, damage to or destruction of wells, production facilities
or other property or equipment, or damage to the environment. Such occurrences
could also subject the Company to clean-up obligations, regulatory
investigation, penalties or suspension of operations. Further, the Company's
operations may be materially curtailed, delayed or canceled as a result of
numerous factors, including the presence of unanticipated pressure or
irregularities in formations, accidents, title problems, weather conditions,
compliance with government requirements and shortages or delays in obtaining
drilling rigs or in the delivery of equipment. In accordance with customary
industry practice, the Company maintains insurance against some, but not all, of
the risks described above. There can be no assurance that the levels of
insurance maintained by the Company will be adequate to cover any losses or
liabilities. The Company cannot predict the continued availability of insurance
or availability at commercially acceptable premium levels.

Competitive Industry. The oil and gas industry is highly competitive. The
Company competes with major oil and gas companies, other independent oil and gas
concerns and individual producers and operators to acquire oil and gas
businesses, properties and equipment, and to hire personnel necessary to explore
for, develop, produce, transport and market oil and gas. Many of these
competitors have financial and other resources that substantially exceed those
available to the Company.

Government Regulation. The Company's business is subject to numerous
federal, state and local laws and regulations, including energy, environmental,
conservation, tax and other laws and regulations relating to the energy
industry. Administrative and legislative proposals are frequently introduced, at
both the state and federal level which, if adopted or enacted, might
significantly affect the industry. The Company cannot predict whether, or when,
such laws and regulations may be enacted or adopted, and cannot predict the cost
of compliance with such changing laws and regulations or their effects on oil
and gas use or prices.

5

REGULATION

General. The Company's business is affected by numerous laws and
regulations, including energy, environmental, conservation, tax and other laws
and regulations relating to the energy industry. Changes in any of these laws
and regulations could have a material adverse effect on the Company's business.
In view of the many uncertainties with respect to current and future laws and
regulations, including their applicability to the Company, the Company cannot
predict the overall effect of such laws and regulations on its future
operations.

The Company believes that its operations comply in all material respects
with all applicable laws and regulations. Although such laws and regulations
have a substantial impact upon the energy industry, generally these laws and
regulations do not appear to affect the Company any differently, or to any
greater or lesser extent, than other similar companies in the energy industry.

The following discussion describes certain laws and regulations applicable
to the energy industry and is qualified in its entirety by the foregoing.

State Regulations Affecting Production Operations. The Company's onshore
exploration, production and exploitation activities are subject to regulation at
the state level. Laws and regulations vary from state to state, but generally
include laws to regulate drilling and production activities and to promote
resource conservation. Examples of such state laws and regulations include laws
which:

- require permits and bonds to drill and operate wells;

- regulate the method of drilling and casing wells;

- establish surface use and restoration requirements for properties upon
which wells are drilled;

- regulate plugging and abandonment of wells;

- regulate the disposal of fluids used or produced in connection with
operations;

- regulate the location of wells, including establishing the minimum size
of drilling units and the minimum spacing between wells;

- concern unitization or pooling of oil and gas properties;

- establish maximum rates of production from oil and gas wells; and

- restrict the venting or flaring of gas.

These regulations and requirements may affect the profitability of affected
properties or operations. The Company is unable to predict the future cost or
impact of complying with such regulations.

Regulations Affecting Sales and Transportation of Oil and Gas. Various
aspects of the Company's oil and gas operations are regulated by agencies of the
federal government. Pursuant to the Natural Gas Act of 1938 (the "NGA") and the
Natural Gas Policy Act of 1978 (the "NGPA"), the Federal Energy Regulatory
Commission (the "FERC") regulates the transportation of natural gas in
interstate commerce including some natural gas produced or marketed by the
Company. In the past, the federal government regulated the prices at which the
Company's natural gas could be sold. Currently, "first sales" of natural gas by
producers and marketers, and all sales of crude oil, condensate and natural gas
liquids can be made at uncontrolled market prices, but Congress could reenact
price controls at any time. The FERC continues to examine its policies affecting
the natural gas industry. It is not possible for the Company to predict what
effect, if any, the ultimate outcome of the FERC's various initiatives will have
on the Company's operations.

The FERC continues to authorize the sale and abandonment from NGA
regulation of natural gas gathering facilities previously owned by interstate
pipelines. Such facilities and services on such systems may be subject to
regulation by state authorities in accordance with state law. In general, state
regulation of gathering facilities includes various safety, environmental and,
in some circumstances, nondiscriminatory take requirements, but does not
generally entail regulation of the gathering rates charged. Natural gas
gathering may receive greater regulatory scrutiny by state agencies in the
future, and in that event, the Company's
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gathering operations could be adversely affected; however, the Company does not
believe that it would be affected by such regulation any differently from other
natural gas producers or gatherers. The effects, if any, of changes in existing
state or FERC policies on the Company's gas gathering or gas marketing
operations are uncertain.

Sales of crude oil, condensate and natural gas liquids by the Company are
not currently regulated and are made at market prices. The price the Company
receives from the sale of these products is affected by the cost of transporting
the products to market. Effective January 1, 1995, the FERC implemented
regulations establishing an indexing system for transportation rates for oil
pipelines, which generally index such rates to inflation, subject to certain
conditions and limitations. The Company is not able to predict with certainty
what effect, if any, these regulations will have on its business, but other
factors being equal, the regulations may tend to increase transportation costs
or reduce wellhead prices under certain conditions.

Federal Regulations Affecting Production Operations. The Company also
operates federal and Indian oil and gas leases, which are subject to the
regulation of the United States Bureau of Land Management ("BLM"), the Bureau of
Indian Affairs ("BIA") and the United States Minerals Management Service
("MMS").

MMS, BIA and BLM leases contain relatively standardized terms requiring
compliance with detailed regulations and orders. Such regulations specify, for
example, lease operating, safety and conservation standards, well plugging and
abandonment requirements, and surface restoration requirements. In addition, the
BIA, BLM and MMS generally require lessees to post bonds or other acceptable
surety to assure that their obligations will be met. The cost of such bonds or
other surety can be substantial and there is no assurance that any particular
lease operator can obtain bonds or other surety in all cases. Under certain
circumstances, the MMS, BIA or BLM may require operations on federal or Indian
leases to be suspended or terminated. Any such suspension or termination could
adversely affect the Company's interests.

Effective June 1, 2000, the MMS amended its regulations governing the
calculation of royalties and the valuation of crude oil produced from federal
leases. The amendments modify the valuation procedures for both arm's length and
non-arm's length crude oil transactions to decrease reliance on posted oil
prices and assign a value to crude oil that better reflects its market value.
Similar changes have been proposed with regard to valuation of Indian royalty
oil. The Company is not able to predict with certainty the effect, if any, these
regulations will have on its business, but believes that the regulations will
not have a greater effect on the Company than on other similar companies in the
energy industry.

The MMS also continues to consider changes to the way it values natural gas
for royalty payments. These changes would establish an alternative market-based
method to calculate royalties on certain natural gas sold to affiliates or
pursuant to non-arm's length sales contracts. Discussions among the MMS,
industry officials and Congress are continuing, although it is uncertain whether
and what changes may ultimately be proposed regarding natural gas royalty
valuation.

Additional proposals and proceedings that might affect the oil and gas
industry are pending before Congress, the FERC, the MMS, the BLM, the BIA, state
commissions and the courts. The Company cannot predict when or whether any such
proposals may become effective. Historically, the natural gas industry has been
very heavily regulated. There is no assurance that the current regulatory
approach pursued by various agencies will continue indefinitely. Notwithstanding
the foregoing, it is not anticipated that compliance with existing federal,
state and local laws, rules and regulations will have a material or
significantly adverse effect upon the capital expenditures, earnings or
competitive position of the Company.

Operating Hazards and Environmental Matters. The oil and gas business
involves a variety of operating risks, including the risk of fires, explosions,
well blow-outs, pipe failure, oil spills, natural gas leaks or ruptures, or
other discharges of toxic gases or other pollutants. The occurrence of these
risks could result in substantial losses to the Company due to personal injury,
loss of life, damage to or destruction of wells, production facilities or other
property or equipment, or damage to the environment. Such occurrences could also
subject the Company to clean-up obligations, regulatory investigation, penalties
or suspension of operations. Although

7

the Company believes it is adequately insured, such hazards may hinder or delay
drilling, development and production operations.

Oil and gas operations are subject to extensive federal, state and local
laws and regulations that regulate the discharge of materials into the
environment or otherwise relate to the protection of the environment. These laws
and regulations may:

- require the acquisition of a permit before drilling commences;

- restrict the types, quantities and concentration of substances that can
be released into the environment;

- restrict drilling activities on certain lands, such as wetlands or other
protected areas; and

- impose substantial liabilities for pollution resulting from drilling and
production operations.

Failure to comply with these laws and regulations may also result in civil and
criminal fines and penalties.

The Company's properties, and any wastes spilled or disposed of by the
Company, may be subject to federal or state environmental laws that could
require the Company to remove the wastes or remediate contamination. For
example, the Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the original conduct, on certain classes of persons who are
considered to be responsible for the release of a "hazardous substance" into the
environment. These persons include the owner or operator of the disposal site or
sites where the release occurred and companies that disposed or arranged for the
disposal of the hazardous substances. Under CERCLA, such persons may be subject
to joint and several liability for the costs of cleaning up the hazardous
substances, for damages to natural resources and for the costs of certain health
studies. In addition, it is not uncommon for neighboring landowners and other
third parties to assert claims for personal injury and property damage allegedly
caused by the release of hazardous substances. See "Environmental Claims" below.

Also, the Company's operations may be subject to the Clean Air Act ("CAA")
and comparable state and local requirements. The Company may be required to
incur certain capital expenditures for air pollution control equipment in
connection with maintaining or obtaining permits and approvals relating to air
emissions. The Company does not believe that its operations will be materially
adversely affected by any such requirements.

In addition, the U.S. Oil Pollution Act ("OPA") requires owners and
operators of facilities in or near rivers, creeks, wetlands, coastal waters,
offshore waters, and other U.S. waters to adopt and implement plans and
procedures to prevent oil spills. OPA also requires affected facility owners and
operators to demonstrate that they have at least $35 million in financial
resources to pay for the costs of cleaning up an oil spill and compensating any
parties damaged by an oil spill. Such financial assurances may be increased to
as much as $150 million if a formal assessment indicates such an increase is
warranted.

The Company's operations are also subject to the federal Clean Water Act
("CWA") and analogous state laws. Among other matters, such laws may prohibit
the discharge of waters produced in association with hydrocarbons into coastal
waters. To comply with this prohibition, the Company may be required to incur
capital expenditures or increased operating expenses. The CWA also regulates
discharges of storm water runoff. This program requires covered facilities to
obtain individual permits, participate in a group permit or seek coverage under
a general permit. While certain of its properties may require permits for
discharges of storm water runoff, the Company believes that it will be able to
obtain, or be included under, such permits, where necessary. Such coverage may
require the Company to make minor modifications to existing facilities and
operations that would not have a material effect on the Company.

Pursuant to the Safe Drinking Water Act, underground injection control
("UIC") wells, including wells used in enhanced recovery and disposal operations
associated with oil and gas exploration and production activities, are subject
to regulation. Such regulations include permitting, bonding, operating,
maintenance and reporting requirements.

8

In addition, the disposal of wastes containing naturally occurring
radioactive material, which is commonly encountered during oil and gas
production, is regulated under state law. Typically, wastes containing naturally
occurring radioactive material can be managed on-site or disposed of at
facilities licensed to receive such waste at costs that are not expected to be
material.

Environmental Claims. The Company owns the following two oil and gas
leases covering an aggregate of approximately 11,000 acres in Los Angeles
County, California: a) Oil and Gas Lease dated June 13, 1935, from Newhall Land
and Farming Company, as Lessor, to Barnsdall Oil Company, as Lessee (the "RSF
Lease"); and b) Oil and Gas Lease dated June 6, 1941, from the Newhall
Corporation, as Lessor, to C.G. Willis, as Lessee (the "Ferguson Lease"). The
RSF Lease and the Ferguson Lease are herein called the "Leases." Oil and gas
production from such lands commenced shortly after the RSF Lease was granted and
has continued to date.

From the inception of the Leases until October 30, 1990, the Leases were
owned by entities that through corporate succession and name change ultimately
became Sun Operating Limited Partnership ("Sun L.P."). On October 30, 1990, Sun
L.P. transferred the Leases to DKM Offshore Energy, Inc. ("DKM") and Neste Oil
Services Inc. ("Neste"). In the assignment of the Leases, Sun L.P. indemnified
DKM and Neste from environmental claims resulting from the indemnitors'
operations provided that such environmental claims were made within ten years
from October 30, 1990. Shortly after the transfer to DKM and Neste, DKM acquired
Neste's rights and, subsequently, DKM became Medallion California Properties
Company ("Medallion California"). Later, the Company acquired the stock of
Medallion California. Also, Sun L.P. became Kerr-McGee Oil & Gas Onshore L.P.
("Kerr-McGee L.P."). In connection with the purchase of Medallion California by
KCS, InterCoast Energy Company ("InterCoast"), the seller, indemnified the
Company and Medallion California for up to 90% of the costs of environmental
remediation not assumed by Kerr-McGee L.P. InterCoast's parent, MidAmerican
Capital Company ("MidAmerican"), guaranteed InterCoast's indemnity obligations.
The nature and extent of both the Sun L.P. and InterCoast indemnities were
recently classified by an Agreed Judgment entered in a Harris County Texas
District Court. See Note 10 to the Consolidated Financial Statements included
herein.

Kerr-McGee L.P. identified 21 sites for cleanup on the lands covered by the
Leases and had a Remedial Action Plan ("RAP") approved by the Los Angeles County
Regional Water Quality Control Board to effect such cleanup. The primary
contaminant identified for this cleanup is petroleum waste. The Company has been
advised that Kerr-McGee L.P. has substantially completed the cleanup of 19 of
these sites. The Company believes that Kerr-McGee L.P. will ultimately
accomplish the RAP and that the Company has no exposure for remediation of these
21 sites.

In addition to the 21 sites identified in the RAP, the Company has
identified and analyzed samples from numerous additional sites and has found
that certain of those sites are contaminated with petroleum waste. The Company
has described those sites to the lessors, Kerr-McGee L.P., InterCoast and
MidAmerican. The Company believes Kerr-McGee L.P. will ultimately be responsible
for remediation of substantially all of the additional sites.

Litigation is currently pending in which the Lessor of the RSF Lease seeks,
among other remedies, damages for alleged environmental contamination and site
restoration of the lands covered by the RSF Lease, and in which Medallion
California claims indemnification is owed by Kerr-McGee L.P., InterCoast and
MidAmerican. See Note 10 to the Consolidated Financial Statements included
herein.

EMPLOYEES

The Company has reduced its workforce over the last several years and
employed a total of 119 persons on December 31, 2002.

AVAILABLE INFORMATION

The Company's Internet website is www.kcsenergy.com. The Investor Relations
portion of the Company's website is www.kcsenergy.com/html/investor.html and it
contains information about the Company,

9

including its annual report on Form 10-K, quarterly reports on Form 10-Q,
current reports on Form 8-K and amendments to those reports filed or furnished
pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as
amended (the "Exchange Act"). These reports may be downloaded, free of charge,
from the website. Since November 15, 2002, the Company has generally made these
reports available on its website within a few days after they are electronically
filed with, or furnished to, the SEC. In the future, the Company intends to make
these reports available as soon as reasonably practicable after they are
electronically filed with, or furnished to, the Securities and Exchange
Commission. Paper copies of these reports are available free of charge upon
request.

ITEM 2. PROPERTIES

OIL AND GAS PROPERTIES

The following table sets forth data as of December 31, 2002 regarding the
number of gross and net producing wells, and the estimated quantities of proved
oil and gas reserves attributable to the Company's principal operating regions.

Approximately 79% of the Company's reserves are attributable to wells it
operates.

MID-CONTINENT REGION

In the Mid-Continent region, the Company is pursuing opportunities
primarily in Oklahoma (Anadarko and Arkoma basins), north Louisiana, west Texas
and Michigan. This region also includes producing properties in the Rocky
Mountains and California. The Company views the Mid-Continent region as
providing a solid base for production replacement and plans to continue to
exploit areas within the various basins that require additional wells for
adequate reserve drainage and to drill low-risk exploration wells. These wells
are generally step-out and extension type wells with moderate reserve potential.

Estimated proved reserves in the Mid-Continent region were 132.0 Bcfe as of
December 31, 2002, representing approximately 67% of the Company's reserves. At
December 31, 2002, the Company owned leasehold interests within the
Mid-Continent region covering approximately 220,269 gross (168,010 net) acres.

GULF COAST REGION

The Gulf Coast region is primarily comprised of producing properties in
south Texas, coastal Louisiana and the Mississippi Salt Basin and minor
non-operated offshore properties. The Company conducts development programs and
pursues moderate-risk, higher potential exploration drilling programs in this
region. The Gulf Coast region has prospects which are expected to provide the
key area of future growth for the Company. Estimated proved reserves in the
region were 63.6 Bcfe as of December 31, 2002, which represented approximately
33% of the Company's reserves. The Company owns or controls approximately
209,311 gross (46,128 net) acres in the Gulf Coast region.

OIL AND GAS RESERVES

The reserve estimates and associated cash flows for all properties for the
years ended December 31, 2002 and 2000 were prepared by Netherland, Sewell &
Associates, Inc. ("NSA"). For the year ended December 31, 2001, the reserve
estimates were prepared by the Company and audited by NSA.

10

The following table sets forth, as of December 31, 2002, summary
information with respect to estimates of the Company's proved oil and gas
reserves based on year-end prices. Oil and gas prices at December 31, 2002 are
not necessarily reflective of the prices that the Company expects to receive in
the future. For this reason and as a result of the uncertainties described in
the following paragraph, the present value of future net revenues in the table
should not be construed to be the current market value of the estimated oil and
gas reserves owned by the Company.

There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves and in projecting future rates of production and
future amounts and timing of development expenditures, including underground
accumulations of crude oil and natural gas that cannot be measured in an exact
manner. The accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Estimates of proved undeveloped reserves are inherently less certain than
estimates of proved developed reserves. The quantities of oil and gas that are
ultimately recovered, production and operating costs, the amount and timing of
future development expenditures, geologic success and future oil and gas sales
prices all may differ from those assumed in these estimates. In addition, the
Company's reserves may be subject to downward or upward revision based upon
production history, results of future development, prevailing oil and gas prices
and other factors.

In accordance with SEC guidelines, the estimates of future net revenues
from the Company's proved reserves and the present values thereof are made using
oil and gas sales prices in effect as of the dates of such estimates and are
held constant throughout the life of the properties except where such guidelines
permit alternate treatment, including, in the case of natural gas contracts, the
use of fixed and determinable contractual price escalations. Gas prices are
based on either a contract price or a December 31, 2002 spot price of $4.74 per
MMbtu, adjusted by lease for Btu content, transportation fees and regional price
differentials. Oil prices are based on a December 31, 2002 West Texas
Intermediate posted price of $28.00 per barrel, adjusted by lease for gravity,
transportation fees and regional price differentials. The prices for natural gas
and oil are subject to substantial seasonal fluctuations, and prices for each
are subject to substantial fluctuations as a result of numerous other factors.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Oil and Gas Risk Factors."

ACREAGE

The following table sets forth certain information with respect to the
Company's developed and undeveloped leased acreage as of December 31, 2002. The
leases in which the Company has an interest are for varying primary terms, and
many require the payment of delay rentals to continue the primary term. The

11

operator may surrender the leases at any time by notices to the lessors, by the
cessation of production, fulfillment of commitments, or by failure to make
timely payments of delay rentals.

TITLE TO INTERESTS

The Company believes that title to the various interests set forth above is
satisfactory and consistent with the standards generally accepted in the oil and
gas industry, subject only to immaterial exceptions which do not detract
substantially from the value of the interests or materially interfere with their
use in the Company's operations. The interests owned by KCS may be subject to
one or more royalty, overriding royalty and other outstanding interests
customary in the industry. The interests may additionally be subject to
obligations or duties under applicable laws, ordinances, rules, regulations and
orders of arbitral or governmental authorities. In addition, the interests may
be subject to burdens such as production payments, net profits interests,
development obligations under oil and gas leases and other encumbrances,
easements and restrictions.

DRILLING ACTIVITIES

All of the Company's drilling activities are conducted through arrangements
with independent contractors. Certain information with regard to the Company's
drilling activities during the years ended December 31, 2002, 2001 and 2000, is
set forth below.

At December 31, 2002, the Company was participating in the drilling of 1
gross (1.0 net) well.

12

PRODUCTION

The following table presents certain information with respect to oil and
gas production attributable to the Company's properties and average sales prices
during the three years ended December 31, 2002, 2001 and 2000.

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

(a) Production includes 11,196 Mmcfe and 15,716 Mmcfe in 2002 and 2001,
respectively, dedicated to the Production Payment sold in February 2001.
See Notes 1 and 2 to Consolidated Financial Statements.
(b) Includes the effects of hedging and, in 2002 and 2001, amortization of
deferred revenue attributed to deliveries under the Production Payment sold
in February 2001.

OTHER FACILITIES

Principal offices of the Company and its operating subsidiaries are leased
in modern office buildings in Houston, Texas and Tulsa, Oklahoma.

The Company believes that all of its property, plant and equipment are well
maintained, in good operating condition and suitable for the purposes for which
they are used.

ITEM 3. LEGAL PROCEEDINGS

Additional information regarding the litigation described above under
"Regulation -- Environmental Claims" and information with respect to other legal
proceedings is contained in Note 10 to the Consolidated Financial Statements.

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

No matter was submitted to a vote of security holders through the
solicitation of proxies or otherwise during the three months ended December 31,
2002.

13

PART II

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

The Company's common stock is traded on the New York Stock Exchange under
the symbol KCS. On March 12, 2003, there were approximately 1,116 stockholders
of record of the Company's common stock. This number does not include any
beneficial owners for whom shares of common stock may be held in "nominee" or
"street" name. The high and low sales prices for the common stock, as reported
in the consolidated transactions reporting system, for each quarterly period
during 2002 and 2001 are shown in the following table.

On March 12, 2003, the last reported sale price of the common stock on the
New York Stock Exchange was $2.62 per share.

DIVIDEND POLICY

No cash dividends on the Company's common stock were paid in 2002 or 2001.
KCS intends to retain earnings for use in the operation and expansion of its
business, and therefore does not anticipate declaring a cash dividend on its
common stock in the foreseeable future. KCS is currently restricted under its
credit facilities from paying cash dividends on the common stock to
stockholders. Any future determination to pay dividends on the common stock will
be at the discretion of the board of directors and will be dependent upon then
existing conditions, including the Company's financial condition, results of
operations, contractual restrictions, capital requirements, business prospects,
and such other factors as the board of directors deems relevant.

14

EQUITY COMPENSATION PLAN INFORMATION

The following table sets forth information as of December 31, 2002 with
respect to compensation plans under which equity securities of the Company are
authorized for issuance.

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

(1) Represents options granted under the KCS Energy, Inc. 2001 Employees and
Directors Stock Plan. In addition, as of December 31, 2002, grants of
579,528 restricted shares were outstanding.

(2) Includes 775,989 shares authorized for issuance pursuant to the Company's
employee stock purchase program and 809,326 shares authorized for issuance
in connection with the Company's savings and investment (401(k)) plan.

INFORMATION REGARDING EQUITY COMPENSATION PLANS THAT HAVE NOT BEEN APPROVED BY
STOCKHOLDERS

KCS Energy, Inc. 2001 Employees and Directors Stock Plan ("2001 Stock
Plan"). The 2001 Stock Plan was adopted as part of the Company's plan of
reorganization (the "Plan") under Chapter 11 of Title 11 of the United States
Bankruptcy Code. The Plan was approved by the Company's stockholders and
creditors; however, the stockholders did not consider and vote on the 2001 Stock
Plan independently of their consideration of the Plan. See Notes 2 and 4 to
Consolidated Financial Statements. The 2001 Stock Plan provides that stock
options, stock appreciation rights, restricted stock and bonus stock may be
granted to employees of KCS. The 2001 Stock Plan provides that each non-employee
director be granted stock options for 1,000 shares annually. The 2001 Stock Plan
also provides that in lieu of cash, each non-employee director be issued KCS
common stock with a fair market value equal to 50% of their annual retainer. The
2001 Stock Plan provides that the option price of shares issued be equal to the
market price on the date of grant. All options expire 10 years after the date of
grant. The 2001 Stock Plan provide for the issuance of up to 4,362,868 share of
KCS common stock.

Other Plans. Shortly after its formation in May 1988, the Company adopted,
among other benefit programs, an employee stock purchase plan and a savings and
investment plan. While the shareholders of KCS's former parent company did not
specifically vote to approve these plans, they did approve a plan authorizing
the spin-off and formation of KCS which included provisions stating the intent
to adopt benefit plans similar to those of the former parent.

Employee Stock Purchase Plan. Under the employee stock purchase plan,
eligible employees and directors may purchase full shares from the Company at a
price per share equal to 90% of the market value determined by the closing price
on the date of purchase. The maximum annual purchase is the number of shares
costing no more than 10% of the eligible employee's annual base salary, and for
directors, 6,000 shares.

Savings and Investment Plan. Under the savings and investment plan,
eligible employees may contribute a portion of their compensation, as defined,
to the savings plan, subject to certain IRS limitations. The Company may make
matching contributions, which have been set by the Board of Directors at 50% of
the employee's contribution (up to 6% of the employee's compensation, subject to
certain regulatory limitations).

15

The savings plan also contains a profit-sharing component whereby the Board of
Directors may declare annual discretionary profit-sharing contributions. The
Company's matching contributions and discretionary profit-sharing contributions
vest over a four-year employment period. Once the four-year employment period
has been satisfied, all Company matching contributions and discretionary
profit-sharing contributions vest immediately.

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth the Company's selected financial data for
each of the five years ended December 31, 2002.

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

(1) Includes a $15.9 million non-cash writedown to zero of the book value of net
deferred tax assets and a $6.2 million non-cash charge for the cumulative
effect of an accounting change related to the amortization method of oil and
gas properties.

(2) Includes $174.5 million after tax non-cash ceiling test writedowns of oil
and gas assets and a $113.9 million writedown of the book value of net
deferred tax assets. Together, these adjustments accounted for $288.4
million, or $9.80 per share, of the 1998 loss.

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

The following is a discussion and analysis of our financial condition and
results of operations and should be read in conjunction with the Consolidated
Financial Statements (including the notes thereto) included elsewhere in this
Form 10-K.

FORWARD-LOOKING STATEMENTS

The information discussed in this annual report on Form 10-K includes
"forward-looking statements" within the meaning of Section 27A of the Securities
Act of 1933, as amended (the "Securities Act"), and Section 21E of the Exchange
Act. All statements, other than statements of historical facts, included herein
concerning, among other things, planned capital expenditures, increases in oil
and gas production, the number of anticipated wells to be drilled after the date
hereof, the Company's financial position, business strategy and other plans and
objectives for future operations, are forward-looking statements. These
forward-looking statements are identified by their use of terms and phrases such
as "expect," "estimate," "project," "plan," "believe," "achievable,"
"anticipate" and similar terms and phrases. Although the Company believes that
the expectations reflected in such forward-looking statements are reasonable,
they do involve certain assumptions, risks and uncertainties, and the Company
can give no assurance that such expectations will prove to be

16

correct. The Company's actual results could differ materially from those
anticipated in these forward-looking statements as a result of certain factors,
including:

- the timing and success of the Company's drilling activities;

- the volatility of prices and supply and demand for oil and gas;

- the numerous uncertainties inherent in estimating quantities of oil and
gas reserves and actual future production rates and associated costs;

- the usual hazards associated with the oil and gas industry (including
blowouts, cratering, pipe failure, spills, explosions and other
unforeseen hazards);

- changes in regulatory requirements; or

- if underlying assumptions prove incorrect.

These and other risks are described in greater detail in "Oil and Gas Risk
Factors" included elsewhere in this Form 10-K.

All forward-looking statements attributable to the Company or persons
acting on its behalf are expressly qualified in their entirety by such factors.
Other than required under the securities laws, the Company does not assume a
duty to update these forward looking statements.

GENERAL

Our main objective in 2002 was to position the Company to meet our Senior
Note obligations due January 15, 2003. In order to meet this objective, we
curtailed our drilling and overall capital expenditure programs and sold certain
non-core assets. These actions positioned us to reduce debt and negotiate the
financing necessary to pay off the remaining portion of the maturing Senior
Notes during a difficult period in the capital markets. Although the asset sales
and curtailed drilling and capital expenditure programs resulted in lower
production and reserves in 2002, we exited the year in a stronger financial
position, with increased financial flexibility, a focused asset base in our core
areas, and a quality multi-year drilling prospect inventory.

On January 14, 2003, we completed the arrangements necessary to amend and
restate our existing credit agreement with a group of institutional lenders. The
amended facility provides $90.0 million of borrowing capacity, $40.0 million in
the form of a term loan and $50.0 million in revolving facilities, and matures
on October 3, 2005. Initial proceeds of $69.3 million were used primarily to pay
off the balance of the maturing Senior Note obligations, leaving $20.7 million
of available borrowing capacity under the facility.

Prices for oil and natural gas are subject to wide fluctuations in response
to relatively minor changes in the supply of and demand for oil and natural gas,
market uncertainty and a variety of additional factors that are beyond our
control. These factors include political conditions in the Middle East and
elsewhere, domestic and foreign supply of oil and natural gas, the level of
industrial and consumer demand, weather conditions and overall economic
conditions.

APPLICATION OF CRITICAL ACCOUNTING POLICIES

The discussion and analysis of our financial condition and results of
operations are based upon the consolidated financial statements, which have been
prepared in accordance with accounting principles generally accepted in the
United States. The preparation of these financial statements requires us to make
estimates and judgments that affect our financial position and results of
operations. Our significant accounting policies are described in Note 1 to
Consolidated Financial Statements contained elsewhere in this annual report on
Form 10-K. Certain of these accounting policies involve judgments and
uncertainties to such an extent that there is a reasonable likelihood that
materially different amounts could have been reported under different
conditions, or if different assumptions had been used. We discussed the
development, selection, and disclosure of each of these critical accounting
estimates with our audit committee. The following discussion details the more
significant accounting policies, estimates and judgments.

17

FULL COST METHOD OF ACCOUNTING FOR OIL AND GAS OPERATIONS

The accounting for our business is subject to accounting rules that are
unique to the oil and gas industry. There are two allowable methods of
accounting for oil and gas business activities, the successful efforts method
and the full cost method. We have elected to use the full cost method to account
for our investment in oil and gas properties. Under this method, the Company
capitalizes all acquisition, exploration and development costs into one cost
center. Such costs include lease acquisitions, geological and geophysical
services, drilling, equipment, and salaries, benefits and other internal costs
directly attributable to these activities. These costs are then amortized over
the remaining life of the aggregate oil and gas reserves using the
"unit-of-production" method of calculating depletion expense discussed below
under "Amortization of Oil and Gas Properties". The full cost method embraces
the concept that dry holes and other expenditures that fail to add reserves are
intrinsic to the oil and gas exploration business, and are therefore
capitalized. Although some of these costs will ultimately result in no
additional reserves, they are part of a program from which we expect the
benefits of successful wells to more than offset the costs of any unsuccessful
ones. As a result, we believe that the full cost method of accounting to be
appropriate and reflective of the economics of our programs for the acquisition,
exploration and development of oil and gas reserves. Under the successful
efforts method, costs of exploratory dry holes and geological and geophysical
exploration costs that would be capitalized under the full cost method would be
charged against earnings during the periods in which the occur. Accordingly, our
financial position and results of operations may have been significantly
different had we used the successful efforts method of accounting for our oil
and gas investments.

OIL AND GAS RESERVE ESTIMATES

Estimates of our proved oil and gas reserves are based on the quantities of
oil and gas which geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known reservoirs under
existing economic and operating conditions. The accuracy of any oil and gas
reserve estimate is a function of the quality of available data, engineering and
geological interpretation, and judgment. For example, we must estimate the
amount and timing of future operating costs, severance taxes, development costs,
and workover costs, all of which may in fact vary considerably from actual
results. In addition, as prices and cost levels change from year to year, the
estimate of proved reserves also change. Any significant variance in these
assumptions could materially affect the estimated quantity and value of our
reserves.

Despite the inherent imprecision in these engineering estimates, estimates
of our oil and gas reserves are used throughout our financial statements. For
example, since we use the unit-of-production method, the amortization rate of
our capitalized oil and gas properties incorporates the estimated
units-of-production attributable to the estimates of proved reserves. Our oil
and gas properties are also subject to a "ceiling" limitation based in part on
the quantity of our proved reserves. See Note 1 to Consolidated Financial
Statements. Finally, these reserves are the basis for our supplemental oil and
gas disclosures.

The estimates of our proved oil and gas reserves have been prepared or
audited by NSA, independent petroleum engineers.

AMORTIZATION OF OIL AND GAS PROPERTIES

Effective January 1, 2002, KCS began amortizing the capitalized costs
related to oil and gas properties under the unit-of-production basis ("UOP")
method using proved oil and gas reserves. See Note 1 to Consolidated Financial
Statements. Under the UOP method, the amortization rate is computed based on the
portion of our reserves produced, including reserves and production associated
with the Production Payment. This rate is applied to the amortizable base of our
oil and gas properties (the net book value of oil and gas properties less the
costs of unevaluated oil and gas properties plus estimated future costs to
develop the oil and gas properties). The calculation of DD&A requires the use of
significant estimates pertaining to oil and gas reserves and future development
costs.

18

BAD DEBT EXPENSE

We routinely assess the recoverability of all material trade and other
receivables to determine their collectibility. Many of our receivables are from
joint interest owners on properties we operate. Thus, we may have the ability to
withhold future revenue disbursements to recover any non-payment of joint
interest billings. The Company markets the majority of its production and these
receivables are generally collected within a month. The receivables for the
remaining production is typically collected within two months. We accrue a
reserve for a receivable when, based on the judgment of management, it is
probable that such receivable will not be collected in full and the amount of
any reserve required can be reasonably estimated.

REVENUE RECOGNITION

Gas imbalances can arise on properties for which two or more owners have
the right to take production "in-kind." In a typical gas balancing arrangement,
each owner is entitled to an agreed-upon percentage of the property's total
production. However, at any given time, the amount of gas sold by each owner may
differ from its allowable percentage. Two principal accounting practices have
evolved to account for gas imbalances. These methods differ as to whether
revenue is recognized based on the actual sale of gas (sales method) or an
owner's entitled share of the current period's production (entitlement method).
We have elected to use the sales method. Under this method, a liability is
recognized for an imbalance only when the estimated remaining reserves will not
be sufficient to enable the under produced owner to recoup its entitled share
through future production. Had we used the entitlement method, our reported
revenues could have been materially different.

INCOME TAXES

We record deferred tax assets and liabilities to account for the expected
future tax consequences of events that have been recognized in our financial
statements and our tax returns. We routinely assess the realizability of our
deferred tax assets. Numerous judgments and assumptions are inherent in the
estimation of future taxable income, including assumptions with respect to our
future operating results (particularly as related to volatile oil and gas
prices). Such judgments and assumptions are inherently imprecise and may prove
to be materially incorrect in the future.

ASSET RETIREMENT OBLIGATIONS

We have significant obligations to remove equipment and restore land at the
end of oil and gas production operations. Our removal and restoration
obligations are primarily associated with plugging and abandoning wells. The
estimated undiscounted costs, net of equipment salvage value, of dismantling and
removing these facilities are accrued over the production life of the oil and
gas property as additional DD&A. Estimating the future asset removal costs is
difficult and requires management to make estimates and judgments because most
of the removal obligations are many years in the future and because contracts
and regulations often have vague descriptions of what constitutes removal. Asset
removal technologies and costs are constantly changing, as are political,
environmental, safety and public relations considerations. In addition, the
Financial Accounting Standards Board (FASB) has recently issued SFAS No. 143,
"Accounting for Asset Retirement Obligations," (SFAS No. 143), which
significantly changes the method of accruing for costs, associated with the
retirement of fixed assets, that an entity is legally obligated to incur.

SFAS No. 143 requires us to record the fair value of a liability for legal
obligations associated with the retirement obligations of tangible long-lived
assets in the periods in which it is incurred. When the liability is initially
recorded, we increase the carrying amount of the related long-lived asset. The
liability is accreted to the fair value at the time of settlement over the
useful life of the asset, and the capitalized cost is depreciated over the
useful life of the related asset. We adopted SFAS No. 143 effective on January
1, 2003. As a result, net property, plant and equipment was increased by $10.2
million, an asset retirement obligation of $11.1 million was recorded and a $0.9
million charge against net income will be reported in the first quarter of 2003
as a cumulative effect of a change in accounting principle.

19

DERIVATIVES

We use commodity derivative contracts on a limited basis to manage our
exposure to oil and gas price volatility. KCS accounts for its commodity
derivative contracts in accordance with SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS No. 133). Realized gains and losses
from our cash flow hedges, including terminated contracts, are generally
recognized in oil and gas production revenue when the hedged volumes are
produced and sold. We do not enter into derivative or other financial
instruments for trading purposes.

RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000

RESULTS OF OPERATIONS

Income before income taxes for 2002 was $9.8 million compared to $57.2
million in 2001. Dramatically lower natural gas prices, lower non-oil and gas
revenue and lower production were partially offset by significantly lower
operating, reorganization and interest expenses. Income tax expense for 2002 was
$13.8 million compared to an income tax benefit of $8.4 million in 2001. As a
result of the non-cash income tax expense in 2002 (see Note 8 to Consolidated
Financial Statements), we reported a net loss before cumulative effect of
accounting change of $3.9 million, or $0.14 per basic and diluted share. The
cumulative effect of accounting change related to the amortization method for
oil and gas properties was a $6.2 million loss, or $0.17 per basic and diluted
share. Net loss in 2002 was $10.1 million, or $0.31 per basic and diluted share
compared to net income of $65.6 million, or $2.02 per basic share ($1.69 per
diluted share) in 2001.

Net income for 2001 was $65.6 million, or $2.02 per basic share ($1.69 per
diluted share), compared to $41.5 million, or $1.42 per basic and diluted share
in 2000. This increase was attributable to higher average realized natural gas
prices, increased working interest production, higher other revenue and lower
interest expense partially offset by lower production from the VPP program,
lower oil prices and higher operating expenses. Reorganization items in 2001
were $2.9 million compared to $15.4 million in 2000.

REVENUE

20

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

(a) Production includes 11,196 Mmcfe and 15,716 Mmcfe in 2002 and 2001,
respectively, dedicated to the Production Payment sold in February 2001.
See Notes 1 and 2 to Consolidated Financial Statements.

(b) Includes the effects of hedging and, in 2002 and 2001, amortization of
deferred revenue attributed to deliveries under the Production Payment sold
in February 2001. See Note 1 to Consolidated Financial Statements.

Gas Revenue. In 2002, gas revenue was $96.5 million compared to $143.9
million in 2001 as a result of a 17% decrease in realized natural gas prices and
a 20% decline in production. The production decline was primarily due to the
sale of oil and gas properties, expiration of certain VPP's and no additional
investment in the VPP program in 2000 or 2001 due to limited capital
availability. Furthermore, the natural decline of producing properties was not
fully offset by new production largely due to the reduction in the capital
investment program. See "Liquidity and Capital Resources".

In 2001, gas revenue was $143.9 million compared to $151.3 million in 2000.
Higher natural gas prices during the first half of the year and a 9% increase in
working interest production were offset by a 7.4 Bcf decrease in scheduled
production from the VPP program and the dramatic decline in natural gas prices
during the second half of 2001. Average realized gas prices during the first
half of 2001 were $4.55 per Mcf compared to $3.19 during the second half of the
year. The decrease in VPP production reflects the expiration of certain VPPs,
limited investment in the program since 1999 and no investment in 2001.

Oil and Liquids Revenue. In 2002, oil and liquids revenue decreased $7.1
million to $23.5 million primarily due to a 19% decrease in production. The
decrease in production in 2002 was attributable to the sale of oil and gas
properties and the natural declines of producing properties.

In 2001, oil and liquids revenue decreased $8.7 million to $30.6 million
primarily due to a 24% decrease in average realized oil prices.

Other Revenue, net. Other revenue, net decreased from $17.6 million in
2001 to a net cost of $1.2 million in 2002. Of the $17.6 million in 2001, $9.3
million was from the sale of emission reduction credits and $7.7 million was
from non-cash gains on derivative instruments that were not designated as oil
and gas hedges when we adopted SFAS No. 133 (see Note 9 to Consolidated
Financial Statements), and the remainder was primarily attributable to marketing
and transportation revenue incidental to our oil and gas operations. In 2002,
the net cost of $1.2 million was primarily attributable to gas marketing and
transportation activities.

In 2000, other revenue, net included $1.0 million from the settlement of
certain claims related to a 1996 acquisition and $0.7 million from the sale of
emission reduction credits.

LEASE OPERATING EXPENSES

For the year ended December 31, 2002, lease operating expenses decreased
17% to $25.2 million, compared to $30.5 million in 2001. Increased focus on cost
reductions and operating efficiency along with the sale of certain properties
contributed to the reductions.

For the year ended December 31, 2001, lease operating expenses increased
10% to $30.5 million, compared to $27.8 million in 2000. The increased costs in
2001 reflect start-up costs associated with our Hartland gas processing plant in
Michigan incurred during the first quarter of the year, higher ad valorem taxes,
higher working interest production, and increased costs of workovers on oil and
gas wells in order to maximize production during the first half of 2001 when
natural gas prices were high.

PRODUCTION TAXES

Production taxes, which are generally based on a percentage of revenue
(excluding revenue from the VPP program), decreased $2.6 million to $5.6 million
in 2002 compared to $8.2 million in 2001 due to lower oil and gas revenue
associated with the decrease in working interest production and lower average
realized prices.

21

Production taxes increased $1.6 million to $8.2 million in 2001, compared
to $6.6 million in 2000 due to higher average natural gas prices and the
increase in working interest production.

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative expenses decreased $0.6 million to $8.3 million
in 2002, compared to $8.9 million in 2001 as a result of lower labor cost
associated with a reduced work force, partially offset by an increase in
insurance premiums and employment severance payments.

General and administrative expenses were $8.9 million in 2001, which
included approximately $1.4 million of costs associated with the retention bonus
program for employees other than senior management that was put in place in
October 2000 in order for us to retain our employees during the reorganization
process. Excluding the effect of the retention bonus program, G&A in 2001
decreased 6% compared to 2000 as a result of lower salaries and wages due to a
reduced workforce.

STOCK COMPENSATION

Stock compensation was $0.8 million in 2002 compared to $1.4 million in
2001. These amounts reflect the non-cash amortization of restricted stock grants
issued to our employees under the 2001 Stock Plan. The 2001 expense includes
incremental costs associated with initial grants made upon our emergence from
Chapter 11 to compensate for a portion of stock options previously issued but
cancelled in connection with the plan of reorganization.

BAD DEBT EXPENSE

We routinely assess the collectibility of our trade and other receivables.
Bad debt expense was $0.2 million in 2002, which represents an allowance against
certain joint interest receivables, the collection of which has been determined
to be doubtful.

Bad debt expense was $4.1 million in 2001, primarily with respect to an
allowance against receivables due from Enron entities, which are now in
bankruptcy, for oil and gas sales and derivative instruments. We ceased all
sales to Enron entities after November 2001. See Note 9 to Consolidated
Financial Statements for information with respect to derivative contracts that
we had with Enron entities.

DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A)

Effective January 1, 2002, we began amortizing our oil and gas properties
using the UOP method based on proved reserves. See Note 1 to Consolidated
Financial Statements. This change resulted in additional amortization of $6.2
million through December 31, 2001, which is classified as a cumulative effect of
accounting change, net of tax, in 2002. For the year ended December 31, 2002,
DD&A decreased $9.1 million to $49.3 million. The decrease reflects reduced
production and a lower depletable base.

For the year ended December 31, 2001, DD&A increased $7.9 million to $58.3
million, reflecting an increase in the DD&A rate largely due to the dramatic
decline in natural gas prices during the second half of 2001 and a higher
depletable base.

INTEREST AND OTHER INCOME

Interest and other income was $0.3 million in 2002 compared to $1.3 million
in 2001 and $0.1 million in 2000. These amounts primarily represent interest
income earned on accumulated cash and cash equivalents. In 2000, we also
reported $1.0 million of interest income associated with accumulated cash and
cash equivalents as a component of "Reorganization items" pursuant to SOP 90-7.

INTEREST EXPENSE

Interest expense was $19.9 million in 2002 compared to $21.8 million in
2001 and $41.5 million in 2000. The lower interest expense in 2002 reflects the
trend of lowering outstanding debt and, to a lesser extent, lower

22

interest rates on our credit facility, partially offset by a $1.1 million write
off of deferred financing costs in December 2002 (See Note 5 to Consolidated
Financial Statements). Interest expense in 2000 includes $4.2 million of
interest on past due interest with respect to our Senior Notes and Senior
Subordinated Notes in accordance with our plan of reorganization.

REORGANIZATION ITEMS

We completed our reorganization in 2001 and consequently there were no
reorganization items in 2002. For the year ended December 31, 2001, we recorded
$2.9 million of reorganization items, primarily for legal and financial advisory
services in connection with the completed Chapter 11 proceedings.

During 2000, we recorded $15.4 million of net reorganization items, $6.1
million of which was a non-cash write-off of deferred debt issuance costs
associated with the Senior Notes and Senior Subordinated Notes in accordance
with Statement of Position 90-7. The balance reflects restructuring costs of
$10.3 million, primarily for legal and financial advisory services. During 2000,
we earned interest income of $1.0 million on cash accumulated during the Chapter
11 proceedings, which partially offset the foregoing charges.

INCOME TAXES

Income tax expense in 2002 was $13.8 million resulting from a $15.9 million
non-cash increase in our valuation allowance against net deferred tax assets at
June 30, 2002, partially offset by a $2.1 million non-cash tax benefit (decrease
in the valuation allowance) primarily associated with certain derivative
instruments initially accounted for as a component of the cumulative effect of a
change in accounting principle upon adoption of SFAS No. 133. As discussed in
Note 8 to Consolidated Financial Statements, we routinely assess the valuation
allowance against net deferred tax assets. During the second quarter of 2002, we
concluded that the $15.9 million increase in the valuation allowance, which
reduced the carrying value of net deferred assets to zero, was appropriate. In
making that assessment, we considered several factors, including future
projections of taxable income, which reflected relatively low natural gas and
oil prices at that time, and the January 2003 maturity of our Senior Note
obligations that required refinancing. While the Senior Note obligations have
now been refinanced and natural gas and oil prices have improved significantly
in recent months, we continue maintain the valuation allowance against 100% of
our net deferred tax assets. We made this determination since, at this time, it
is difficult to project the necessary levels of future taxable income with
sufficient certainty, considering the significant volatility in natural gas and
oil prices and that the current higher price environment has existed for only a
short period. We will continue to assess the necessity for the valuation
allowance, and to the extent it is determined that such allowance is no longer
required, the tax benefit of the remaining net deferred tax assets will be
recognized in the future.

In connection with the adoption of SFAS No. 133 on January 1, 2001, we
recorded a liability of $43.8 million representing the fair market value of our
derivative instruments upon adoption and an after-tax charge to other
comprehensive income of $28.5 million from the cumulative effect of a change in
accounting principle. During 2001, we reclassified $23.9 million of the
liability as a non-cash reduction to oil and gas revenues and reduced the
valuation allowance related primarily to net operating losses, for a related tax
benefit of $8.4 million.

No income taxes were recorded in 2000 related to pre-tax book income as a
portion of the valuation allowance account established in 1998 was reversed due
to our assessment of our ability to utilize net operating loss carryforwards.
See Note 8 to Consolidated Financial Statements.

LIQUIDITY AND CAPITAL RESOURCES

Our main objective in 2002 was to position the Company to meet our Senior
Note obligations due January 15, 2003. In order to meet this objective, we
curtailed our drilling and overall capital expenditure programs and sold certain
non-core assets. These actions positioned us to reduce debt and negotiate the
financing necessary to pay off the remaining portion of the maturing Senior
Notes during a difficult period in the capital markets. Although the asset sales
and curtailed drilling and capital expenditure programs resulted

23

in lower production and reserves in 2002, we exited the year in a stronger
financial position, with increased financial flexibility, a focused asset base
in our core areas, and a quality multi-year drilling prospect inventory.

On January 14, 2003, we completed the arrangements necessary to amend and
restate our existing credit agreement ("Credit Agreement") with a group of
institutional lenders. Initial proceeds of $69.3 million were used primarily to
pay off the balance of the maturing Senior Note obligations, leaving $20.7
million of available borrowing capacity under the facility.

We reduced lifting costs (lease operating expenses and production taxes) by
20% and general and administrative expenses by 7% in 2002 and expect further
reductions in 2003. With the completion of the financing and the implementation
of this cost reduction program, we believe that we are well positioned to
capitalize on the strong natural gas price environment and to focus on
developing our prospect inventory to grow reserves and production in our core
areas.

We have reduced debt from a peak of $425.0 million in early 1999 to $194.3
million on January 15, 2003 and are committed to further debt reduction.

CASH FLOW FROM OPERATING ACTIVITIES

Net cash provided by operating activities for 2002 was $20.1 million
compared to $183.4 million in 2001. The 2001 cash provided by operating
activities was significantly impacted by the execution of the Plan of
reorganization which included net proceeds of $175.0 million from the Production
Payment sold in February 2001 (see Notes 1 and 2 to Consolidated Financial
Statements), the payment of $71.5 million of interest expense ($49.1 million of
which pertained to prior years) and the $28.0 million cost of terminating
certain derivative instruments in connection with the emergence from Chapter 11.
The 2002 cash provided by operating activities was negatively impacted by lower
realized natural gas prices and lower production as discussed above.

Net cash provided by operating activities was $183.4 million in 2001
compared to $128.0 million in 2000. In addition to the impact of the execution
of the Plan of reorganization, 2001 was favorably impacted by higher natural gas
prices and higher other revenue. In 2000, the net increase in accounts payable
and accrued liabilities, inclusive of accrued interest was primarily due to the
suspension of interest payments on the Senior Notes and Senior Subordinated
Notes during the period of reorganization and to accrued restructuring costs.

INVESTING ACTIVITIES

Capital expenditures for the year ended December 31, 2002 were $47.5
million, of which, $30.3 million was for development activities, $4.8 million
for the acquisition of proved reserves and $12.4 million for lease acquisitions,
seismic surveys and exploratory drilling.

Capital expenditures for the year ended December 31, 2001 were $87.2
million, of which $42.9 million was for development activities, $26.8 million
for the acquisition of proved reserves, $15.3 million for lease acquisitions,
seismic surveys and exploratory drilling and $2.2 million for other assets.

Capital expenditures for the year ended December 31, 2000 were $69.1
million of which $36.0 million was for development activities, $7.3 million for
the acquisition of proved reserves and $19.3 million for lease acquisitions,
seismic surveys and exploratory drilling. Other capital expenditures were $6.5
million, of which $6.2 million was for the construction of a gas processing
facility.

Capital spending for 2003 has initially been budgeted at $50 million. The
2003 capital program is expected to be funded with internally generated cash.

CREDIT FACILITIES

The Credit Agreement, which matures on October 3, 2005, provides up to
$90.0 million of borrowing capacity, $40.0 million in the form of a term loan, a
$30.0 million revolving "A" facility and a $20.0 million revolving "B" facility.
Borrowing capacity is subject to monthly borrowing base calculations with
respect to the value of certain of the Company's oil and gas assets. Initial
proceeds of $69.3 million were used primarily
24

to pay off the Company's maturing Senior Note obligations. The term loan and the
revolving "B" facility, which may be prepaid at any time without penalty, bear
interest based on the prime rate, initially equating to 9.0%, and increasing
annually. The revolving "A" facility bears, at the Company's option, an interest
rate of LIBOR plus 2.75% to 3.0% or prime plus 0.5% to 0.75%, depending on
utilization. The revolving "A" facility requires a commitment fee of 0.5% per
annum on the unused availability and carries an early termination penalty of
1.5% in the first year and 1% in the second year. Financing fees associated with
the amended and restated agreement have been recorded as deferred charges and
are being amortized as interest expense over the life of the Credit Agreement.
The remaining deferred financing fees associated with the original agreement
were written off to interest expense in December 2002. Certain other fees are
also payable under the Credit Facility based on services provided. Substantially
all of the Company's assets are pledged to secure the Credit Agreement.

The Credit Agreement contains various restrictive covenants including
ratios of debt to EBITDA, interest coverage, fixed charge coverage and
liquidity. The Credit Agreement also contains provisions that require the
hedging of a portion of the Company's oil and gas production, payment upon a
change of control, restrictions on the payment of dividends and certain other
restricted payments and places limitations on the incurrence of additional debt,
capital expenditures, the sale of assets, and the repurchase of Senior
Subordinated Notes. Any repayment made on the term loan portion of the facility
will permanently reduce the funds available under the Credit Agreement.

CONTRACTUAL CASH OBLIGATIONS

The following table quantifies our future contractual obligations as of
December 31, 2002.

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

(a) Subsequent to December 31, 2002, $3,750,000 of convertible preferred stock
was exchanged for our common stock. The preferred stock is redeemable at
our option if the closing price of the common stock exceeds $6.00 per share
for 25 out of 30 consecutive trading days or at the election of holders of
a majority of the outstanding shares of the preferred stock on or after
January 31, 2009. See Notes 5, 6 and 7 to Consolidated Financial
Statements.

OTHER COMMERCIAL COMMITMENTS

In connection with the Production Payment discussed in Notes 1 and 2 to the
Consolidated Financial Statement, we have obligations to deliver 6.8 Bcfe in
2003, 5.2 Bcfe in 2004, 3.9 Bcfe in 2005 and 0.3 Bcfe in 2006. At December 31,
2002, we had $2.4 million of surety bonds that remain outstanding until specific
events or projects are completed and claims are settled. In February 2003, a one
year $2.0 million standby letter of credit was issued under the Credit Agreement
in support of our hedging program.

NEW ACCOUNTING PRINCIPLES

In July 2001, the FASB issued Statement of Financial Accounting Standard
("SFAS No. 143"), "Accounting for Asset Retirement Obligations". SFAS No. 143
requires entities to record the fair value of a liability for legal obligations
associated with the retirement obligations of tangible long-lived assets in the
periods in which it is incurred. When the liability is initially recorded, the
entity increases the carrying amount
25

of the related long-lived asset. The liability is accreted to the fair value at
the time of settlement over the useful life of the asset, and the capitalized
cost is depreciated over the useful life of the related asset. The Company
adopted SFAS No. 143 effective on January 1, 2003. As a result, property, plant
and equipment was increased by $10.2 million, an additional asset retirement
obligation of $11.1 million was recorded and a $0.9 million charge against net
income will be reported in the first quarter of 2003 as a cumulative effect of a
change in accounting principle.

In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" ("SFAS No. 144"). SFAS No. 144
addresses the financial accounting and reporting for the impairment or disposal
of long-lived assets. SFAS No. 144 supersedes SFAS No. 121 but retains its
fundamental provisions for the (a) recognition/measurement of impairment of
long-lived assets to be held and used and (b) measurement of long-lived assets
to be disposed of by sale. SFAS No. 144 also supersedes the accounting/reporting
provisions of APB Opinion No. 30 for segments of a business to be disposed of
but retains the requirement to report discontinued operations separately from
continuing operations and extends that reporting to a component of an entity
that either has been disposed of or is classified as held for sale. The Company
adopted the provisions of SFAS No. 144 effective January 1, 2002, with no
significant impact.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Derivative Instruments. The Company's major market risk exposure is to oil
and gas prices, which have historically been volatile. Realized prices are
primarily driven by the prevailing worldwide price for crude oil and regional
spot prices for natural gas production. The Company has utilized, and may
continue to utilize, derivative contracts, including swaps, futures contracts,
options and collars to manage this price risk. The Company does not enter into
derivative or other financial instruments for speculative purposes. Effective
January 1, 2001, the Company adopted SFAS No. 133. See Note 9 to Consolidated
Financial Statements. While these derivative contracts are structured to reduce
the Company's exposure to decreases in the price associated with the underlying
commodity, they also limit the benefit the Company might otherwise receive from
any price increases.

At December 31, 2002, the Company had no outstanding derivative financial
instruments. During February 2003, the Company invested $0.6 million in a series
of derivative transactions covering 3.5 million MMbtu of gas production for
April through November 2003. These instruments establish an average floor

26

price of $4.51 and enable the Company to receive market prices up to an average
cap of $5.78, approximately 26% of any price realized between $5.78 and $6.28
and 100% of any price realized above $6.28.

In addition to the above, the Company has entered into fixed price sales
contracts covering 0.7 million MMbtu at an average price of $5.08 for February
through June 2003 and will deliver 6.8 Bcfe in 2003 under the Production Payment
sold in February 2001 at an average price of $4.05 per Mcfe as described in
Notes 1 and 2 to Consolidated Financial Statements.

For 2002, the Company delivered approximately 30% of its production under
the Production Payment sold in February 2001 at an average realized price of
$4.05 per Mcfe and also entered into derivative arrangements designed to reduce
price downside risk for approximately 17% of the balance of its production. For
the year 2001, the Company delivered approximately 34% of its production under
the Production Payment and also entered into derivative contracts which covered
approximately 30% of the balance of its production.

Interest Rate Risk. The Company uses fixed and variable rate long-term
debt to finance its capital spending program and for general corporate purposes.
These variable rate debt instruments expose the Company to market risk related
to changes in interest rates. The Company's fixed rate debt and the associated
weighted average interest rate was $186.3 million at 9.6% on December 31, 2002
and $204.8 million at 9.7% on December 31, 2001. The Company's variable rate
debt and weighted average interest rate was $0.5 million at 5.3% on December 31,
2002. The Company had no variable rate debt on December 31, 2001. The table
below presents principal cash flows and related average interest rates by
expected maturity dates for the Company's debt obligations at December 31, 2002.
The fixed rate debt due in 2003 was replaced with variable rate debt on January
14, 2003. See Note 5 to Consolidated Financial Statements.

27

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT PUBLIC AUDITORS

To the Board of Directors and Stockholders of KCS Energy, Inc.:

We have audited the accompanying consolidated balance sheet of KCS Energy,
Inc. and subsidiaries as of December 31, 2002 and the related consolidated
statements of operations, stockholders' deficit, and cash flows for the year
then ended. These consolidated financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audit. The consolidated financial statements
of KCS Energy, Inc. and subsidiaries as of December 31, 2001, and for each of
the two years in the period then ended, were audited by other auditors who have
ceased operations. Those auditors expressed an unqualified opinion on those
financial statements in their report dated March 13, 2002. Their report,
however, had an explanatory paragraph indicating that the Company changed its
method of accounting for derivative instruments and hedging activities,
effective January 1, 2001, to conform with Statement of Financial Accounting
Standard No. 133, "Accounting for Derivative Instruments and Hedging
Activities."

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

In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of KCS Energy,
Inc. and subsidiaries as of December 31, 2002 and the consolidated results of
their operations and their cash flows for the year ended December 31, 2002 in
conformity with accounting principles generally accepted in the United States.

As discussed above, the consolidated financial statements of KCS Energy,
Inc. and subsidiaries as of December 31, 2001, and for each of the two years in
the period then ended, were audited by other auditors who have ceased
operations. As described in Note 1, effective January 1, 2002, the Company
changed their method of accounting for the amortization of its oil and gas
properties. These financial statements have been revised to reflect the pro
forma effect on income available to common stockholders and earnings per share
as if the Company had applied the new amortization method to its oil and gas
properties during 2001 and 2000. Our audit procedures with respect to these
adjustments in Note 1 for 2001 and 2000 included (a) agreeing the previously
reported income available to common stockholders and basic and diluted earnings
per share to the previously issued financial statements, (b) agreeing the
adjustments to reported income available to common stockholders, representing
changes in the amortization method, to the Company's underlying records obtained
from management, and (c) testing the mathematical accuracy of the reconciliation
of adjusted income available to common stockholders and the related per-share
amounts. In our opinion, such adjustments are appropriate and have been properly
applied. However, we were not engaged to audit, review, or apply any procedures
to the 2001 and 2000 consolidated financial statements of KCS Energy, Inc. and
subsidiaries other than with respect to such adjustments and, accordingly, we
do not express an opinion or any other form of assurance on the 2001 and 2000
consolidated financial statements taken as a whole.

/s/ ERNST & YOUNG LLP

Houston, Texas
March 27, 2003

28

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To KCS Energy, Inc.:

We have audited the accompanying consolidated balance sheets of KCS Energy,
Inc. (a Delaware Corporation) and subsidiaries as of December 31, 2001 and 2000,
and the related statements of consolidated operations, stockholders' (deficit)
equity and cash flows for each of the three years in the period ended December
31, 2001. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of KCS Energy,
Inc. and subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001 in conformity with accounting principles generally accepted in
the United States.

As explained in Note 9 to the consolidated financial statements, effective
January 1, 2001, the Company changed its method of accounting for derivative
instruments and hedging activities to conform with Statement of Financial
Accounting Standard No. 133, "Accounting for Derivative Instruments and Hedging
Activities."

/s/ ARTHUR ANDERSEN LLP

Houston, Texas
March 13, 2002

THIS IS A COPY OF AN ACCOUNTANTS' REPORT PREVIOUSLY ISSUED BY ARTHUR
ANDERSEN LLP, THE COMPANY'S FORMER INDEPENDENT PUBLIC ACCOUNTANTS, IN CONNECTION
WITH THE COMPANY'S FORM 10-K FILED APRIL 1, 2002, AND HAS NOT BEEN REISSUED BY
ARTHUR ANDERSEN SINCE THAT DATE. SEE EXHIBIT 23(ii) FOR FURTHER INFORMATION. THE
COMPANY IS INCLUDING THIS COPY OF THE ARTHUR ANDERSEN LLP AUDIT REPORT PURSUANT
TO RULE 2-02(e) OF REGULATION S-X UNDER THE SECURITIES ACT OF 1933, AS AMENDED.
29

KCS ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED OPERATIONS

The accompanying notes are an integral part of these financial statements.
30

KCS ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

The accompanying notes are an integral part of these financial statements.
31

KCS ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED STOCKHOLDERS' DEFICIT

The accompanying notes are an integral part of these financial statements.
32

KCS ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

The accompanying notes are an integral part of these financial statements.
33

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

KCS Energy, Inc. is an independent oil and gas company engaged in the
acquisition, exploration and production of natural gas and crude oil with
operations predominately in the Mid-Continent and Gulf Coast regions.

BASIS OF PRESENTATION

The consolidated financial statements include the accounts of KCS Energy,
Inc. and its wholly owned subsidiaries ("KCS" or "Company"). All significant
intercompany accounts and transactions have been eliminated in consolidation.
Certain previously reported amounts have been reclassified to conform to current
year presentation.

The preparation of financial statements in conformity with generally
accepted accounting principles in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
During 2000 and until the Plan was effective (see Note 2), the Company conducted
its business and reported its results of operations and financial position as a
debtor-in-possession pursuant to Statement of Position 90-7. In connection
therewith, the Company reported all liabilities deemed subject to compromise at
amounts reasonably expected to be paid.

CASH EQUIVALENTS

The Company considers as cash equivalents all highly liquid investments
with a maturity of three months or less from date of purchase.

DERIVATIVE INSTRUMENTS

Oil and gas prices have historically been volatile. The Company has entered
and may continue to enter into derivative contracts to manage the risk
associated with the price fluctuations affecting it by effectively fixing the
price of certain sales volumes for certain time periods. Through December 31,
2000, the Company accounted for such contracts in accordance with Statement of
Financial Accounting Standard ("SFAS") No. 80 "Accounting for Futures
Contracts". These contracts permitted settlement by delivery of commodities and,
therefore, were not financial instruments as defined by SFAS Nos. 107 and 119.
Changes in the market value of these transactions were deferred until the sale
of the underlying production was recognized.

Effective January 1, 2001, the Company adopted SFAS No. 133 "Accounting for
Derivative Instruments and Hedging Activities." SFAS No. 133, as amended,
establishes accounting and disclosure standards requiring that all derivative
instruments be recorded in the balance sheet as an asset or liability, measured
at fair value. It further requires that changes in a derivative instrument's
fair value be recognized currently in earnings unless specific hedge accounting
criteria are met. To qualify as a hedge, these transactions must be formally
documented and designated as a hedge and the changes in their fair value must
correlate with changes in the expected cash flow from anticipated future sales
of production. Changes in the market value of these cash flow hedges are
deferred through other comprehensive income ("OCI") until such time as the
hedged volumes are produced and sold. Hedge effectiveness is measured at least
quarterly based on relative changes in fair value between the derivative
contract and the hedged item over time. Any ineffectiveness is immediately
reported in other revenue in the Statements of Consolidated Operations. If the
likelihood of occurrence of a hedged transaction ceases to be "probable", hedge
accounting will cease on a prospective basis and all future changes in
derivative fair value will be recognized currently in earnings. The net gain or
loss from hedges terminated prior to maturity continue to be deferred until the
hedged production is recognized in income. If it becomes probable that the
hedged transaction will not occur, the derivative gain or loss associated

34

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

with a terminated derivative will immediately be reclassified from OCI into
earnings. If the contract is not designated as a hedge, changes in fair value
are recorded currently in income.

See Note 9 for further discussion of the Company's price risk management
activities.

FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying value of certain financial instruments, including cash, cash
equivalents, revolving credit debt and short-term debt approximates estimated
fair value due to their short-term maturities and varying interest rates. The
estimated fair value of public debt is based upon quoted market values.
Derivative financial instruments are carried at fair value.

PROPERTY, PLANT AND EQUIPMENT

The Company follows the full cost method of accounting under which all
costs incurred in acquisition, exploration and development activities are
capitalized in a country-wide cost center. Such costs include lease
acquisitions, geological and geophysical services, drilling, completion,
equipment and certain salaries, benefits and other internal costs directly
associated with acquisition, exploration and development activities. Interest
costs related to unproved properties are also capitalized. Salaries, benefits
and other internal costs related to production and general overhead are expensed
as incurred. Effective January 1, 2002, the Company began providing for
depreciation, depletion and amortization ("DD&A") of evaluated costs using the
unit-of-production method based on recoverable reserves (including reserves
associated with the Production Payment). See "New Accounting Principles". Future
development costs and asset retirement obligations are added to the amortizable
base. Costs directly associated with the acquisition and evaluation of unproved
properties are excluded from the DD&A calculation until a complete evaluation is
made and it is determined whether proved reserves can be assigned to the
properties or if impairment has occurred. The costs of drilling exploratory dry
holes are included in the amortization base immediately upon determination that
such wells are dry. Geological and geophysical costs not associated with
specific unevaluated properties are included in the amortization base as
incurred. Costs of unevaluated properties excluded from amortization were $3.4
million and $8.5 million at December 31, 2002 and 2001, respectively. The
Company will begin to amortize these costs when proved reserves are established
or impairment is determined.

Capitalized costs of oil and gas properties, net of accumulated DD&A and
related deferred taxes, are limited to the sum of the present value of estimated
future net revenues from proved oil and gas reserves at current prices net of
related tax effects discounted at 10%, plus the lower of cost or fair value of
unproved properties. To the extent that the capitalized costs exceed this
"ceiling" limitation at the end of any quarter, such excess is expensed.

During 2002, the Company sold certain non-core oil and gas properties for
net proceeds of $30.5 million. Proceeds from dispositions of oil and gas
properties are credited to the cost center with no recognition of gains or
losses unless a significant portion of the Company's proved reserves are sold
(generally more than 25%).

Depreciation of other property, plant and equipment is provided on a
straight-line basis over the estimated useful lives of the assets ranging from 3
to 20 years. Repairs of all property, plant and equipment and replacements and
renewals of minor items of property are charged to expense as incurred.

REVENUE RECOGNITION

The Company follows the sales method of accounting for natural gas revenues
whereby revenues are recognized based on volume sold. The volume of gas sold may
differ from the volume to which KCS is entitled based on its working interest.
An imbalance is recognized as a liability only when the estimated remaining
reserves will not be sufficient to enable the under-produced owner(s) to recoup
its entitled share through future production. The Company has a liability of
$0.7 million for imbalances at December 31 for 2002 and
35

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

2001. Under the sales method, no receivables are recorded where KCS has taken
less than its share of production. Gas imbalances are reflected as adjustments
to proved gas reserves and future cash flows in the unaudited supplemental oil
and gas disclosures.

Pursuant to the Production Payment discussed in Note 2, the Company
recorded the net proceeds from the sale of this Production Payment of
approximately $175 million as deferred revenue on the balance sheet. In
accordance with SFAS No. 19 "Financial Accounting and Reporting by Oil and Gas
Producing Companies," deliveries under this Production Payment are recorded as
non-cash oil and gas revenue with a corresponding reduction of deferred revenue
at the average price per Mcf of natural gas and per barrel of oil received when
the Production Payment was sold. The Company also reflects the production
volumes and depletion expense as deliveries are made. However, the associated
oil and gas reserves are excluded from the Company's reserve data. In 2002, the
Company delivered 11.2 Bcfe under this Production Payment and recorded $45.2
million of oil and gas revenue. Since the sale of the Production Payment in
February 2001 through December 31, 2002, the Company has delivered 26.9 Bcfe, or
62% of the total quantity to be delivered. For 2003, scheduled deliveries are
6.8 Bcfe.

STOCK COMPENSATION

The cost of awards of restricted stock, determined as the market value of
the shares at the date of grant, is expensed ratably over the restricted period.
See Note 4.

As permitted under SFAS No. 123 "Accounting for Stock-Based Compensation",
as amended, the Company has elected to continue to account for stock options
under the provisions of Accounting Principles Board Opinion No. 25 "Accounting
for Stock Issued to Employees." Under this method, the Company records no
compensation expense for stock options granted if the exercise price of those
options is equal to or greater than the market price of the Company's common
stock on the date of grant, unless the awards are subsequently modified. The
following table illustrates the effect on income (loss) available to common

36

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

stockholders and earnings (loss) per share if the Company had applied the fair
value recognition provision of SFAS No. 123, as amended.

ALLOWANCE FOR DOUBTFUL ACCOUNTS

The Company maintains an allowance for doubtful accounts receivable based
upon the expected collectibility of all trade receivables. The allowance is
reviewed continually and adjusted for accounts deemed uncollectible. The
allowance was $4.7 million and $4.2 million at December 31, 2002 and 2001,
respectively. Included in the allowance is $3.7 million which represents a 79%
reserve against receivables from Enron entities in bankruptcy. The Company
currently believes that the remaining $1.0 million receivable from such entities
will ultimately be recovered based on several factors, including the Company's
assessment that a large percentage of its Enron related receivables should
qualify as priority claims in the bankruptcy process.

The Company extends credit, primarily in the form of monthly oil and gas
sales and joint interest owners receivables, to various companies in the oil and
gas industry, which may result in a concentration of credit risk. The
concentration of credit risk may be affected by changes in economic or other
conditions and may, accordingly, impact the Company's overall credit risk.
However, the Company believes that the risk associated with these receivables is
mitigated by the size and reputation of the companies to which the Company
extends credit and by dispersion of credit risk among many parties.
37

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

INCOME TAXES

The Company accounts for income taxes in accordance with SFAS No. 109
"Accounting for Income Taxes." Deferred income taxes are recorded to reflect the
future tax consequences of differences between the tax bases of assets and
liabilities and their financial reporting amounts at each year end. A valuation
allowance is recognized if at the time it is anticipated that some or all of a
deferred tax asset may not be realized.

During the second quarter of 2002, the Company concluded that a $15.9
million increase in the valuation allowance, which reduced the carrying value of
net deferred assets to zero, was appropriate. In making that assessment,
management considered several factors, including future projections of taxable
income, which reflected relatively low natural gas and oil prices at that time,
and the January 2003 maturity of the Company's Senior Note obligations that
required refinancing. While the Senior Note obligations have now been refinanced
and natural gas and oil prices have improved significantly in recent months, the
Company continues to maintain the valuation allowance against 100% of its net
deferred tax assets. The Company made this determination since, at this time, it
is difficult to project the necessary levels of future taxable income with
sufficient certainty, considering the significant volatility in natural gas and
oil prices and that the current higher price environment has existed for only a
short period. The Company will continue to assess the valuation allowance and to
the extent it is determined that such allowance is no longer required, the tax
benefit of the remaining net deferred tax assets will be recognized in the
future. See Note 8.

EARNINGS (LOSS) PER SHARE

Basic earnings (loss) per share of common stock is computed by dividing
income (loss) available to common stockholders by the weighted average number of
common shares outstanding during the period. Diluted earnings (loss) per share
of common stock reflects the potential dilution that could occur if the
Company's dilutive outstanding stock options and warrants were exercised using
the average common stock price for the period and if the Company's convertible
preferred stock was converted to common stock.

The following table sets forth the computation of basic and diluted
earnings per share:

Common shares on assumed conversion of convertible preferred stock
amounting to 4.8 million shares in 2002 were not included in the computation of
diluted loss per common share nor were accrued dividends on convertible
preferred stock or stock options and warrants since they would be anti-dilutive.

38

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

COMMON STOCK OUTSTANDING

SEGMENT REPORTING

The Company operates in one reportable segment, as an independent oil and
gas company engaged in the acquisition, exploration, exploitation and production
of oil and gas properties. The Company's operations are conducted entirely in
the United States.

NEW ACCOUNTING PRINCIPLES

Effective January 1, 2002, KCS began amortizing the capitalized costs
related to oil and gas properties on the unit-of-production basis ("UOP") using
proved oil and gas reserves. Previously, KCS had computed amortization on the
basis of future gross revenue ("FGR"). As discussed in "Revenue Recognition"
above, the Company accounted for the proceeds from the Production Payment as
deferred revenue and as such, did not credit the full cost pool for the
proceeds. Accordingly, for purposes of calculating DD&A under both UOP and FGR,
the Company includes reserves associated with the Production Payment. Under UOP,
the amortization rate is computed by dividing the physical units of production
by the physical units of proved reserves. Physical units of oil and gas are
converted to a common unit of measurement on the basis of their relative energy
content. Under FGR, the amortization rate is computed by dividing oil and gas
revenue by the future gross revenue from proved reserves based on current
prices. Using either the UOP or FGR, the amortization rate is applied to the
amortizable base of the Company's oil and gas properties (the net book value of
oil and gas properties less the cost of unevaluated oil and gas properties plus
estimated future development costs associated with proved reserves, including
estimated dismantlement and abandonment costs net of estimated salvage values).

The Company determined that the change to UOP was preferable under
accounting principles generally accepted in the United States, since among other
reasons, it provides a more rational basis for amortization during periods of
volatile commodity prices and also increases consistency with others in the
industry.

As a result of this change, the Company recorded a non-cash cumulative
effect charge of $6.2 million, net of tax (or $0.17 per basic and diluted common
share) in the Statements of Consolidated Operations. The effect of the change in
accounting principle in 2002 was to decrease the net loss by approximately $3.2
million, or $0.09 per basic and diluted share. The following table illustrates
the effect on income (loss) attributable to

39

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

common stockholders and earnings per share if the Company had applied UOP to
amortize its oil and gas properties during 2001 and 2000:

In July 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 143, "Accounting for Asset Retirement Obligations". SFAS No. 143 requires
entities to record the fair value of a liability for legal obligations
associated with the retirement obligations of tangible long-lived assets in the
periods in which it is incurred. When the liability is initially recorded, the
entity increases the carrying amount of the related long-lived asset. The
liability is accreted to the fair value at the time of settlement over the
useful life of the asset, and the capitalized cost is depreciated over the
useful life of the related asset. The Company adopted SFAS No. 143 effective
January 1, 2003. As a result, net property, plant and equipment was increased by
$10.2 million, an asset retirement obligation of $11.1 million was recorded and
a $0.9 million charge against net income will be reported in the first quarter
of 2003 as a cumulative effect of a change in accounting principle.

In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" ("SFAS No. 144"). SFAS No. 144
addresses the financial accounting and reporting for the impairment or disposal
of long-lived assets. SFAS No. 144 supersedes SFAS No. 121 but retains its
fundamental provisions for the (a) recognition/measurement of impairment of
long-lived assets to be held and used and (b) measurement of long-lived assets
to be disposed of by sale. SFAS No. 144 also supersedes the accounting/reporting
provisions of APB Opinion No. 30 for segments of a business to be disposed of
but retains the requirement to report discontinued operations separately from
continuing operations and extends that reporting to a component of an entity
that either has been disposed of or is classified as held for sale. The Company
adopted the provisions of SFAS No. 144 effective January 1, 2002, with no
significant impact.

USE OF ESTIMATES

The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosures of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.

2. REORGANIZATION

On January 30, 2001, the United States Bankruptcy Court for the District of
Delaware (the "Bankruptcy Court") confirmed the KCS Energy, Inc. plan of
reorganization ("the Plan") under Chapter 11 of Title 11 of the United States
Bankruptcy Code ("Bankruptcy Code") after the Company's creditors and
stockholders voted to approve the Plan. On February 20, 2001, the Company
completed the necessary steps for the Plan to

40

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

go effective and emerged from bankruptcy having reduced its debt from a peak of
$425.0 million in early 1999 to $215.0 million and having cash on hand in excess
of $30 million.

Under the terms of the Plan, the Company: 1) sold a 43.1 Bcfe (38.3 Bcf of
gas and 797,000 barrels of oil) production payment ("Production Payment") to be
delivered in accordance with an agreed schedule over a five year period for net
proceeds of approximately $175 million and repaid all amounts outstanding under
its existing bank credit facilities, 2) sold $30.0 million of convertible
preferred stock, 3) paid to the holders of the Company's 11% Senior Notes, on a
pro rata basis, cash equal to the sum of (a) $60.0 million plus the amount of
past due accrued and unpaid interest of $15.1 million on $60.0 million of the
Senior Notes as of the effective date, compounded semi-annually at 11% per annum
and (b) the amount of past due accrued and unpaid interest of $21.5 million on
$90.0 million of the Senior Notes as of January 15, 2001, compounded
semi-annually at 11% per annum, 4) paid to the holders of the Company's 8 7/8%
Senior Subordinated Notes, cash in the amount of past due accrued and unpaid
interest of $23.7 million as of January 15, 2001, compounded semi-annually at
8 7/8% per annum, 5) renewed the remaining outstanding $90.0 million principal
amount of Senior Notes and $125.0 million principal amount of Senior
Subordinated Notes under amended indentures but without a change in interest
rates, and 6) paid pre-petition trade creditors in full. Shareholders retained
100% of their common stock, subject to dilution from conversion of the new
convertible preferred stock.

3. RETIREMENT BENEFIT PLAN

The Company sponsors a Savings and Investment Plan ("Savings Plan") under
Section 401(k) of the Internal Revenue Code. Eligible employees may contribute a
portion of their compensation, as defined, to the Savings Plan, subject to
certain IRS limitations. The Company may make matching contributions, which have
been set by the Board of Directors at 50% of the employee's contribution (up to
6% of the employee's compensation, subject to certain regulatory limitations).
The Savings Plan also contains a profit-sharing component whereby the Board of
Directors may declare annual discretionary profit-sharing contributions.
Profit-sharing contributions are allocated to eligible employees based upon
their pro-rata share of total eligible compensation and may be made in cash or
in KCS Common Stock. Contributions to the Savings Plan are invested at the
direction of the employee in one or more funds or can be directed to purchase
common stock of the Company at market value. The Company's matching
contributions and discretionary profit-sharing contributions vest over a
four-year employment period. Once the four-year employment period has been
satisfied, all Company matching contributions and discretionary profit-sharing
contributions vest immediately. Company contributions to the Savings Plan were
$531,103 in 2002, $510,702 in 2001 and $454,341 in 2000. These amounts are
included in general and administrative expense.

4. STOCK OPTION AND INCENTIVE PLANS

On February 20, 2001 in connection with the Plan (see Note 2), the
Company's 1992 Stock Plan and the 1994 Directors' Stock Plan and all outstanding
options thereunder were cancelled. Also, as part of the Plan, the KCS Energy,
Inc. 2001 Employees and Directors Stock Plan ("2001 Stock Plan") was adopted.
The 2001 Stock Plan provides that stock options, stock appreciation rights,
restricted stock and bonus stock may be granted to employees of KCS. The 2001
Stock Plan provides that each non-employee director be granted stock options for
1,000 shares annually. This plan also provides that in lieu of cash, each
non-employee director be issued KCS common stock with a fair market value equal
to 50% of their annual retainer. The 2001 Stock Plan provides that the option
price of shares issued be equal to the market price on the date of grant.
Options granted to directors as part of their annual retainer vest immediately.
All other options vest ratably on the anniversary of the date of grant over
either two years or three years. All options expire 10 years after the date of
grant. Options reissued to employees within six months of a cancellation are
accounted for as a modification of the original award. For these awards, changes
in the quoted market price of the Company's stock above the exercise price of
the options result in a change in the measurement of compensation for the
41

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

awards. No compensation expense was recorded for modified awards in 2002, 2001
or 2000. The 2001 Stock Plan provided for the issuance of up to 4,362,868 shares
of KCS common stock.

Restricted shares awarded under the 2001 Stock Plan have a restriction
period of three years during which ownership of the shares cannot be transferred
and the shares are subject to forfeiture if employment terminates before the end
of the restriction period. Certain restricted stock awards provide for the
restriction period to accelerate to one year if certain performance criteria are
met. Restricted stock is considered to be currently issued and outstanding and
has the same rights as other common stock. The cost of the awards of restricted
stock, determined as the market value of the shares at the date of grant, is
expensed ratably over the restricted period. Restricted stock totaling 579,528
shares were outstanding at December 31, 2002.

At December 31, 2002, a total of 1,989,092 shares were available for future
grants under the 2001 Stock Plan.

A summary of the status of the stock options under the 2001 Stock Plan, the
cancelled 1992 Stock Plan and the cancelled 1994 Directors' Stock Plan at
December 31, 2002, 2001 and 2000 and changes during the years then ended is
presented below.

The fair value of each option grant is estimated on the date of grant using
the Black-Scholes option pricing model with the following weighted average
assumptions used for grants in 2002: risk-free interest rate of 5.3%; expected
dividend yield of 0.00%; expected life of 10 years; and expected stock price
volatility of 86.7%. The weighted average assumptions used for grants in 2001
were: risk-free interest rate of 5.4%; expected dividend yield of 0.00%; and
expected life of 10 years; and expected stock price volatility of 85.3%.

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

(a) Cancelled in connection with the Company's plan of reorganization.

42

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table summarizes information about stock options outstanding
at December 31, 2002:

The Company has an employee stock purchase program (the "Program") whereby
all eligible employees and directors may purchase full shares from the Company
at a price per share equal to 90% of the market value determined by the closing
price on the date of purchase. The minimum purchase is 25 shares. The maximum
annual purchase is the number of shares costing no more than 10% of the eligible
employee's annual base salary, and for directors, 6,000 shares. The number of
shares issued in connection with the Program was 8,209 shares, 9,160 shares and
100 shares during 2002, 2001 and 2000, respectively. At December 31, 2002, there
were 775,989 shares available for issuance under the Program.

5. DEBT

Debt consists of the following:

CREDIT AGREEMENT

On January 14, 2003, the Company amended and restated its credit agreement
("Credit Agreement") with a group of institutional lenders. The Credit
Agreement, which matures on October 3, 2005, provides up to $90.0 million of
borrowing capacity, $40.0 million in the form of a term loan, a $30.0 million
revolving "A" facility and a $20.0 million revolving "B" facility. Borrowing
capacity is subject to monthly borrowing base calculations with respect to the
value of the Company's oil and gas assets. Initial proceeds of $69.3 million
were used primarily to pay off the Company's maturing Senior Note obligations.
The term loan and the revolving "B" facility, which may be prepaid at any time
without penalty, bear interest based on the prime rate, initially equating to
9.0%, and increasing annually. The revolving "A" facility bears, at the
Company's option, an interest rate of LIBOR plus 2.75% to 3.0% or prime plus
0.5% to 0.75%, depending on utilization. The revolving "A" facility requires a
commitment fee of 0.5% per annum on the unused availability and carries an early
termination penalty of 1.5% in the first year and 1% in the second year.
Financing fees associated with the amended and restated agreement have been
recorded as deferred charges and are being amortized as interest expense over
the life of the Credit Agreement. The remaining deferred financing fees
associated with the original agreement ($1.1 million) were written off to
interest expense in December 2002.

43

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Certain other fees are also payable under the Credit Facility based on services
provided. Substantially all of the Company's assets are pledged to secure the
Credit Agreement.

The Credit Agreement contains various restrictive covenants including
ratios of debt to EBITDA, interest coverage, fixed charge coverage and
liquidity. The Credit Agreement also contains provisions that require the
hedging of a portion of the Company's oil and gas production, payment upon a
change of control, restrictions on the payment of dividends and certain other
restricted payments and places limitations on the incurrence of additional debt,
capital expenditures, the sale of assets, and the repurchase of Senior
Subordinated Notes. Any repayment made on the term loan portion of the facility
will permanently reduce the funds available under the Credit Agreement. The
Credit Agreement also contains cross-default provisions which would result in
the acceleration of payments if the Company defaults on its other debt
instruments.

SENIOR NOTES

On January 25, 1996, KCS issued $150.0 million principal amount of 11%
Senior Notes due 2003 (the "Senior Notes"). The Company redeemed $70.2 million
of Senior Notes in 2001, $18.5 million in 2002 and paid off the remaining $61.3
million upon maturity on January 15, 2003. The balance at December 31, 2002 has
been classified as long-term because of the Company's intent and ability to
refinance such amounts on a long-term basis through the Credit Agreement amended
on January 14, 2003.

SENIOR SUBORDINATED NOTES

On January 15, 1998, the Company completed a public offering of $125.0
million of Senior Subordinated Notes at an interest rate of 8 7/8%. The Senior
Subordinated Notes were non-callable for five years and are unsecured
subordinated obligations of KCS. The subsidiaries of KCS have guaranteed the
Senior Subordinated Notes on an unsecured subordinated basis. The guarantees are
full and unconditional and joint and several.

On February 20, 2001, in connection with the Plan (see Note 2), the
indenture governing the Senior Subordinated Notes was amended to, among other
things, accelerate the maturity date of the Senior Subordinated Notes from
January 15, 2008 to January 15, 2006.

The Senior Subordinated Notes, as amended, contain certain restrictive
covenants which, among other things, limit the Company's ability to incur
additional indebtedness, require the repurchase of the Senior Subordinated Notes
upon a change of control, and limit: a) the aggregate purchases and redemptions
of the Company's Series A Convertible Preferred Stock for cash and b) the
aggregate cash dividends paid on capital stock, collectively, to 50% of the
Company's cumulative net income, as defined, during the period beginning after
December 31, 2000. The Senior Subordinated Notes also contain cross-default
provisions which would result in the acceleration of payments if the Company
defaults on its other debt instruments.

OTHER INFORMATION

The estimated fair values of the Company's Senior Notes and Senior
Subordinated Notes are based on quoted market values and at December 31, 2002
were $61.3 million and $94.4 million, respectively. The estimated fair value of
the Company's Senior Notes and Senior Subordinated Notes at December 31, 2001
were $79.4 million and $85.0 million, respectively.

The scheduled maturities of the Company's debt during the next five years
are as follows: $-0- in 2003, $-0- in 2004, $61.8 million in 2005 and $125.0
million in 2006.

Total interest payments were $19.2 million in 2002, $71.5 million in 2001
and $8.6 million in 2000. Interest payments in 2001 included approximately $60.7
million made in connection with the Plan (see Note 2). The 2001 payments include
$60.3 million paid in connection with the Plan to holders of the Senior

44

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Notes and the Senior Subordinated Notes for interest accrued but not paid during
the reorganization period, which included interest on interest. Capitalized
interest was $0.7 million in 2002, $0.6 million in 2001 and $0.6 million in
2000.

6. REDEEMABLE CONVERTIBLE PREFERRED STOCK

In connection with the Plan (see Note 2), the Company issued 30,000 shares
of Series A Convertible Preferred Stock, $0.01 par value ("Preferred Stock") at
a price of $1,000 per share convertible at any time into a total of 10,000,000
shares of KCS Common Stock at a conversion price of $3.00 per share. Net
proceeds from the issuance of the Preferred Stock was $28.4 million. The excess
of the redemption value of the Preferred Stock over the original net issuance
proceeds is reflected as accretion of issuance costs on preferred stock in the
Statements of Consolidated Operations. The Preferred Stock pays a 5% per annum
dividend payable quarterly in cash or, during the first two years following
issuance, in shares of KCS common stock valued at the average of the high and
the low trading price for the twenty trading days prior to the dividend payment
date. The Preferred Stock is redeemable at the option of the Company if the
closing price of the Common Stock exceeds $6.00 per share for 25 out of 30
consecutive trading days or at the election of holders of a majority of the
outstanding shares of Preferred Stock on or after January 31, 2009.

In connection with the issuance of the Preferred Stock, the Company issued
the placement agent warrants, which expire on February 29, 2006, to purchase
400,000 shares of KCS common stock at $4.00 per share.

The Preferred Stock has no voting rights except upon certain defaults or
failure to pay dividends and as otherwise required by law. The Preferred Stock
ranks senior to Common Stock or any future issue of preferred stock. The
Preferred Stock has a liquidation preference of $1,000 per share plus accrued
and unpaid dividends.

As a result of conversions of the Preferred Stock, 1.0 million and 4.6
million shares of common stock were issued in 2002 and 2001, respectively. In
addition 0.4 million and 0.2 million shares of common stock were issued as
dividends on the preferred stock in 2002 and 2001, respectively. In January
2003, 1.2 million shares of common stock were issued as a result of conversions
of the Preferred Stock.

7. LEASES AND UNCONDITIONAL PURCHASE OBLIGATIONS

Future minimum lease payments under operating leases having initial or
remaining non-cancelable lease terms in excess of one year are as follows: $1.5
million in 2003, $1.2 million in 2004, $0.5 million in 2005, $0.3 million in
2006 and none thereafter. Lease payments charged to operating expenses amounted
to $1.3 million, $0.8 million and $0.6 million during 2002, 2001 and 2000,
respectively. In addition, the Company has unconditional purchase obligations,
primarily related to natural gas transportation contracts of $2.9 million in
2003, $2.9 million in 2004, $2.6 million in 2005 and $0.7 million in 2006.

45

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

8. INCOME TAXES

Federal and state income tax provision (benefit) includes the following
components:

The primary differences giving rise to the Company's net deferred tax
assets are as follows:

State income tax payments were $0.5 million in 2002 and $0.1 million in
2001. No income tax payments were made in 2000.

46

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Due to the significant losses recorded in 1998 and the uncertainty of
future oil and natural gas commodity prices, the Company concluded at that time
that a valuation allowance against net deferred tax assets was required in
accordance with SFAS No. 109. In making its assessment, the Company considered
several factors, including uncertainty of the Company's ability to generate
sufficient income in order to realize its future tax benefits. A substantial
portion of the valuation allowances provided by the Company relates to loss and
credit carryforwards. To determine the proper amount of valuation allowances
with respect to these carryforwards, the Company evaluated all appropriate
factors, including any limitations concerning their use resulting from
consequences of its bankruptcy or otherwise and the year the carryforwards
expire, as well as the levels of taxable income necessary for utilization.

During the second quarter of 2002, the Company concluded that a $15.9
million increase in the valuation allowance, which reduced the carrying value of
net deferred assets to zero, was appropriate. In making that assessment,
management considered several factors, including future projections of taxable
income, which reflected relatively low natural gas and oil prices at that time,
and the January 2003 maturity of the Company's Senior Note obligations that
required refinancing. While the Senior Note obligations have now been refinanced
and natural gas and oil prices have improved significantly in recent months, the
Company continues to maintain the valuation allowance against 100% of its net
deferred tax assets. The Company made this determination, since at this time, it
is difficult to project the necessary levels of future taxable income with
sufficient certainty, considering the significant volatility in natural gas and
oil prices and that the current higher price environment has existed for only a
short period. The Company will continue to assess the valuation allowance and to
the extent it is determined that such allowance is no longer required, the tax
benefit of the remaining net deferred tax assets will be recognized in the
future.

At December 31, 2002, the Company had tax net operating losses (NOLs) of
approximately $215.4 million available to offset future taxable income, of which
approximately $59.2 million will expire in 2012, $73.8 million will expire in
2018, $34.1 million will expire in 2019, $26.0 million will expire in 2020 and
$22.3 million will expire in 2022.

9. DERIVATIVES

Oil and gas prices have historically been volatile. The Company has at
times utilized derivative contracts, including swaps, futures contracts, options
and collars, to manage this price risk.

Commodity Price Swaps. Commodity price swap agreements require the Company
to make or receive payments from the counter parties based upon the differential
between a specified fixed price and a price related to those quoted on the New
York Mercantile Exchange for the period involved.

Futures Contracts. Oil or natural gas futures contracts require the
Company to sell and the counter party to buy oil or natural gas at a future time
at a fixed price.

Option Contracts. Option contracts provide the right, not the obligation,
to buy or sell a commodity at a fixed price. By buying a "put" option, the
Company is able to set a floor price for a specified quantity of its oil or gas
production. By selling a "call" option, the Company receives an upfront premium
from selling the right for a counter party to buy a specified quantity of oil or
gas production at a fixed price.

Price Collars. Selling a call option and buying a put option creates a
"collar" whereby the Company establishes a floor and ceiling price for a
specified quantity of future production. Buying a call option with a strike
price above the sold call strike price establishes a "3-way collar" that
entitles the Company to capture the benefit of price increases above that call
price.

Upon adoption of SFAS No. 133, the Company recorded a liability of $43.8
million representing the fair market value of its derivative instruments at
adoption, a related deferred tax asset of $15.3 million and an

47

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

after-tax cumulative effect of change in accounting principle of $28.5 million
to accumulated OCI. The Company elected not to designate its then existing
derivative instruments as hedges which, subsequent to adoption of SFAS No. 133,
would require that changes in a derivative instrument's fair value be recognized
currently in earnings. However, SFAS No. 133 requires the Company's derivative
instruments that had been designated as cash flow hedges under accounting
principles generally accepted prior to the initial application of SFAS No. 133
to continue to be accounted for as cash flow hedges with the transition
adjustment reported as a cumulative-effect-type adjustment to accumulated OCI as
mentioned above.

In February 2001, the Company terminated certain derivative instruments in
connection with its emergence from bankruptcy for a cash payment of $28.0
million, which was offset against the accrued liability recorded in connection
with the adoption of SFAS No. 133. During the quarter ended March 31, 2001, as a
result of market price decreases, the ultimate cost to settle the remaining
derivative instruments in place at January 1, 2001 was reduced by $7.7 million.
This non-cash gain was recorded in other revenue during the quarter. The actual
cost to settle the remaining derivatives was $8.1 million. During 2001, $15.5
million, net of tax, of the above $28.5 million charged to OCI was reclassified
into earnings. The $8.5 million remaining in accumulated other comprehensive
income will be amortized into earnings over the original term of the derivative
instruments, which extends through August 2005 ($3.6 million in 2003, $2.9
million in 2004 and $2.0 million in 2005).

During 2001, all derivative contracts, other than the derivatives
terminated in connection with emergence from bankruptcy as discussed above, were
with Enron North America Corp., a subsidiary of Enron Corp. At the end of
November 2001, the Company had price swap contracts, designated as hedges,
covering 0.3 million MMbtu of December 2001 gas production; and price swaps and
collars covering 6.2 million MMBtu of 2002 gas production. The recorded value of
these derivatives at that time was estimated to be $2.7 million. Because of
Enron's financial condition, the Company concluded that these derivative
contracts no longer qualified for hedge accounting treatment. The Company
unwound the December derivatives and certain swap contracts covering 1.0 million
MMbtu of 2002 gas production. In December 2001, Enron North America Corp. and
Enron Corp. filed for bankruptcy protection and did not pay the Company for the
contracts that were unwound. At December 31, 2001, $2.3 million in unrealized
gains related to 2002 gas production was included in accumulated OCI and was
reclassified into earnings during 2002. The related assets were reclassified as
a receivable from Enron and a provision for doubtful accounts was established.

At December 31, 2002, the Company had no derivative contracts outstanding.
The Company realized $4.9 million in net hedging losses during 2002, including
$5.0 million net hedging losses due to reclassifications from OCI for contracts
terminated prior to January 1, 2002. At December 31, 2001, the Company was not a
party to derivative contracts other than the Enron contracts described above.
The Company realized $22.1 million in net hedging losses and $8.6 million net
non-hedge derivative losses during 2001.

The table below presents changes in OCI associated with the Company's
derivative transactions since adopting SFAS No. 133.

48

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The unrealized loss balances at the end of year on the Company's derivative
transactions are net of income tax benefit of $4.6 million and $7.0 million for
2002 and 2001, respectively.

During February 2003, the Company entered into a series of derivative
transactions designed to protect against possible declines in natural gas prices
while enabling the Company to benefit from price increases. These transactions,
which covered 3.5 million MMbtu of 2003 gas production, as summarized below:

10. LITIGATION

ENVIRONMENTAL SUITS

The Company was a defendant in a lawsuit originally brought by InterCoast
Energy Company and MidAmerican Capital Company ("Plaintiffs") against KCS
Energy, Inc., KCS Medallion Resources, Inc. and Medallion California Properties
Company ("KCS Defendants"), and Kerr-McGee Oil & Gas Onshore LP and Kerr-McGee
Corporation ("Kerr-McGee Defendants") in the 234th Judicial District Court of
Harris County, Texas under Cause Number 1999-45998. The suit sought a
declaratory judgment declaring the rights and obligations of each of the
Plaintiffs, the KCS Defendants and the Kerr-McGee Defendants in connection with
environmental damages and surface restoration on lands located in Los Angeles
County, California which are covered by an Oil & Gas Lease dated June 13, 1935,
from Newhall Land and Farming Company, as Lessor, to Barnsdall Oil Company, as
Lessee (the "RSF Lease") and by an Oil and Gas Lease dated June 6, 1941, from
the Newhall Corporation, as Lessor, to C. G. Willis, as Lessee (the "Ferguson
Lease" and together with the RSF Lease, the "Leases").

The Kerr-McGee Defendants, KCS Defendants and Plaintiffs entered into an
Agreed Interlocutory Judgment that contains clarification of the language of the
1990 agreement between predecessors of the KCS Defendants and the Kerr-McGee
Defendants (the "1990 Agreement") under which the Leases were transferred from
Kerr-McGee's predecessor to predecessors of Medallion California Properties
Company ("MCPC"). The Court previously entered the Agreed Interlocutory
Judgment, which essentially disposed of interpretation questions concerning the
1990 Agreement. After entry of the Agreed Interlocutory Judgment, the remaining
issues in the case concerned the interpretation of the 1996 Stock Purchase
Agreement through which certain of the KCS Defendants acquired the stock of
MCPC. Specifically, the remaining issues involved the extent to which Plaintiffs
are obligated to indemnify the KCS Defendants for environmental investigation
costs previously incurred by the KCS Defendants and also for costs of defense
and liability to the KCS Defendants, if any, in the California litigation
described below. By Compromise and Settlement Agreement dated as of October 19,
2001, the Plaintiffs and KCS Defendants agreed: (i) to settle those issues

49

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

dealing with the Plaintiffs' obligations to reimburse costs previously incurred
in connection with defense of the California case described below; (ii) to
provide prospectively for the control of defense and settlement and the sharing
of defense costs in the California case described below; and (iii) to defer any
disputes concerning the respective liability of Plaintiffs and KCS Defendants
for any individual claims until the extent of such individual claim liability,
after giving effect to indemnification obligations under the 1990 Agreement, is
fully and finally determined. The Agreed Interlocutory Judgment has now been
entered as a final judgment.

MCPC is a defendant in a lawsuit filed January 30, 2001, by The Newhall
Land and Farming Company ("Newhall") against MCPC and Kerr-McGee Corporation and
several Kerr-McGee affiliates. The case is currently pending in Los Angeles
County Superior Court under Cause Number BC244203. In the suit, Newhall seeks
damages for alleged environmental contamination and surface restoration on the
lands covered by the RSF Lease and also seeks a declaration that Newhall may
terminate the RSF Lease or alternatively, that it may terminate those portions
of the RSF Lease on which there is currently default under the Lease. MCPC
claims that Newhall is not entitled to lease termination as a remedy and that
Kerr-McGee and InterCoast and MidAmerican owe indemnities to MCPC for defense
and certain potential liability under Newhall's action, all as more particularly
described in the Harris County, Texas litigation described above. Discovery is
ongoing, and the lawsuit is set for trial in May 2003.

OTHER

The Company and several of its subsidiaries have been named as
co-defendants along with numerous other industry parties in an action brought by
Jack Grynberg on behalf of the Government of the United States. The complaint,
filed under the Federal False Claims Act, alleges underpayment of royalties to
the Government of the United States as a result of alleged mismeasurement of the
volume and wrongful analysis of the heating content of natural gas produced from
federal and Native American lands. The complaint is substantially similar to
other complaints filed by Jack Grynberg on behalf of the Government of the
United States against multiple other industry parties. All of the complaints
have been consolidated in one proceeding. In April 1999, the Government of the
United States filed notice that it had decided not to intervene in these
actions. The Company believes that the allegations in the complaint are without
merit.

The Company is also a party to various other lawsuits and governmental
proceedings, all arising in the ordinary course of business. Although the
outcome of all of the above proceedings cannot be predicted with certainty,
management does not expect such matters to have a material adverse effect,
either singly or in the aggregate, on the financial position or results of
operations of the Company. It is possible, however, that charges could be
required that would be significant to the operating results during a particular
period.

50

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

11. QUARTERLY FINANCIAL DATA (UNAUDITED)

Effective January 1, 2002, the Company changed its method of amortizing its
oil and gas properties from FGR to UOP. See Note 1 to Consolidated Financial
Statements. The previously reported amounts reflected in quarterly reports on
Form 10-Q for the first three quarters of 2002 reflected FGR. These amounts have
been recalculated to reflect UOP in the table above. The effect of this change
was to decrease the net losses in the first and second quarters by $2.1 million
and $0.8 million, respectively, and increase net income by $0.2 million in both
the third and fourth quarters. Amounts for 2001 have not been restated to
reflect the change.

The total of the earnings per share for the quarters may not equal the
earnings per share elsewhere in the Consolidated Financial Statements as each
quarterly computation is based on the weighted average number of common shares
outstanding during that period. In addition, certain potentially dilutive
securities were not included in certain of the quarterly computations of diluted
earnings (loss) per common share because to do so would have been anti-dilutive.

12. OIL AND GAS PRODUCING OPERATIONS (UNAUDITED)

The following data is presented pursuant to SFAS No. 69 "Disclosure about
Oil and Gas Producing Activities" with respect to oil and gas acquisition,
exploration, development and producing activities, which is based on estimates
of year-end oil and gas reserve quantities and forecasts of future development
costs and production schedules. These estimates and forecasts are inherently
imprecise and subject to substantial revision as a result of changes in
estimates of remaining volumes, prices, costs and production rates.

Except where otherwise provided by contractual agreement, future cash
inflows are estimated using year-end prices. Oil and gas prices at December 31,
2002 are not necessarily reflective of the prices the Company expects to receive
in the future. Other than gas sold under contractual arrangements, gas prices
were based on year-end spot market prices of $4.74, $2.65 and $9.53 per MMBTU
adjusted by lease for BTU content, transportation fees and regional price
differentials at December 31, 2002, 2001 and 2000, respectively. Oil prices were
based on West Texas Intermediate (WTI) posted prices of $28.00, $16.75 and
$23.75 at

51

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

December 31, 2002, 2001 and 2000, respectively adjusted by lease for gravity,
transportation fees and regional price differentials.

Purchased VPP volumes represent oil and gas reserves acquired from third
parties which generally entitle the Company to a specified volume of oil and gas
to be delivered over a stated time period. The related volumes stated herein
reflect scheduled amounts of oil and gas to be delivered to the Company at
agreed delivery points and future cash inflows are estimated at year-end prices.
Although specific terms of the Company's VPPs vary, the Company is generally
entitled to receive delivery of its scheduled oil and gas volumes, free of
drilling and lease operating costs. The Company received the final deliveries
under purchased VPP's in December 2002. Therefore, reserve data as of December
31, 2002 do not include any VPP volumes.

Reserves at December 31, 2002 and 2001 have been reduced to reflect the
sale of the Production Payment of 38.3 Bcf of gas and 797,000 barrels of oil as
discussed in Note 2.

PRODUCTION REVENUES AND COSTS (UNAUDITED)

Information with respect to production revenues and costs related to oil
and gas producing activities is as follows:

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

(a) Includes amortization of deferred revenue of $45,182 in 2002, and $63,089
in 2001 related to volumes delivered under the Production Payment sold in
February 2001. See Note 2.

52

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)

The following information relating to discounted future net cash flows has
been prepared on the basis of the Company's estimated net proved oil and gas
reserves in accordance with SFAS No. 69.

Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

Changes in Discounted Future Net Cash Flows from Proved Reserve Quantities

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

(a) Excludes $66,582 and $111,880 of deferred revenue at December 31, 2002
and 2001, respectively, related to the Production Payment sold in 2001 as
discussed in Note 2.

53

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

RESERVE INFORMATION (UNAUDITED)

The reserve estimates and associated cash flows for all properties for the
years ended December 31, 2002 and 2000 were prepared by Netherland, Sewell &
Associates, Inc. ("NSA"). For the year ended December 31, 2001, the reserve
estimates were prepared by the Company and audited by NSA. Proved developed
reserves represent only those reserves expected to be recovered through existing
wells using equipment currently in place. Proved undeveloped reserves represent
proved reserves expected to be recovered from new wells or from existing wells
after material recompletion expenditures. All of the Company's reserves are
located within the United States.

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

(a) 2001 and 2002 production excludes volumes produced and delivered with
respect to the Production Payment sold in February 2001 as discussed in
Note 2.

(b) The Company sold a Production Payment in 2001 as discussed in Note 2. The
approximate 38.3 Bcf of gas and 797,000 barrels of oil Production Payment
is reflected as sales of reserves in place in 2001 in the table above.

54

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

By unanimous written consent dated July 1, 2002, the Company's board of
directors, upon the recommendation of its Audit Committee, approved the
dismissal of Arthur Andersen LLP ("Andersen") and the appointment of Ernst &
Young LLP to serve as the Registrant's independent public accountants for the
fiscal year ending December 31, 2002.

The audit reports of Andersen with respect to the consolidated financial
statements of the Company as of and for the fiscal years ended December 31, 2001
and December 31, 2000 did not contain any adverse opinion or disclaimer of
opinion, nor were they qualified or modified as to uncertainty or audit scope.
In addition, there were no modifications as to accounting principles except that
the most recent audit report of Andersen dated March 13, 2002 contained an
explanatory paragraph with respect to the change in the method of accounting for
derivative instruments effective January 1, 2001 as required by the Financial
Accounting Standards Board.

During the years ended December 31, 2001 and 2000 and the subsequent
interim period through July 1, 2002, there were no disagreements with Andersen
on any matter of accounting principles or practices, financial statement
disclosure, or auditing scope or procedure which, if not resolved to Andersen's
satisfaction, would have caused them to make reference to the subject matter in
connection with their report on the Company's financial statements for such
years, and there were no reportable events as defined in Item 304(a)(1)(v) of
Regulation S-K.

The Company provided Andersen with a copy of the above disclosures and
requested that Andersen furnish the Company with a letter addressed to the
Securities and Exchange Commission stating whether or not Andersen agreed with
the statements made by the Company and, if not, stating the respects in which it
does not agree. The Company was informed by Andersen's national office that
Andersen could not issue such a letter due to the discontinuance of its audit
practice.

During the Company's two fiscal years ended December 31, 2001 and 2000, and
the subsequent interim period through July 1, 2002, the Company did not consult
Ernst & Young LLP with respect to the application of accounting principles to a
specified transaction, either completed or proposed, or the type of audit
opinion that might be rendered on the Company's consolidated financial
statements, or any other matters or reportable events described in Items
304(a)(2)(i) and (ii) of Regulation S-K.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Information for this item is set forth in our Proxy Statement for the 2003
Annual Meeting of Stockholders, and is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

Information for this item is set forth in our Proxy Statement for the 2003
Annual Meeting of Stockholders, and is incorporated herein by reference.

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

Information for this item is set forth in our Proxy Statement for the 2003
Annual Meeting of Stockholders, and is incorporated herein by reference.
Information concerning securities authorized for issuance under equity
compensation plans is set forth in Item 5 of this Form 10-K and is incorporated
herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information for this item is set forth in our Proxy Statement for the 2003
Annual Meeting of Stockholders, and is incorporated herein by reference.
55

ITEM 14. CONTROLS AND PROCEDURES

(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

The term disclosure controls and procedures is defined in Rules 13a-14(c)
and 15d-14(c) of the Securities Exchange Act of 1934. These rules refer to the
controls and other procedures of a company that are designed to ensure that
information required to be disclosed by a company in the reports that it files
under the Exchange Act is recorded, processed, summarized and reported within
the time periods specified in the Securities and Exchange Commission's rules and
forms. Furthermore, we have designed our disclosure controls and procedures to
ensure that information that we are required to disclose in our report is
accumulated and communicated to management (including our Chief Executive
Officer and Principal Financial Officer) in a manner that permits timely
decisions to be made regarding required disclosure.

Our Chief Executive Officer and our Principal Financial Officer have
evaluated the effectiveness of our disclosure controls and procedures as of a
date within 90 days prior to the date of the filing of this annual report, and
they have concluded that such disclosure controls and procedures were effective
at ensuring that they were alerted in a timely manner as to all material
information that we are required to include in our reports with the Securities
and Exchange Commission.

(b) CHANGES IN INTERNAL CONTROLS

We maintain a system of internal accounting controls that is designed to
provide reasonable assurance that our books and records accurately reflect our
transactions and that our established policies and procedures are followed.
Since the date of the evaluation of our disclosure controls and procedures by
our Chief Executive Officer and Principal Financial Officer, there have been no
significant changes to our internal controls or in other factors that could
significantly affect our internal controls subsequent to the date of the most
recent evaluation.

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

(a) Financial statements, financial statement schedules and exhibits

(1) The following consolidated financial statements of KCS and its
subsidiaries and the related Report of Independent Public Accountants are
presented in Item 8 of this Form 10-K.

(2) Financial Statement Schedules

Financial statement schedules have been omitted because they are
either not required, not applicable or the information required to be
presented is included in the Company's financial statements and related
notes.

(3) Exhibits

See "Exhibit Index" located on page 61 of this Form 10-K for a
listing of all exhibits filed herein or incorporated by reference to a
previously filed registration statement or report with the Securities
and Exchange Commission ("SEC").

56

(b) Reports on Form 8-K

On December 18, 2002, the Company filed a report on Form 8-K under Item 5,
Other Events reporting the extension of the maturity date on its bank credit
facility. There were no other reports on Form 8-K filed during the three months
ended December 31, 2002. On January 21, 2003, the Company filed a report on Form
8-K under Item 5, Other Events reporting that the Company had completed its
previously announced financing and that it paid off the balance of its maturing
Senior Notes obligations.

57

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

KCS ENERGY, INC.

By: /s/ FREDERICK DWYER
------------------------------------
Frederick Dwyer
Vice President, Controller and
Secretary

Date: March 27, 2003

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities on the dates indicated.

58

CERTIFICATIONS

I, James W. Christmas, certify that:

1. I have reviewed this annual report on Form 10-K of KCS Energy, Inc.;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;

(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this annual report (the "Evaluation Date"); and

(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit committee
of registrant's board of directors (or persons performing the equivalent
functions):

(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal controls;
and

(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

/s/ JAMES W. CHRISTMAS
--------------------------------------
James W. Christmas
President and Chief Executive Officer

March 27, 2003

59

I, Frederick Dwyer, certify that:

1. I have reviewed this annual report on Form 10-K of KCS Energy, Inc.;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;

(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this annual report (the "Evaluation Date"); and

(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit committee
of registrant's board of directors (or persons performing the equivalent
functions):

(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal controls;
and

(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officer and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

/s/ FREDERICK DWYER
--------------------------------------
Frederick Dwyer
Vice President, Controller and
Secretary
(Principal Financial Officer and
Principal
Accounting Officer)

March 27, 2003

60

EXHIBIT INDEX

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

* Management contract or compensatory plan or arrangement required to be filed
as an exhibit.

61