KCS ENERGY INC - 10-Q Quarterly Report

Back to GetFilings.com

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2003

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: 001-13781

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

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

5555 San Felipe Road, Suite 1200, Houston, TX 77056
(Address of principal executive offices) (Zip Code)

(713) 877-8006
(Registrant's telephone number, including area code)

NOT APPLICABLE
(Former name, former address and former
fiscal year, if changed since last report.)

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. X Yes No
------- -------

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

Indicate by check mark whether the registrant has filed all documents and
reports required to be filed by Sections 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, par value $0.01 per share, outstanding as of
October 31, 2003 41,375,533

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

KCS ENERGY, INC. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

The accompanying notes to the unaudited condensed consolidated financial
statements are an integral part of these financial statements.

1

KCS ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS

The accompanying notes to the unaudited condensed consolidated financial
statements are an integral part of these financial statements.

2

KCS ENERGY, INC. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

The accompanying notes to the unaudited condensed consolidated financial
statements are an integral part of these financial statements.

3

KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY
(Amounts in thousands)

The accompanying notes to the unaudited condensed consolidated
financial statements are an integral part of these financial statements.

4

KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. Basis of Presentation

The condensed consolidated interim financial statements included herein
have been prepared by KCS Energy, Inc. ("KCS" or "Company"), without audit,
pursuant to the rules and regulations of the Securities and Exchange Commission
("SEC") for quarterly reports on Form 10-Q and reflect all adjustments which are
of a normal recurring nature and which are, in the opinion of management,
necessary to a fair statement of the results for the interim periods presented.
Certain information and footnote disclosures have been condensed or omitted
pursuant to such rules and regulations. Although KCS believes that the
disclosures are adequate to make the information presented not misleading, it is
suggested that these condensed consolidated financial statements be read in
conjunction with the financial statements and the notes thereto included in the
KCS Annual Report on Form 10-K for the year ended December 31, 2002. Certain
previously reported amounts have been reclassified to conform with current
period presentations. The results of operations for the nine months ended
September 30, 2003 are not necessarily indicative of the results that may be
expected for the year ending December 31, 2003.

2. New Accounting Principles

Effective January 1, 2003, the Company adopted Financial Accounting
Standards Board Statement No. 143, "Accounting for Asset Retirement Obligations"
("SFAS No. 143"). 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. Upon adoption of SFAS
No. 143, the Company's net property, plant and equipment was increased by $10.2
million, an additional asset retirement obligation of $11.1 million (primarily
for plugging and abandonment costs of oil and gas wells) was recorded and a $0.9
million charge, net of tax against net income (or a $0.02 loss per basic and
diluted share) was reported in the first quarter of 2003 as a cumulative effect
of a change in accounting principle. Subsequent to adoption, the effect of the
change in accounting principle in the nine months of ended September 30, 2003
was immaterial.

Had the provisions of SFAS No. 143 been applied as of January 1, 2002,
the asset retirement obligation would have been $10.1 million. The following
table illustrates the pro forma effect on income (loss) available to common
stockholders and income (loss) per share if the Company had applied the
provisions of SFAS No. 143 in the three months and nine months ended September
30, 2002.

5

Effective January 1, 2002, the Company 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, the Company had computed
amortization on the basis of future gross revenues ("FGR"). 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 first
quarter of 2002. Prior year amounts have been restated to reflect the change in
the accounting principle.

In January 2003, the Financial Accounting Standards Board ("FASB")
issued Interpretation No. 46, "Consolidation of Variable Interest Entities, an
Interpretation of Accounting Research Bulletin No. 51" ("FIN 46"). FIN 46
requires a company to consolidate a variable interest entity ("VIE") if the
company has a variable interest (or combination of variable interests) that is
exposed to a majority of the entity's expected losses if they occur, receives a
majority of the entity's expected residual returns if they occur, or both. In
addition, more extensive disclosure requirements apply to the primary and other
significant variable interest owners of the VIE. This interpretation applies
immediately to VIEs created after January 31, 2003, and to VIEs in which an
enterprise obtains an interest after that date. It is also effective for the
first fiscal year or interim period ending after December 15, 2003, to VIEs in
which a company holds a variable interest that is acquired before February 1,
2003. The Company has concluded it does not have any interests in VIEs and that
this interpretation has no impact on its consolidated financial statements.

In May 2003, the FASB issued Statement of Financial Accounting
Standards No. 150 "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity" ("SFAS No. 150"). SFAS No. 150
establishes standards on how the Company classifies and measures certain
financial instruments with characteristics of both liabilities and equity. The
statement requires that the Company classify as liabilities the fair value of
all mandatorily redeemable financial instruments that had previously been
recorded as equity or elsewhere in the consolidated financial statements. This
statement is effective for financial instruments entered into or modified after
May 31, 2003, and is otherwise effective for all existing financial instruments
beginning in the third quarter of 2003. SFAS No. 150 does not impact the
Company's classification of its convertible preferred stock because the
convertible preferred stock is not mandatorily redeemable as defined by SFAS No.
150.

6

Statement of Financial Accounting Standards No. 141, "Business
Combinations" ("SFAS No. 141") and Statement of Financial Accounting Standards
No. 142, "Goodwill and Intangible Assets" ("SFAS No. 142"), were issued in June
2001 and became effective July 1, 2001 and January 1, 2002, respectively. It is
the Company's understanding that the SEC has questioned other public companies
as to whether they properly adopted the provisions of SFAS No. 141 and SFAS No.
142, with respect to how the costs of acquiring contractual mineral interests in
oil and gas properties should be classified on the balance sheet. It is also the
Company's understanding that the FASB, the SEC and others are engaged in
deliberations on the issue of whether SFAS No. 141 and SFAS No. 142 require that
interests held under oil, gas and mineral leases or other contractual
arrangements be classified as intangible assets or as oil and gas properties. If
such interests were deemed intangible assets, mineral interests for undeveloped
and developed leaseholds would be classified separately from oil and gas
properties on the balance sheet but would be aggregated with oil and gas
properties in the Notes to Condensed Consolidated Financial Statements in
accordance with Statement of Financial Accounting Standards No. 69, "Disclosures
about Oil and Gas Producing Activities." Historically, the Company has included
all oil and gas leasehold interests as part of oil and gas properties. Because
this issue is being deliberated and is unresolved, the Company continues to
include mineral interests as oil and gas properties on its balance sheet.

3. Income Taxes

The Company records deferred tax assets and liabilities to account for
temporary differences arising from events that have been recognized in its
financial statements and will result in future taxable or deductible items in
its tax returns. To the extent deferred tax assets exceed deferred tax
liabilities, at least annually (and more frequently if events or circumstances
change materially), the Company assesses the realizability of its net deferred
tax assets. A valuation allowance is recognized if, at the time, it is
anticipated that some or all of the net deferred tax assets may not be realized.

In making this assessment, management performs an extensive analysis of
the operations of the Company to determine the sources of future taxable income.
Such an analysis consists of a detailed review of all available data, including
the Company's budget for the ensuing year, forecasts based on current as well as
historical prices, and the independent reservoir engineers' reserve report.

The determination to establish and adjust a valuation allowance
requires significant judgment as the estimates used in preparing budgets,
forecasts and reserve reports are inherently imprecise and subject to
substantial revision as a result of changes in the outlook for prices,
production volumes and costs, among other factors. It is difficult to predict
with precision the timing and amount of taxable income the Company will generate
in the future. Accordingly, while the Company's current net operating loss
carryforwards aggregating approximately $200 million have remaining lives
ranging from 10 to 20 years (with the majority having a life in excess of 15
years), management looks at a much shorter time horizon, usually two to three
years, when projecting estimates of future taxable income and making the
determination as to whether the valuation allowance should be adjusted.

During the second quarter of 2002, uncertainty resulting from
relatively low commodity prices and the January 2003 maturity date for the
Company's Senior Notes led management to establish a valuation allowance against
the balance of the Company's deferred tax assets. Since that time, the future
outlook for taxable income has improved significantly. The Company successfully
negotiated an amended and restated credit agreement, allowing it to repay the
Senior Notes. Furthermore, oil and natural gas prices have improved
significantly and are expected to remain relatively high for the foreseeable
future based on existing available information, including current prices quoted
on the New York Mercantile Exchange. Therefore, during the

7

second quarter of 2003, the Company reversed approximately $11 million of the
valuation allowance related to expected taxes on future years' taxable income,
which is reflected as an income tax benefit in the condensed statements of
consolidated operations.

4. Deferred Revenue

In 2001, the Company entered into a production payment transaction
whereby it sold 43.1 Bcfe (38.3 Bcf of gas and 797,000 barrels of oil) to be
delivered over sixty months (the "Production Payment"). Net proceeds from the
Production Payment of approximately $175 million were recorded as deferred
revenue on the Company's balance sheet. Deliveries under the Production Payment
are recorded as oil and gas revenue with a corresponding reduction of deferred
revenue at the average discounted 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.
For the nine months ended September 30, 2003, the Company delivered 5.3 Bcfe and
recorded $21.7 million of oil and gas revenue. This compares to Production
Payment deliveries of 8.7 Bcfe and $35.1 million of oil and gas revenue for the
nine months ended September 30, 2002. Since the sale of the Production Payment
in February 2001 through September 30, 2003, the Company has delivered 32.2
Bcfe, or 75% of the total quantity to be delivered.

5. Redeemable Convertible Preferred Stock

On September 15, 2003, the Company issued a redemption notice to
holders of its Series A Convertible Preferred Stock ("Preferred Stock") in
accordance with provisions in the Certificate of Designation, Preferences,
Rights and Limitations of the Preferred Stock whereby the Company had the option
to redeem the Preferred Stock if the closing price of KCS common stock exceeded
$6.00 per share for 25 out of 30 consecutive trading days. The redemption date
was set as October 15, 2003. Prior to the redemption date, holders of 100% of
the outstanding Preferred Stock exercised their right to convert their preferred
shares into shares of KCS common stock at a conversion price of $3.00 per share
of KCS common stock. As a result of conversions of the Preferred Stock issued in
2001, 2.8 million shares of KCS common stock were issued during the nine months
ended September 30, 2003 and 1.6 million shares of common stock were issued in
October 2003.

8

6. Earnings Per Share

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

Common shares on assumed conversion of Preferred Stock amounting to 5.1
million shares for the nine months ended September 30, 2002 were not included in
the computations of diluted loss per common share nor were assumed conversion of
dividends on Preferred Stock or stock options and warrants since they would be
anti-dilutive.

7. 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 counterparties 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 counterparty 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 counterparty 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

9

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 and eliminate exsposure to margin calls.

In 2003, the Company entered into a series of derivative transactions
designed to protect a portion of the Company's oil and gas production against
possible declines in natural gas prices while enabling the Company to benefit
from price increases. At September 30, 2003, the Company had derivative
instruments covering 2.6 million Mmbtu of gas production for October 2003
through March 2004. The following table sets forth the Company's oil and natural
gas hedged position at September 30, 2003.

In addition to the above, the Company will deliver 1.5 Bcfe for
October through December 2003, 5.2 Bcfe in 2004, 3.9 Bcfe in 2005 and 0.3 Bcfe
in 2006 under the Production Payment sold in February 2001 and amortized
deferred revenue associated therewith at an average price of $4.05 per Mcfe as
discussed in Note 4 to Condensed Consolidated financial Statements.

During 2001, the Company terminated certain derivative contracts that
were in place at the companies acquired in the 1996 acquisition known as the
"Medallion Acquisition" and has been amortizing the loss accumulated in other
comprehensive income ("OCI") into earnings over the original term of the
derivative instruments. During the nine months ended September 30, 2003, $2.7
million, net of tax, was credited to OCI. As of September 30, 2003, $5.8
million, net of tax, remains in accumulated other comprehensive income and will
be amortized against earnings through 2005 ($0.9 million during the remainder of
2003, $2.9 million in 2004 and $2.0 million in 2005). During the nine months
ended September 30, 2003, unrealized derivative gains and losses were charged to
OCI and will be reclassified against earnings when the hedged transaction
occurs. The amounts charged to OCI and the ineffective portion of these
derivatives were immaterial.

8. Supplemental Cash Flow Information

The Company considers all highly liquid financial instruments with a
maturity of three months or less when purchased to be cash equivalents. Interest
paid (net of capitalized interest) for the nine months ended September 30, 2003
was $17.0 million. Income tax payments totaling $0.7 million were made in the
nine-month period ended September 30, 2003 while no income tax was paid in the
nine-month period ended September 30, 2002.

In connection with the adoption of SFAS No. 143, the Company recorded a
non-cash increase to oil and gas properties of $10.2 million, a non-cash
increase in liabilities of $11.1 million and a non-cash charge of

10

$0.9 million as a cumulative effect of accounting change. During the nine months
ended September 30, 2003, non-cash additions to oil and gas properties as a
result of recognizing asset retirement obligations for new wells under SFAS No.
143 was $0.3 million. Other non-cash additions to oil and gas properties netted
to $5.1 million with increases in accrued drilling costs offset by increased
prepaid drilling costs.

9. Credit Agreement

On January 14, 2003, the Company amended and restated its credit
agreement (the "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 periodic 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. On September 30, 2003, $70.0 million
was outstanding under the Credit Agreement, the weighted average interest rate
was 7.5% and $18.0 million was available for additional Company borrowings. 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 Credit Agreement
have been recorded as deferred charges and are being amortized as interest
expense over the life of the Credit Agreement. Certain other fees are also
payable under the Credit Agreement 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 the Company's
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. At September 30, 2003, the Company was in compliance with all
covenants in the Credit Agreement.

10. Stock Compensation

As permitted under Statement of Financial Accounting Standards No. 123,
"Accounting for Stock-Based Compensation", as amended ("SFAS No. 123"), 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 stockholders and
earnings (loss) per share if the Company had applied the fair value recognition
provision of SFAS No. 123 to stock options.

11

11. Litigation

Environmental Suits

Medallion California Properties Company ("MCPC") was 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 (collectively, "Kerr-McGee"). Newhall filed the case in Los Angeles
County, California, Superior Court under Cause Number BC244203 and sought
damages from Kerr-McGee and Medallion for alleged environmental contamination
and surface restoration on lands in Los Angeles County, California covered by an
Oil & Gas Lease dated June 13, 1935, from Newhall, as Lessor, to Barnsdall Oil
Company (a predecessor of Kerr-McGee), as Lessee (the "RSF Lease"). In addition,
Newhall sought a declaration that it was entitled to terminate MCPC's leasehold
interest in the lands covered by the RSF Lease, or at least as to those portions
of the RSF Lease in which Newhall claimed MCPC was in default under the terms of
the lease.

Certain of the respective rights and obligations of Kerr-McGee and MCPC
respecting the RSF Lease (as well as rights and obligations of entities that
previously owned the stock of MCPC and that provided certain indemnities to the
Company in connection with its acquisition of MCPC and MCPC's parent company)
had been previously determined in a case in the 234th Judicial District Court of
Harris County, Texas under Cause Number 1999-45998. As part of the final
judgment in that case and under a Compromise and Settlement Agreement dated
October 19, 2001, executed as part of the resolution of the case, MCPC was found
to be entitled to certain indemnifications for environmental contamination and
surface restoration on the lands covered by the RSF Lease.

The case brought by Newhall was settled in October 2003 and the parties
have released each other and have each dismissed their respective claims with
prejudice to their refiling. Under the terms of the Settlement Agreement with
respect to this case, MCPC paid approximately $2 million - 90% of which was
provided by its indemnitor and 10% of which was provided by MCPC. In addition,
MCPC agreed to conduct certain cleanup and surface restoration activities in
accordance with the lease terms on the lands covered by the RSF Lease upon the
earlier of abandonment of the lease or Lessor's purchase of the lease, wells and
related equipment as Lessor is entitled to do under the terms of the RSF Lease.
Also, MCPC agreed to deposit 15% of its net cash flow from the RSF Lease into an

12

account to secure performance of its cleanup and surface restoration
obligations. The amount of the account to secure performance is capped at $2
million and, at such time as MCPC timely performs its obligation, the $2 million
will be returned to MCPC. Lastly, the RSF Lease was amended in certain respects
and, as so amended, was declared to be in full force and effect.

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.

12. Comprehensive Income

The following table presents the components of comprehensive income
(loss) for the three months and nine months ended September 30, 2003 and 2002:

13

ITEM 2. 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 unaudited
condensed consolidated financial statements (including the notes thereto)
included elsewhere in this quarterly report on Form 10-Q.

FORWARD-LOOKING STATEMENTS

The information discussed in this quarterly report on Form 10-Q
includes "forward-looking statements" within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange
Act of 1934, as amended. All statements, other than statements of historical
fact, 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 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 of, 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 fires, well blowouts, 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 in the Company's Annual Report on Form 10-K for the year
ended December 31, 2002, and from time to time in the Company's other filings
with the Securities and Exchange Commission.

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, whether as a result of new
information, subsequent events or circumstances, changes in expectations or
otherwise.

GENERAL

Our main objective in 2002 was to position the Company to meet the
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.

14

On January 14, 2003, we completed the arrangements necessary to amend
and restate our existing credit agreement (the "Credit Agreement") with a group
of institutional lenders. The Credit Agreement provides $90.0 million of
borrowing capacity, $40.0 million in the form of a term loan and $50.0 million
in the form of 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 Credit Agreement.

With the completion of the financing, we accelerated our drilling
program in 2003 resulting in increased production and reserves. We believe that
the Company is positioned to capitalize on the current strong natural gas price
environment, to focus on developing our prospect inventory to grow reserves and
production in our core areas and to further reduce debt per thousand cubic feet
equivalent (Mcfe).

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

RESULTS OF OPERATIONS

Income available to common stockholders for the three months ended
September 30, 2003 was $11.4 million, or $0.30 per basic share ($0.28 per
diluted share), compared to $3.6 million, or $0.10 per basic share ($0.09 per
diluted share), for the three months ended September 30, 2002. This increase was
primarily attributable to higher natural gas and oil prices and higher working
interest production which reflects our successful 2003 drilling program.

For the nine months ended September 30, 2003, income before income
taxes and cumulative effect of accounting change was $42.1 million, compared to
$6.8 million for the nine months ended September 30, 2002. This increase was
primarily attributable to higher natural gas and oil prices and the sale of
emission reduction credits, partially offset by decreased oil and gas production
due to the expiration of our Volumetric Production Payment (VPP) program and the
sale of certain non-core oil and gas properties in 2002. Income tax benefit for
the nine months ended September 30, 2003 was $11.7 million compared to income
tax expense of $14.1 million for the same period in 2002 due to changes in our
valuation allowance against net deferred tax assets (see Note 3 to Condensed
Consolidated Financial Statements). The cumulative effect of an accounting
change was $0.9 million, or $0.02 per basic and diluted share, for the nine
months ended September 30, 2003 as a result of the adoption of Financial
Accounting Standards Board Statement No. 143, "Accounting for Asset Retirement
Obligations" ("SFAS No. 143"). For the nine months ended September 30, 2002, the
cumulative effect of accounting change was $6.2 million, or $0.17 per basic and
diluted share, which reflected the change from the future gross revenue method
of accounting for the amortization of capitalized costs related to oil and gas
properties to the unit-of-production method. See Note 2 to Condensed
Consolidated Financial Statements for more information regarding these
accounting changes. Income available to common stockholders for the nine months
ended September 30, 2003 was $52.2 million, or $1.37 per basic share ($1.28 per
diluted share), compared to a loss of $14.3 million, or $0.40 per basic and
diluted share, for the nine months ended September 30, 2002.

15

The following table presents production, average realized prices and
revenues associated with the sale of natural gas, oil, and natural gas liquids
for the three and nine month periods ended September 30, 2003 and 2002.

Notes:

(a) Production includes 1,594 and 5,314 million cubic feet equivalent (Mmcfe),
respectively, for the three and nine months ended September 30, 2003
compared to 2,671 and 8,715 Mmcfe, respectively, for the three and nine
months ended September 30, 2002, dedicated to the Production Payment sold
in February 2001. See Note 4 to Condensed Consolidated Financial Statements
for more information on the Production Payment.

(b) Includes the effects of volumes delivered under the Production Payment sold
in February 2001 and hedging activities, including terminated derivative
contracts associated with the Medallion Acquisition. See Notes 4 and 7 to
Condensed Consolidated Financial Statements for more information on the
Production Payment and the Company's hedging activities.

Gas revenue

For the three months ended September 30, 2003, gas revenue increased
$10.8 million, to $34.9 million, from $24.1 million for the same period in 2002
due to a 41% increase in average realized natural gas prices and a 6% increase
in working interest production. This production increase reflects our successful
2003 drilling program which more than offset the impact of properties sold in
2002.

16

For the nine months ended September 30, 2003, gas revenue increased
$27.5 million, to $100.3 million, from $72.8 million for the same period in 2002
due to a 58% increase in average realized natural gas prices offset by a 13%
decrease in production. The production decline was due to the expiration of VPPs
and the sale of non-core oil and gas properties in 2002.

Oil and liquids revenue

For the three months ended September 30, 2003, oil and liquids revenue
decreased $0.1 million, to $6.2 million, from $6.3 million for the same period
in 2002, due to a 15% decrease in production offset by a 16% increase in the
weighted average price. For the nine months ended September 30, 2003, oil and
liquids revenue increased $1.2 million, to $18.9 million, from $17.7 million for
the same period in 2002 due to a 31% increase in the weighted average price
offset by a 19% decrease in production. The decrease in oil and liquids
production in 2003 was primarily due to the sale of non-core properties in 2002
and the natural declines of producing oil wells as our 2003 drilling program
focused primarily on gas producing properties.

Other, net

Other, net decreased from $0.1 million for the three months ended
September 30, 2002 to a net cost of $0.4 million for the same period in 2003.
The decrease is primarily attributable to gas marketing and transportation
activities incidental to our oil and gas operations. For the nine months ended
September 30, 2003, other, net was $4.7 million compared to a net cost of $1.0
million for the nine months ended September 30, 2002. The increase in other, net
was primarily related to the sale of emission reduction credits.

Lease operating expenses

Lease operating expenses increased $0.9 million, to $6.8 million, for
the three months ended September 30, 2003, from $5.9 million for the same period
in 2002. For the nine months ended September 30, 2003, lease operating expense
increased $0.5 million, to $19.8 million, from $19.3 million for the same period
in 2002. The increases are primarily attributable to a higher level of drilling
and workover activity on oil and gas wells in 2003.

Production taxes

Production taxes, which are generally based on a percentage of revenue
(excluding VPP revenue), increased $0.7 million, to $2.2 million, for the three
months ended September 30, 2003, compared to $1.5 million for the same period in
2002. This increase is primarily attributable to higher average natural gas and
oil prices and the increase in working interest production. For the nine months
ended September 30, 2003, production taxes increased $1.6 million, to $6.0
million, compared to $4.4 million for the same period in 2002. This increase is
primarily attributable to higher oil and gas revenue associated with higher
average realized prices.

General and administrative expenses

General and administrative expenses ("G&A") for the three months ended
September 30, 2003 were $2.0 million compared to $2.4 million for the same
period in 2002. For the nine months ended September 30, 2003, G&A were $5.7
million compared to $6.3 million for the same period in 2002. The decreases in
the 2003 three- and nine-month periods were primarily due to lower labor costs
associated with a reduced work force, partially offset by higher incentive
compensation expense resulting from improved operating results.

Stock compensation

Stock compensation reflects the non-cash expense associated with stock
options issued in 2001 that are subject to variable accounting in accordance
with Financial Accounting Standards Board ("FASB")

17

Interpretation No. 44, "Accounting for Certain Transactions Involving Stock
Compensation" and the non-cash expense associated with the amortization of
restricted stock grants. Under variable accounting for stock options, the amount
of expense recognized during a reporting period is directly related to the
movement in the market price of KCS common stock during that period. For the
three months ended September 30, 2003, stock compensation was $0.6 million
compared to $0.2 million for the same period in 2002. For the nine months ended
September 30, 2003, stock compensation was $1.0 million compared to $0.7 million
for the same period in 2002. The increases in stock compensation in the
current-year periods reflect the increasing market price of KCS common stock.

Accretion of asset retirement obligation

Accretion of our asset retirement obligation was $0.3 million and $0.8
million for the three-month and nine-month periods ended September 30, 2003,
respectively. Effective January 1, 2003, we adopted Financial Accounting
Standards Board Statement No. 143, "Accounting for Asset Retirement Obligations"
("SFAS No. 143"). See Note 2 to Condensed Consolidated Financial Statements for
more information regarding this accounting change.

Depreciation, depletion and amortization

Depreciation, depletion and amortization ("DD&A") expense for the nine
months ended September 30, 2003, decreased $3.1 million, to $34.8 million, from
$37.9 million for the same period in 2002. The decrease is primarily
attributable to reduced production as a result of the expiration of VPPs and
non-core property sales in 2002.

Interest expense

Interest expense for the nine months ended September 30, 2003 was $13.8
million compared to $14.3 million for the same period in 2002 primarily due to
lower average outstanding debt in 2003.

Income Taxes

For the nine months ended September 30, 2003, income tax benefits were
$11.7 million compared to an income tax expense of $14.1 million for the same
period in 2002.

We record deferred tax assets and liabilities to account for temporary
differences arising from events that have been recognized in our financial
statements and will result in future taxable or deductible items in our tax
returns. To the extent our deferred tax assets exceed deferred tax liabilities,
at least annually (and more frequently if events or circumstances change
materially) we assess the realizability of our net deferred tax assets. A
valuation allowance is recognized if, at the time, it is anticipated that some
or all of our net deferred tax assets may not be realized. See Note 3 to
Condensed Consolidated Financial Statements for more information regarding
income taxes.

During the second quarter of 2002, we increased the valuation allowance
on the Company's deferred tax assets, which are primarily related to tax net
operating loss carryforwards, by $15.9 million, thereby reducing to zero the
carrying amount of net deferred tax assets with a corresponding non-cash charge
to income tax expense. 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.

18

In early 2003, we negotiated an amended and restated Credit Agreement
with a group of institutional lenders and repaid the remaining Senior Note
obligations. In addition, natural gas and oil prices improved significantly and
we generated significant income during the first half of 2003, thereby utilizing
a portion of our deferred tax assets. During the second quarter of 2003, as a
result of the substantial improvement in our financial condition and current and
projected profitability levels over the next several years, we reversed $11
million of our valuation allowance related to the tax effects on future gross
taxable income which is reflected as an income tax benefit in the statement of
operations.

LIQUIDITY AND CAPITAL RESOURCES

Our main objective in 2002 was to position the Company to meet the
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 ("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. On September 30,
2003, $70.0 million was outstanding under the Credit Agreement, the weighted
average interest rate was 7.5% and $18.0 million was available for additional
Company borrowings.

With the completion of the financing, we accelerated our drilling
program in 2003 resulting in increased production and reserves. We believe that
the Company is positioned to capitalize on the current strong natural gas price
environment, to focus on developing our prospect inventory to grow reserves and
production in our core areas and to further reduce debt per Mcfe.

Our primary cash reqiurements are for exploration, development and
acquisition of oil and gas properties, operating expenses and debt service. We
fund our exploration and development activities primarily through internally
generated cash flows.

In response to our successful drilling program and increased cash flow,
we increased our 2003 budget for investments in oil and gas properties to $75
million in the third quarter of 2003.

On September 16, 2003, the Company, along with two of its operating
subsidiaries, KCS Resources, Inc. and Medallion California Properties Company,
filed a $200 million universal shelf registration statement with the Securities
and Exchange Commission covering the issuance of an unspecified amount of
senior unsecured debt securities, senior subordinated debt securities, common
stock, preferred stock, warrants, units or guarantees, or a combination
thereof. The Company may, in one or more offerings, offer and sell its common
stock, preferred stock, warrants and units. The Company may also, in one or
more offerings, offer and sell its senior unsecured and senior subordinated
debt securities, which may be fully and unconditionally guaranteed by KCS
Resources, Inc. and Medallion California Properties Company.

The Company recently announced a proposed public offering of 6,000,000
shares of its common stock pursuant to its shelf registration statement. No
assurances can be given that the proposed offering will be completed.

The Company believes that cash on hand, net cash generated from
operations and unused committed borrowing capacity under the Credit Agreement
will be adequate to fund its capital expenditure program and satisfy its
liquidity needs. In the future, the Company may also utilize various financing
sources, including the issuance of debt or equity securities. The Company's
ability to complete future debt and equity offerings and the timing of any such
offerings will depend upon various factors including prevailing market
conditions, interest rates and the Company's financial condition.

Cash flow from operating activities

Net cash provided by operating activities for the nine months ended
September 30, 2003 was $53.3 million compared to $4.1 million during the same
period in 2002. The improvement in our cash flow in 2003 was primarily due to
higher realized oil and natural gas prices and substantially less production
dedicated to repayment of the Production Payment discussed in Note 4 to
Condensed Consolidated Financial Statements.

19

The net change in trade accounts receivable reflects the higher natural gas and
oil price environment in 2003 and the timing of cash receipts. The net change in
accounts payable and accrued liabilities is primarily attributable to the
significant increase in our drilling program in the current year.

Cash flow from investing activities

For the nine months ended September 30, 2003, net cash used in
investing activities was $62.4 million, of which $61.8 million was invested in
oil and gas properties, compared to net cash used in investing activities of
$6.9 million for the same period in 2002. For the 2002 nine-month period, the
Company invested $36.4 million in oil and gas properties and sold $29.4 million
of non-core properties.

New Accounting Principles

Effective January 1, 2003, we adopted SFAS No. 143 which 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. Upon adoption of SFAS No. 143, our net
property, plant and equipment was increased by $10.2 million, an additional
asset retirement obligation of $11.1 million (primarily for plugging and
abandonment costs of oil and gas wells) was recorded and a $0.9 million charge,
net of tax against net income (or a $0.02 loss per basic and diluted share) was
reported in the first quarter of 2003 as a cumulative effect of a change in
accounting principle. Subsequent to adoption, the effect of the change in
accounting principle in the nine months ended September 30, 2003 was immaterial.

Effective January 1, 2002, we 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, we had computed amortization on the
basis of future gross revenue ("FGR"). 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, we 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 first quarter of 2002.

In January 2003, the FASB issued Interpretation No. 46, "Consolidation
of Variable Interest Entities, an Interpretation of Accounting Research Bulletin
No. 51" ("FIN 46"). FIN 46 requires a company to consolidate a variable interest
entity ("VIE") if the company has a variable interest (or combination of
variable interests) that is exposed to a majority of the entity's expected
losses if they occur, receives a majority of the entity's expected residual
returns if they occur, or both. In addition, more extensive disclosure
requirements apply to the primary and other significant variable interest owners
of the VIE. This interpretation applies immediately to VIEs created after
January 31, 2003, and to VIEs in which an enterprise obtains an interest after
that date. It is also effective for the first fiscal year or interim period
ending after December 15, 2003, to VIEs in which a company holds a variable
interest that is acquired before February 1, 2003. The Company has concluded
that it does not have any interest in VIEs and that this interpretation has no
impact on its consolidated financial statements.

In May 2003, the FASB issued Statement of Financial Accounting Standards
No. 150 "Accounting for Certain Financial Instruments with Characteristics of
both Liabilities and Equity" ("SFAS No. 150"). SFAS No. 150 establishes
standards on how the Company classifies and measures certain financial
instruments with

20

characteristics of both liabilities and equity. The statement requires that the
Company classify as liabilities the fair value of all mandatorily redeemable
financial instruments that had previously been recorded as equity or elsewhere
in the consolidated financial statements. This statement is effective for
financial instruments entered into or modified after May 31, 2003, and is
otherwise effective for all existing financial instruments beginning in the
third quarter of 2003. SFAS No. 150 does not impact the Company's classification
of its convertible preferred stock because the convertible preferred stock is
not mandatorily redeemable as defined by SFAS No. 150.

Statement of Financial Accounting Standards No. 141, "Business
Combinations" ("SFAS No. 141") and Statement of Financial Accounting Standards
No. 142, "Goodwill and Intangible Assets" ("SFAS No. 142"), were issued in June
2001 and became effective July 1, 2001 and January 1, 2002, respectively. It is
the Company's understanding that the SEC has questioned other public companies
as to whether they properly adopted the provisions of SFAS No. 141 and SFAS No.
142 with respect to how the costs of acquiring contractual mineral interests in
oil and gas properties should be classified on the balance sheet. It is also the
Company's understanding that the FASB, the SEC and others are engaged in
deliberations on the issue of whether SFAS No. 141 and SFAS No. 142 require that
interests held under oil, gas and mineral leases or other contractual
arrangements be classified as intangible assets or as oil and gas properties. If
such interests were deemed intangible assets, mineral interests for undeveloped
and developed leaseholds would be classified separately from oil and gas
properties on the balance sheet but would be aggregated with oil and gas
properties in the Notes to Consolidated Financial Statements in accordance with
SFAS No. 69, "Disclosures about Oil and Gas Producing Activities." Historically,
the Company has included all oil and gas leasehold interests as part of oil and
gas properties. Because this issue is being deliberated and is unresolved, the
Company continues to include mineral interests as oil and gas properties on its
balance sheet.

21

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

COMMODITY PRICE RISK. The Company's major market risk exposure is to
oil and gas prices, which have historically been volatile and unpredictable.
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. See Note 7 to
Condensed Consolidated Financial Statements for more information on the
Company's use of derivative instruments. While these derivative instruments 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 September 30, 2003, the Company had derivative instruments covering
2.6 million Mmbtu of gas production for October 2003 through March 2004. The
following table sets forth the Company's oil and natural gas hedged position at
September 30, 2003.

In addition to the above, the Company will deliver 1.5 Bcfe for October
through December 2003, 5.2 Bcfe in 2004, 3.9 Bcfe in 2005 and 0.3 Bcfe in 2006
under the Production Payment sold in February 2001 and amortize deferred revenue
associated therewith at an average price of $4.05 per Mcfe as discussed in Note
4 to Condensed Consolidated Financial Statements.

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 $125.0 million at 8.9% on September 30, 2003
and $193.7 million at 9.6% on September 30, 2002. The Company's variable rate
debt and weighted average interest rate was $70.0 million at 7.6% on September
30, 2003 and $10.7 million at 4.1% on September 30, 2002. The impact on annual
cash flow of a one percent change in the interest rate on the Company's current
variable rate debt would be approximately $0.7 million.

22

ITEM 4. CONTROLS AND PROCEDURES.

The Company carried out an evaluation, under the supervision and with
the participation of its management, including the Company's Chief Executive
Officer and Chief Financial Officer, of the effectiveness of the design and
operation of the Company's disclosure controls and procedures as of the end of
the period covered by this report, pursuant to Exchange Act Rule 13a-15. Based
upon that evaluation, the Company's Chief Executive Officer and Chief Financial
Officer concluded that the Company's disclosure controls and procedures are
effective in timely alerting them to material information relating to the
Company (including its consolidated subsidiaries) required to be included in the
Company's periodic Exchange Act reports.

There have been no changes in the Company's internal control over
financial reporting that occurred during the Company's most recent fiscal
quarter that have materially affected, or are reasonably likely to materially
affect, the Company's internal control over financial reporting.

23

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

Reference is made to Note 11 to Condensed Consolidated Financial
Statements included herein.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.

(a) Exhibits:

10.1 Fourth Amendment to the Amended and Restated Credit Agreement
dated as of September 30, 2003 by and among KCS Energy, Inc.,
the lenders from time to time thereto, Foothill
CapitalCorporation, as collateral and administrative agent,
and Highbridge/Zwirn Special Opportunities Fund, L.P., as lead
arranger.

31.1 Certification of James W. Christmas, Chairman and Chief
Executive Officer, pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.

31.2 Certification of Joseph T. Leary, Vice President and Chief
Financial Officer, pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.

32.1 Certification of James W. Christmas, Chairman and Chief
Executive Officer, pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.

32.2 Certification of Joseph T. Leary, Chief Financial Officer,
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.

(b) Reports on Form 8-K.

The Company furnished a report on Form 8-K on August 11, 2003 under
Item 12, Results of Operations and Financial Condition, reporting the
issuance of a press release announcing the Company's operating results
for the three and six months ended June 30, 2003.

The Company filed a report on Form 8-K on September 15, 2003 under Item
5, Other Events, reporting the issuance of a press release announcing
the Company's issuance of a redemption notice to the holders of its
Series A Convertible Preferred Stock.

24

SIGNATURES

Pursuant to the requirements 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.

Date: November 11, 2003 /s/ Frederick Dwyer
----------------------------------------
Frederick Dwyer
Vice President, Controller and Secretary
(Principal Accounting Officer)

25

EXHIBIT INDEX