KCS ENERGY INC - 10-K Annual Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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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, 2004
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
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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, SUITE 1200, 77056
HOUSTON, TEXAS (Zip Code)
(Address of principal executive offices)

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:
NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [X] No [ ]
The aggregate market value of the 46,513,928 shares of the registrant's
common stock, par value $0.01 per share, held by non-affiliates of the
registrant at the $13.32 closing price on June 30, 2004 (the last business day
of the registrant's most recently completed second fiscal quarter) was
$619,565,521.
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.
The number of shares of the registrant's common stock, par value $0.01 per
share, outstanding as of the close of business on March 10, 2005: 49,777,229.

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's Proxy Statement for the Annual Meeting of
Stockholders to be held on May 26, 2005 are incorporated by reference into Part
III of this annual report on Form 10-K. Except with respect to information
specifically incorporated by reference in this Form 10-K, the Proxy Statement
for the Annual Meeting of Stockholders is not deemed to be filed as part hereof.
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TABLE OF CONTENTS

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Quantities of natural gas are expressed in this annual report on Form 10-K
in terms of thousand cubic feet (Mcf), million cubic feet (MMcf) or billion
cubic feet (Bcf). Natural gas sales volumes and amounts hedged under derivative
contracts may be expressed in terms of one million British thermal units
(MMBtu), which is equal to one Mcf containing 1,000 British thermal units (Btu)
per cubic foot. The average Btu content of our natural gas reserves is in excess
of 1,000 Btu per cubic foot. Oil and natural gas liquids are quantified in terms
of barrels (bbls) and thousands of barrels (Mbbls). Oil and natural gas liquids
are compared with natural gas in terms of thousand cubic feet equivalent (Mcfe),
million cubic feet equivalent (MMcfe) and billion cubic feet equivalent (Bcfe).
For purposes of comparing oil and natural gas liquids to natural gas on a per
unit equivalent basis, one barrel of oil or natural gas liquids is the energy
equivalent of six Mcf of natural gas. With respect to information relating to
our working interest in wells or acreage, "net" oil and gas wells or acreage is
determined by multiplying gross wells or acreage by our working interest in the
oil and gas wells or acreage. Unless otherwise specified, all references to
wells and acres are gross. Working interest, or "WI", is the net percentage
ownership interest in a well that gives the owner the right to drill, produce
and conduct operating activities on the property and a share of the production.

References to "proved reserves" in this annual report on Form 10-K refer to
the estimated quantities of crude oil, natural gas and natural gas liquids 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 term "proved developed reserves" refers to reserves
that can be expected to be recovered through existing wells with existing
equipment and operating methods. The term "proved undeveloped reserves" refers
to reserves that are expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major expenditure is required
for recompletion. The term "recompletion" refers to the completion for
production of an existing wellbore in another formation from that in which the
well has previously been completed. The term "productive well" refers to a well
that is producing oil or natural gas or that is capable of production. The term
"workover" refers to operations on a producing well to restore or increase
production from an existing formation or recomplete to a new formation.

This annual report on Form 10-K refers to the pre-tax present value of
estimated future net revenues, or "PV-10 value," of our oil and natural gas
reserves. The PV-10 value of reserves refers to the pre-tax 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 10%. In accordance with applicable
requirements of the Securities and Exchange Commission, the PV-10 value is
generally based on prices and costs as of the date of the estimate. In contrast,
the actual future prices and costs may be materially higher or lower. Please do
not interpret the PV-10 values as the current market value of our properties'
estimated oil and natural gas reserves. The standardized measure of discounted
future net cash flows, or "Standardized Measure", differs from PV-10 value
because Standardized Measure includes the present value effect of future income
taxes.

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PART I

ITEM 1. BUSINESS.

GENERAL

KCS Energy, Inc., a Delaware corporation, is an independent oil and gas
company engaged in the acquisition, exploration, development and production of
natural gas and crude oil. Our properties are primarily located in the
Mid-Continent and onshore Gulf Coast regions of the United States. We also have
interests in producing properties in Michigan, California, Wyoming and offshore
Gulf of Mexico. As of December 31, 2004, our oil and natural gas properties were
estimated to have net proved reserves of approximately 328 Bcfe with a PV-10
value of $814 million. Approximately 88% of our net proved reserve base was
natural gas and approximately 76% was classified as proved developed. We operate
approximately 84% of our proved oil and natural gas reserve base. The following
table sets forth the estimated quantities of proved reserves attributable to our
principal operating regions as of December 31, 2004.

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(1) Includes Michigan and Wyoming

(2) Includes California

In 2004, we produced an average of 109.2 MMcfe per day compared to 95.2
MMcfe per day in 2003. We plan to continue growing our reserves and production
through a balanced investment program in low-risk exploitation activities in the
Mid-Continent and Gulf Coast regions and moderate-risk, higher potential
exploration drilling programs primarily in the onshore Gulf Coast region.

We are a publicly-owned company whose stock is traded on the New York Stock
Exchange under the symbol "KCS." We were incorporated in Delaware in 1988 in
connection with the spin-off of the non-utility businesses of a New Jersey-based
natural gas distribution company. Our principal executive offices are located at
5555 San Felipe Road, Suite 1200, Houston, Texas 77056. Our telephone number is
(713) 877-8006. Unless the context otherwise requires, the terms "KCS," "we,"
"our" or "us" refer to KCS Energy, Inc. and its subsidiaries.

2004 HIGHLIGHTS

The year ended December 31, 2004 was an outstanding year for us. We drilled
a record 130 wells during 2004, of which 126 were completed, resulting in a 97%
success rate and significantly increased production and reserves. In 2004, gross
production increased 15%, to 40 Bcfe, while net production after production
payment delivery obligations, that do not contribute to cash flow from operating
activities, increased 25% compared to 2003. Natural gas and oil reserves
increased 22% to 328 Bcfe as of December 31, 2004 compared to 268 Bcfe as of
December 31, 2003. In total, we added 94.5 Bcfe of proved reserves during 2004,
of which 97% was through the drill bit. Total oil and gas capital expenditures
were $166.7 million.

In 2004, we continued to execute our strategies of focusing on low-risk
development and exploitation drilling in our core operating areas and to commit
approximately 15% of our capital expenditure budget to moderate-risk,
higher-potential exploration prospects primarily in the onshore Gulf Coast
region. In 2005, we plan to commit approximately 15% to 20% of our capital
expenditure budget to such exploration projects. We continue to focus primarily
on natural gas prospects. We have continued our disciplined hedging program
designed to protect against price declines while participating to a large extent
in future price increases. In this

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way, we endeavor to ensure that we generate a sufficient level of cash flow to
carry out a capital expenditure program sufficient to at least replace our
expected production and still benefit if prices rise.

We further strengthened our financial condition in 2004 and provided
additional financial flexibility by completing a $175 million senior notes
offering. The new senior notes bear interest at an annual rate of 7 1/8% and
mature in 2012. The proceeds of this issuance were used to redeem our $125
million 8 7/8% senior subordinated notes due 2006, including an early redemption
premium, and to repay the $22 million outstanding under our bank credit
facility. As of December 31, 2004, we had $6.6 million of cash on hand and $100
million of unused committed borrowing capacity under our bank credit facility.
We plan to maintain a conservative capital structure. Please read Note 6 to our
Consolidated Financial Statements for more information regarding our senior
notes and our bank credit facility.

We believe that the steps taken during 2004, along with our multi-year
drilling prospect inventory, position us to increase production and reserves in
2005 and beyond.

COMPETITIVE STRENGTHS AND BUSINESS STRATEGIES

We intend to continue to increase production and reserves to optimize
stockholder value by executing the following strategies:

- Focus on Natural Gas -- As of December 31, 2004, our proved reserves were
88% natural gas. We believe that the future need for natural gas in the
United States will continue to grow and that natural gas is better
insulated from the price volatility associated with global geopolitical
instability. In addition, North American supplies of natural gas have
been declining in recent years. Lease operating expenses associated with
natural gas properties are also typically less than oil properties, which
allows us to maintain our low per-unit cost structure.

- Grow Through the Drill Bit -- We believe our personnel possess
exceptional knowledge in identifying, drilling and stimulating tight rock
formations. We also think that the economics of drilling self-generated
prospects are superior to those of acquiring reserves. Over the last
three years, we have added 217 Bcfe to our reserves, of which 95% were
through the drill bit. With our inventory of drilling prospects, we
believe that we are well-positioned to continue growing our reserves and
production.

- Exploit Our Large Inventory of Drilling Projects -- We have a significant
inventory of future drilling locations in targeted areas. Generally,
these locations range in depth from 5,000 feet to 13,000 feet and are low
risk opportunities. Most of the locations are step-out or extension wells
from existing production.

- Concentrate in Core Areas -- We concentrate our drilling programs
predominately in the Mid-Continent and Gulf Coast regions. Operating in
concentrated areas helps us to better control our overhead by enabling us
to manage a greater amount of acreage with fewer employees and minimize
incremental costs of increased drilling and production. Our strategy of
targeting our operations in relatively concentrated areas permits us to
more efficiently capitalize on our base of geological, engineering,
exploration, development, completion and production experience in these
regions. The areas we produce generally have high price realizations
relative to benchmark prices for natural gas production and favorable
operating costs.

- Control Drilling and Production Operations -- We operate approximately
84% of our proved oil and natural gas reserve base as of December 31,
2004. We prefer to generate and retain operating control over our own
prospects rather than owning non-operated interests. This allows us to
more effectively control operating costs, the timing and plans for future
development, the level of drilling and the marketing of production on the
properties. In addition, as an operator, we receive reimbursements for
overhead from other working interest owners, which reduces our general
and administrative expenses. During the year ended December 31, 2004, we
controlled the drilling operations on 93 of the 130 wells in which we
participated.

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- Search for Complimentary Acquisitions -- We proactively search for
acquisitions in our core areas to expand our acreage position and
drilling inventory. Two recent examples of this were the O'Connor Ranch
acreage acquisition in the third quarter of 2004 that compliments our
south Texas drilling program and our recently announced acquisition of
properties in our North-Louisiana-East Texas core operating area. Please
read Note 15 to our Consolidated Financial Statements for more
information regarding our recently announced acquisition which is
currently scheduled to close in mid-April 2005.

- Employ Experienced Technical Professionals -- We employ oil and gas
professionals, including geophysicists, petrophysicists, geologists,
petroleum engineers, production and reservoir engineers and landmen who
have an average of approximately 25 years of experience in their
technical fields. We continually apply our extensive in-house expertise
and advanced technologies to benefit our drilling and completion
operations.

- Maintain Financial Flexibility -- The timing of most of our capital
expenditures is discretionary. Consequently, we have a significant degree
of flexibility to adjust the level of expenditures according to market
conditions. We currently anticipate spending approximately $190 million,
exclusive of acquisitions, on capital projects in 2005. We expect that
these projects will be funded primarily with internally generated cash
flow.

- Control Risk -- We allocate approximately 80% of our capital on an annual
basis to low risk development and exploitation projects and the remainder
to moderate risk exploration plays. We set limits on the amount of
capital we will invest in any one exploration project. We hedge a portion
of our oil and natural gas to protect against downward price swings, and
we control costs closely to ensure the best possible profit margins. In
addition, we turnkey our drilling operations where economic in order to
reduce drilling risk.

CORE OPERATING AREAS

MID-CONTINENT

In the Mid-Continent region, we concentrate our drilling programs primarily
in north Louisiana, east Texas, Oklahoma (Anadarko and Arkoma basins) and west
Texas. Our Mid-Continent operations provide us with a solid base for production
and reserve growth. We plan to continue to exploit areas within the various
basins that require low-risk exploitation wells for additional reservoir
drainage. Our exploitation wells are generally step-out and extension type wells
with moderate reserve potential. During 2004, we drilled 101 wells in this
region with a success rate of 97%. In 2005, we plan to drill 90 to 115 wells in
this region, approximately half of which are planned in the Elm Grove Field
which is our largest field. We will also pursue drilling in the Sawyer Canyon,
Joaquin, Terryville and Talihina fields and have budgeted $20 million to
commence development of the properties being acquired in April 2005.

- Elm Grove Field -- Located in Bossier Parish of north Louisiana,
production from this field comes from the Hosston and Cotton Valley
formations. These zones are composed of low permeability rocks that
require large fracture stimulation treatments to produce. We operate nine
sections with WI ranging from 89 to 100%. We also have lesser interests
ranging from 5% to 82% in six other adjacent sections. In 2004, the field
contributed about 26% of our net production. As of December 31, 2004, we
had 116 Bcfe of proved reserves in this field that accounted for
approximately 38% of our PV-10 value.

We began a development program in late 2002 that included the drilling of
six wells. In 2003, we drilled 19 wells and in 2004 41 additional wells,
all of which were successful. This drilling activity increased gross
operated production from 6 MMcfe per day in 2002 to over 45 MMcfe per day
as of December 31, 2004. In 2005, we plan to drill 45 to 50 proved
undeveloped and step-out locations to continue growing production and
reserves.

- Sawyer Canyon Field -- Our second largest field, contributing
approximately 11% of our net production in 2004, is located in Sutton
County, west Texas. We are actively producing and developing on lands
comprising approximately 33,500 acres. Over the last several years, we
have been conducting drilling programs targeting shallow Canyon sandstone
formations. We have a 92% to 100% WI in most
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of the areas we are actively drilling. We drilled 25 wells in 2004 and
plan to drill approximately 20 to 30 additional wells in 2005.

- Joaquin Field -- We operate and have rights to approximately 8,200 acres
in this property located just west of the Texas-Louisiana border in
Shelby County, Texas which produce Travis Peak sands at depths of 6,000
to 8,600 feet. In 2004, we drilled nine wells in this field and
anticipate drilling approximately ten additional wells in 2005.

- Terryville Field -- We have 5,160 acres in this developing play. We
recently drilled our third well to test the potential of the Cotton
Valley sands in this area. We have preliminarily budgeted seven wells for
the acreage in 2005 which could lead to a future multi-well development
program of the acreage.

GULF COAST

In the Gulf Coast region, we concentrate our drilling programs primarily in
south Texas. We also have working interests in several minor non-operated
offshore and Mississippi salt basin properties. We conduct development programs
and pursue moderate-risk, higher potential exploration drilling programs in this
region. Our Gulf Coast operations have numerous exploration prospects that are
expected to provide us additional growth. During 2004, we drilled 13 exploration
and 16 development wells in this region with a success rate of 97%. We
anticipate drilling 40 to 50 wells in this region in 2005, approximately
three-fourths of which will be exploratory. In 2004, exploration success was
achieved in the La Reforma and Coquat fields. In the third quarter of 2004, we
acquired a 42,300 acre lease on the O'Connor Ranch and license to approximately
100 square miles of 3D seismic data in Goliad County, Texas. The 2005 drilling
program will be concentrated in O'Connor Ranch, La Reforma, Coquat and Austin
fields and the West Mission Valley area.

Wilcox Trend -- Our projects in the Wilcox trend are mostly located in
Harris, Goliad, Victoria and Live Oak counties in Texas. Our primary objectives
are the abnormally pressured Middle Wilcox sands, although we also produce from
normal-pressured Frio, Yegua and Upper Wilcox zones. Sandstones in these
formations are found at depths between 4,000 to 13,000 feet. In 2004, we drilled
five Wilcox exploration wells, all of which were successful. In addition, we
drilled seven Wilcox development wells. Normally, we generate these prospects
and retain a 25% to 60% WI. Over the last several years we have been expanding
our efforts in this area. In 2001, we purchased interests in the West Mission
Valley Field and participated in the discovery of the Marshall Field. In 2003,
we participated in discoveries at the Five Mile Creek Field and the East
Marshall Field. In 2004, we participated in the following areas:

- West Mission Valley Area, Goliad and Victoria Counties, Texas. We
drilled seven Wilcox wells in 2004, four of which we operated, with WI
ranging from 25% to 50%. Reservoirs are mid-Wilcox in age and are at
moderate depth ranges of 10,000 to 12,000 feet. We plan to drill an
additional nine Wilcox wells in this area in 2005.

- Coquat Field, Live Oak County, Texas. We drilled four successful wells
in 2004 in this KCS-operated field with WI ranging from 40% to 57%. The
drilling program increased our gross field production from less than 1
MMcfepd to over 21 MMcfepd. Four to five wells are scheduled for drilling
in Coquat in 2005, one of these, the Meider #7A, has been drilled and is
completing now. All of the productive zones are abnormally pressured
Wilcox reservoirs from 10,000 to 13,000 feet.

- O'Connor Ranch, Goliad County, Texas. In the third quarter of 2004, we
purchased 42,300 acres with accompanying 100 miles of 3D seismic data in
this KCS-operated field where our WI ranges from 55% to 95%. This
property is located immediately south and adjacent to West Mission
Valley. It is also contiguous to our production area in the Austin Field.
In 2005, we plan to drill 15 to 20 Frio wells at depths ranging of 3,000
to 4,000 feet. We also plan to drill Yegua prospects at depths
approximating 7,000 feet and Wilcox prospects at depths ranging from
12,000 to 14,500 feet.

Vicksburg Trend -- We also pursue Vicksburg formation prospects primarily
in our La Reforma Field in Hidalgo County, Texas. We drilled a successful
initial test well in late 2002, drilled one additional well in 2003 and four
wells in 2004. Since beginning this drilling program we have increased gross
production in this field

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from below 5 MMcfpd to over 50 MMcfepd in 2004. We plan on drilling three to
four additional wells in the La Reforma Field in 2005. Our WI in these wells is
either 24% or 31.5% depending on the well's location.

Other Gulf Coast -- We have minor, non-operated working interests in
several offshore blocks and in several fields in the Mississippi salt basin.

OTHER OPERATING AREAS

We also operate and own majority interests in fields located in the Niagran
Reef play of Michigan, several fields in Wyoming and one field in the Los
Angeles basin in California. As of December 31, 2004, these properties accounted
for approximately 10% of our PV-10 value. In 2004, we drilled four wells in
Michigan and participated in two development wells in a Wyoming unit.

OIL AND GAS PROPERTIES

We hold interests in all of our oil and gas properties through two
operating subsidiaries: KCS Resources, Inc., a Delaware corporation, and
Medallion California Properties Company, a Texas corporation. The oil and gas
properties referred to in this annual report on Form 10-K are held by these
subsidiaries. We treat all operations as one line of business.

The following table sets forth the number of gross and net producing wells
by region as of December 31, 2004.

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(1) Includes Michigan and Wyoming

(2) Includes California

OIL AND NATURAL GAS RESERVES

The following table sets forth, as of December 31, 2004, summary
information with respect to estimates of our proved oil and natural gas reserves
based on year-end prices. Oil and natural gas prices as of December 31, 2004 are
not necessarily indicative of the prices that we expect to receive in the
future. Accordingly, the pre-tax present value of future net revenues in the
following table should not be construed to be the current market value of the
estimated oil and natural gas reserves.

In accordance with Securities and Exchange Commission guidelines, the
estimates of future net revenues from our proved reserves and the present values
of our proved reserves are made using oil and natural gas sales prices in effect
as of the dates of those estimates and are held constant throughout the life of
the properties except where those guidelines permit alternate treatment. Natural
gas prices are based on either a contract price or a December 31, 2004 spot
price of $6.18 per MMBtu, adjusted by lease for Btu content, transportation

7

fees and regional price differentials. Oil prices are based on a December 31,
2004 West Texas Intermediate posted price of $40.25 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. Please read "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and "Business -- Risk Factors"
for further discussion of these and other factors.

The estimates of our proved oil and natural gas reserves and associated
revenues, as of December 31, 2004, were prepared by us and were audited by
Netherland Sewell & Associates, Inc., or NSAI. NSAI follows the general
principles set forth in the standards pertaining to the estimating and auditing
of oil and gas reserve information promulgated by the Society of Petroleum
Engineers, or SPE.

A reserve audit as defined by the SPE is not the same as a financial audit.
The SPE's definition of a reserve audit includes the following concepts:

- A reserve audit is an examination of reserve information that is
conducted for the purpose of expressing an opinion as to whether such
reserve information, in the aggregate, is reasonable and has been
estimated and presented in conformity with generally accepted petroleum
engineering and evaluation principles.

- The estimation of reserves is an imprecise science due to the many
unknown geologic and reservoir factors that can only be estimated through
sampling techniques. Since reserves are only estimates, they cannot be
audited for the purpose of verifying exactness. Instead, reserve
information is audited for the purpose of reviewing in sufficient detail
the policies, procedures and methods used by a company in estimating its
reserves so that the reserve auditors may express an opinion as to
whether, in the aggregate, the reserve information furnished by the
company is reasonable and has been estimated and presented in conformity
with generally accepted petroleum engineering and evaluation principles.

- The methods and procedures used by a company, and the reserve information
furnished by the company, must be reviewed in sufficient detail to permit
the reserve auditor, in its professional judgment, to express an opinion
as to the reasonableness of the reserve information. In some cases, the
auditing procedure may require the reserve auditor to prepare its own
estimates of reserve information for particular properties. The
desirability of preparing its own estimates is determined by the reserve
auditor exercising its professional judgment.

In performing our reserve audit, NSAI does prepare its own estimates of
reserves for the majority our properties. As part of the audit process, we and
NSAI compare our reserve estimates, and often share additional data in order to
understand and narrow the gaps on properties where there are major variances in
the estimates. Once NSAI is satisfied that the reserve estimates are reasonable
and that their audit objectives have been met, the process is deemed complete.
When compared on a well-by-well or lease-by-lease basis, some of our estimates
of net proved reserves are greater and some are less than the estimates of NSAI.
We have been advised by NSAI that it generally issues a completed audit opinion
if its reserve estimates are within ten percent of a company's reserve
estimates. At the conclusion of the audit process, it is NSAI's opinion, as set
forth in its audit letter, that our estimates of our proved oil and natural gas
reserves and associated future net revenues are, in the aggregate, reasonable
and have been prepared in accordance with generally accepted petroleum
engineering and evaluation principles.

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PRODUCTION

The following table presents certain information with respect to production
attributable to our properties including average sales prices and unit costs for
the years ended December 31, 2004, 2003 and 2002.

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(a) Includes delivery obligations dedicated to a production payment transaction
whereby in February 2001 we sold 43.1 Bcfe (38.3 Bcf of natural gas and 797
Mbbl of oil) to be delivered over 60 months (the "Production Payment').
Production includes 5,170 MMcfe in 2004, 6,807 MMcfe in 2003 and 11,196
MMcfe in 2002 dedicated to the Production Payment. Please read Note 1 to
our Consolidated Financial Statements for more information on the
Production Payment.

(b) We sold properties in 2002 to reduce debt.

(c) We discontinued making new investments in VPPs in 1999 and final deliveries
from our VPP program were received in November 2002. The average production
cost per Mcfe in 2002 excludes the production received under our purchased
VPP program because that production was free from these expenses.

(d) The average realized prices reported above include the non-cash effects of
volumes delivered under the Production Payment as well as the unwinding of
various derivative contracts terminated in 2001. These items do not
generate cash to fund our operations. Excluding these items, the average
realized price per Mcfe was $5.85, $5.05 and $3.19 in 2004, 2003 and 2002,
respectively. For further information, please read "Management's Discussion
and Analysis of Financial Condition and Results of Operation -- Major
Influences on Results of Operations."

ACREAGE

The following table sets forth our developed and undeveloped leased acreage
as of December 31, 2004. The leases in which we have an interest are for varying
primary terms, and many require the payment of delay rentals to continue the
primary term. The operator may surrender the leases at any time by notices to
the

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lessors, the cessation of production, fulfillment of commitments, or failure to
make timely payments of delay rentals.

TITLE TO INTERESTS

We believe 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 that do not detract
substantially from the value of the interests or materially interfere with their
use in our operations. Our owned interests 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,
including production payments, net profits interests, development obligations
under oil and gas leases and other encumbrances, easements and restrictions.

DRILLING ACTIVITIES

During the three-year period ended December 31, 2004, we participated in
drilling 261 (169.2 net) wells with a success rate of 91%. During 2004, we
participated in drilling 130 (91.7 net) wells with a success rate of 97%. Our
drilling results for 2004 include 115 development wells and 15 exploration wells
with success rates of 98% and 87%, respectively. All of our drilling activities
are conducted through arrangements with independent contractors. The following
table sets forth certain information with respect to our drilling activities
during the years ended December 31, 2004, 2003 and 2002.

As of December 31, 2004, we were participating in the drilling of eight
(3.9 net) wells.

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OTHER FACILITIES

Our principal executive offices and those of our operating subsidiaries are
leased in modern office buildings in Houston, Texas and Tulsa, Oklahoma.

We believe that all of our property, plant and equipment are well
maintained, in good operating condition and suitable for the purposes for which
they are used.

REGULATION

General. Our 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 our business. In light of
the many uncertainties related to current and future laws and regulations,
including their applicability to us, we may be unable to predict the overall
effect of current and future laws and regulations on our future operations.

We believe that our operations comply in all material respects with all
applicable laws and regulations. Although applicable laws and regulations have a
substantial impact upon the energy industry, generally these laws and
regulations do not appear to affect us 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. Our 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 these state laws and regulations include laws
that:

- 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 natural gas properties;

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

- restrict the venting or flaring of natural gas.

These laws and regulations may adversely affect the profitability of affected
properties or our operations. We are unable to predict the future cost or impact
of complying with these regulations.

Federal Regulations Affecting Production Operations. We also operate
federal oil and natural gas leases that are subject to the regulation of the
United States Bureau of Land Management, or BLM, and the United States Minerals
Management Service, or MMS. Leases regulated by the BLM and MMS contain
relatively standardized terms requiring compliance with detailed regulations and
orders. These regulations specify, for example, lease operating, safety and
conservation standards, well plugging and abandonment requirements, and surface
restoration requirements. In addition, the BLM and MMS generally require us to
post surety bonds or other acceptable financial assurances to assure that our
obligations will be met. The cost of these bonds or other financial assurances
can be substantial and we may be unable to obtain bonds or other financial
assurances in all cases. Under certain circumstances, the BLM or MMS may require
operations on federal leases to be suspended or terminated. Any suspension or
termination under these leases may adversely affect our interests.

11

Additional proposals and proceedings that might affect the oil and natural
gas industry are pending before Congress, the Federal Energy Regulatory
Commission, or FERC, the MMS, the BLM, state commissions and the courts. We are
unable to predict when or whether any such proposals may become effective.
Historically, the natural gas industry has been very heavily regulated and for
many years was subject to price controls imposed by the federal government. The
current regulatory approach pursued by various agencies and Congress may not
continue indefinitely and it is possible Congress (or in the case of some
natural gas sales, the FERC) could reimpose price controls in the future.
Notwithstanding the foregoing, we do not anticipate that compliance with
existing federal, state and local laws, rules and regulations will have a
material or significantly adverse effect upon our capital expenditures, earnings
or competitive position.

Operating Hazards and Environmental Matters. The oil and natural gas
business involves a variety of operating risks, including the risk of fires,
natural disasters, explosions, well blowouts, adverse weather conditions,
mechanical problems, including pipe failure, abnormally pressured formations,
and environmental accidents, including oil spills, natural gas leaks or
ruptures, and discharges of toxic gases or other pollutants. The occurrence of
these risks could result in substantial losses to us due to personal injury,
loss of life, damage to or destruction of wells, production facilities, natural
resources or other property or equipment, pollution and other environmental
damage. These occurrences could also subject us to clean-up obligations,
regulatory investigation, penalties or suspension of operations. Although we
believe we are adequately insured, these hazards may hinder or delay drilling,
development and production operations.

Oil and natural 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, including 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.

Our properties, and any wastes spilled or disposed of by us, may be subject
to federal or state environmental laws that could require us to remove the
wastes or remediate contamination. For example, the Comprehensive Environmental
Response, Compensation and Liability Act, or 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 present or former 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, these 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, neighboring landowners and other third
parties may assert claims for personal injury and property damage allegedly
caused by the release of hazardous substances.

Our operations may also be subject to the Clean Air Act, or CAA, and
comparable state and local requirements. Pursuant to these requirements, we 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. We do not believe that our operations will be
materially adversely affected by these requirements.

In addition, the United States Oil Pollution Act, or OPA, requires owners
and operators of facilities in or near rivers, creeks, wetlands, coastal waters,
offshore waters, and other United States waters to adopt and implement plans and
procedures to prevent oil spills. OPA also requires affected facility owners and
operators in coastal waters to demonstrate that they have at least $10 million
in financial resources to pay for the costs of the remediation of an oil spill
and compensating any parties damaged by an oil spill. These financial assurances
may be increased to as much as $150 million depending on a facility's worst case
oil spill discharge volume and other relative operational, environmental and
human health risks.

12

Our operations are also subject to the federal Clean Water Act, or CWA, and
analogous state laws. Among other matters, these laws may prohibit the discharge
of waters produced in association with hydrocarbons into coastal waters. To
comply with this prohibition, we 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 our properties may require permits for discharges of storm
water runoff, we believe that we will be able to obtain, or be included under,
these permits as necessary. Coverage under these permits may require us to make
minor modifications to existing facilities and operations that would not have a
material adverse effect on us.

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

In addition, the disposal of wastes containing naturally occurring
radioactive material, which is commonly encountered during oil and natural 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.

RISK FACTORS

THE OIL AND NATURAL GAS MARKET IS VOLATILE AND THE PRICE OF OIL AND NATURAL GAS
FLUCTUATES, WHICH MAY ADVERSELY AFFECT OUR CASH FLOWS AND THE VALUE OF OUR OIL
AND NATURAL GAS RESERVES.

Our future revenues and profits and the value of our oil and natural gas
reserves will depend substantially on the demand and prices we receive for
produced oil and natural gas. Oil and natural gas prices have been and are
likely to continue to be volatile in the future. The recent oil and natural gas
prices may not continue and could drop precipitously in a short period of time.
The prices of oil and natural gas are subject to wide fluctuations in response
to a variety of factors beyond our control, including the following:

- relatively minor changes in the supply of, and demand for, domestic and
foreign oil and natural gas;

- market uncertainty;

- the ability of members of the Organization of Petroleum Exporting
Countries to agree upon and maintain oil prices and production controls;

- the level of consumer product demand;

- political conditions in international oil-producing regions, such as the
Middle East, Nigeria and Venezuela;

- weather conditions;

- domestic and foreign governmental regulations and taxes;

- the price and availability of alternative fuels;

- overall domestic and global economic conditions;

- the price of oil and natural gas imports;

- the effect of worldwide energy conservation measures; and

- the proximity to and capacity of transportation facilities.

These external factors and the volatile nature of the energy markets make
it difficult to reliably estimate future prices of oil and natural gas.

13

As oil and natural gas prices decline, we are affected in several ways:

- we are paid less for our oil and natural gas, thereby reducing our cash
flows;

- exploration and development activity may decline as some projects may
become uneconomic and either are delayed or eliminated;

- our lenders could reduce the borrowing base under our bank credit
facility because of lower oil and natural gas reserve values, thereby
reducing our liquidity and possibly requiring mandatory loan repayments;
and

- access to other sources of capital, such as equity or long-term debt
markets, could be severely limited or unavailable in a low price
environment.

Accordingly, any substantial or extended decline in oil or natural gas
prices may have material adverse effects on our cash flow, liquidity and
profitability and may cause us to be unable to meet our financial obligations or
make planned capital expenditures.

WE MAY BE UNABLE TO SATISFY OUR FUTURE CAPITAL REQUIREMENTS.

We make substantial capital expenditures in connection with the
acquisition, exploration and development of our oil and natural gas properties.
In the past, we have funded these capital expenditures with cash flow from
operations, funds from long-term debt financings, including bank financings
secured by our oil and natural gas assets, and funds from equity financings. Our
future cash flows are subject to a number of factors, some of which are beyond
our control, including the following:

- the price of oil and natural gas;

- the level of production from existing wells;

- operating and development costs; and

- our success in locating and producing new reserves.

The availability of long-term debt and equity financing is also subject to
these factors. Investors in our debt securities view our future cash flow as a
measure of our ability to make principal and interest payments. In addition, the
availability of funds under our bank credit facility is based on the value of
our estimated oil and natural gas reserves and our cash flows, which in turn are
based on prices of oil and natural gas and the amount and timing of production.
Similarly, investors in our equity securities consider both the value of our oil
and natural gas properties and our cash flow in evaluating our prospects for
growth and profitability. If our future cash flows decrease, however, and we are
unable to obtain additional long-term debt or equity financing or our borrowing
base under our bank credit facility is re-determined to a lower amount, we may
be unable to satisfy our future capital requirements.

WE MAY BE UNABLE TO SUCCESSFULLY IDENTIFY, EXECUTE OR EFFECTIVELY INTEGRATE
FUTURE ACQUISITIONS, WHICH MAY NEGATIVELY AFFECT OUR RESULTS OF OPERATIONS.

Acquisitions of oil and natural gas businesses and properties have been an
important element of our business, and we will continue to pursue acquisitions
in the future. In the last several years, we have pursued and consummated
acquisitions that allow us to drill development and extension wells. Although we
regularly engage in discussions with, and submit proposals to, acquisition
candidates, suitable acquisitions may not be available in the future on
reasonable terms as there is intense competition for acquisition opportunities
in our industry. If we do identify an appropriate acquisition candidate, we may
be unable to successfully negotiate the terms of an acquisition, finance the
acquisition or, if the acquisition occurs, effectively integrate the acquired
business into our existing business. Negotiations of potential acquisitions and
the integration of acquired business operations may require a disproportionate
amount of management's attention and our resources. Even if we complete
additional acquisitions, continued acquisition financing may not be available or
available on reasonable terms, any new businesses may not generate revenues
comparable to our existing business, the anticipated cost efficiencies or
synergies may not be realized and these businesses may not be integrated

14

successfully or operated profitably. The success of any acquisition will depend
on a number of factors, many of which are beyond our control, including:

- the ability to estimate accurately the recoverable volumes of reserves;

- the ability to estimate accurately rates of future production and future
net revenues attainable from the reserves;

- future oil and natural gas prices;

- operating costs; and

- the ability to estimate accurately potential environmental and other
liabilities.

Our inability to successfully identify, execute or effectively integrate
future acquisitions may negatively affect our results of operations. Even though
we perform a due diligence review (including a review of title and other
records) of the major properties we seek to acquire that we believe is
consistent with industry practices, these reviews are inherently incomplete. It
is generally not feasible for us to review in-depth every individual property
and all records involved in each acquisition. However, even an in-depth review
of records and properties may not necessarily reveal existing or potential
problems or permit us to become familiar enough with the properties to assess
fully their deficiencies and potential. Even when problems are identified, we
may not be able to obtain contractual indemnities from the sellers for
liabilities that it created and we may assume certain environmental and other
risks and liabilities in connection with the acquired businesses and properties.
The discovery of any material liabilities associated with our acquisitions could
harm our results of operations.

In addition, acquisitions of businesses may require additional debt or
equity financing, resulting in additional leverage or dilution of ownership. Our
bank credit facility and the indenture governing our senior notes contain
certain covenants that limit, or which may have the effect of limiting, among
other things, acquisitions, capital expenditures, the sale of assets and the
incurrence of additional indebtedness.

THERE ARE NUMEROUS UNCERTAINTIES INHERENT IN ESTIMATING QUANTITIES OF PROVED OIL
AND NATURAL GAS RESERVES AND FUTURE NET REVENUES.

The quantities and values of our proved reserves included in this annual
report and in the other documents we file with, or furnish to, the Securities
and Exchange Commission are only estimates and are subject to numerous
uncertainties. Reserve estimating is a subjective process of determining the
size of underground accumulations of oil and natural gas that cannot be measured
in an exact manner. Estimates of economically recoverable oil and natural gas
reserves and of future net revenues may vary considerably from the actual
results because of a number of variable factors and assumptions involved. These
include:

- the effects of regulation by governmental agencies;

- future oil and natural gas prices;

- operating costs;

- the method by which the reservoir is produced as well as the properties
of the rock;

- relationships with landowners, working interest partners, pipeline
companies and others;

- severance and excise taxes;

- development costs; and

- workover and remedial costs.

In addition, volumetric calculations are often used to estimate initial
reserves from a field. These estimates utilize data including the area that a
well is expected to drain, rock properties derived from log analysis,
anticipated reservoir fluid properties, abandonment pressure and estimates of
recovery factors. As production data becomes available, the actual performance
is often used to project the final reserves. As such,

15

initial reserve estimates are much less precise in nature. The actual
production, revenues and expenditures related to our reserves may vary
materially from the engineers' estimates.

Furthermore, we may make changes to our estimates of reserves and future
net revenues. These changes, which may be material, may be based on the
following factors:

- well performance;

- results of development including drilling and workovers;

- oil and natural gas prices;

- performance of counterparties under agreements to which we are a party;
and

- operating and development costs.

Actual future net revenues may also be materially affected by the following
factors:

- the amount and timing of actual production and costs incurred with such
production;

- the supply of, and demand for, oil and natural gas; and

- the changes in governmental regulations or taxation.

Ultimately, the timing in producing and the costs incurred in developing
and producing will affect the actual present value of oil and natural gas. In
addition, the Securities and Exchange Commission requires that we apply a 10%
discount factor in calculating PV-10 value for reporting purposes. This may not
be the most appropriate discount factor to apply because it does not take into
account the interest rates in effect, the risks associated with us and our
properties, or the oil and natural gas industry in general.

For the foregoing reasons, you should not assume that the present value of
future net cash flows from our proved reserves referred to in this annual report
or in our other reports filed with, or furnished to, the Securities and Exchange
Commission is the current market value of our estimated oil and natural gas
reserves. In accordance with Securities and Exchange Commission requirements, we
base the estimated discounted future net cash flows from our proved reserves on
prices and costs on the date of the estimate. Actual prices and costs since the
date of the estimate and future prices and costs may differ materially from
those used in the net present value estimate, and as a result, net present value
estimates using current prices and costs may be significantly more or less than
the estimate which is provided in this annual report or in our other reports
filed with, or furnished to, the Securities and Exchange Commission.

OUR OPERATING ACTIVITIES INVOLVE SIGNIFICANT RISKS THAT ARE INHERENT IN THE OIL
AND NATURAL GAS INDUSTRY, WHICH MAY RESULT IN SUBSTANTIAL LOSSES, AND INSURANCE
MAY BE UNAVAILABLE OR INADEQUATE TO PROTECT US AGAINST THESE RISKS.

Our operations are subject to numerous operating risks that are beyond our
control, are inherent in the oil and natural gas industry and could result in
substantial losses. These risks include:

- fires;

- natural disasters;

- explosions;

- well blowouts;

- adverse weather conditions;

- mechanical problems, including pipe failure;

- abnormally pressured formations; and

- environmental accidents, including oil spills, natural gas leaks or
ruptures, or other discharges of toxic gases or other pollutants.

16

The occurrence of these risks could result in substantial losses due to
personal injury, loss of life, damage to or destruction of wells, production
facilities, natural resources or other property or equipment, pollution and
other environmental damage. These occurrences could also subject us to clean-up
obligations, regulatory investigation, penalties or suspension of operations.
Further, our operations may be materially curtailed, delayed or canceled as a
result of numerous factors, including:

- unexpected drilling conditions;

- the presence of unanticipated pressure or irregularities in formations;

- equipment failures or accidents;

- title problems;

- weather conditions;

- compliance with governmental requirements; and

- costs of, shortages or delays in the availability of, drilling rigs or in
the delivery of equipment and experienced labor.

In accordance with customary industry practice, we maintain insurance
against some, but not all, of the risks described above. The levels of insurance
we maintain may not be adequate to fully cover any losses or liabilities. We may
not be able to maintain insurance at commercially acceptable premium levels or
at all. The occurrence of a significant event, not fully insured or indemnified
against, could have a material adverse effect on our financial condition and
operations.

WE MAY BE UNABLE TO PRODUCE SUFFICIENT AMOUNTS OF OIL AND NATURAL GAS AND, AS A
RESULT, OUR PROFITABILITY AND CASH FLOW WILL DECLINE.

We may drill new wells that are not productive or we may not recover all or
any portion of our investment. Drilling for oil and natural 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;

- wells that are productive may not provide sufficient net reserves to
return a profit after taking into account leasehold, geophysical and
geological, drilling, operating and other costs; and

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

If we are unable to produce sufficient amounts of oil and natural gas, our
profitability and cash flow will decline.

IF WE ARE UNABLE TO ACQUIRE OR DISCOVER ADDITIONAL RESERVES, OUR RESERVES AND
PRODUCTION WILL DECLINE MATERIALLY.

Our prospects for future growth and profitability depend primarily on our
ability to replace oil and natural gas reserves through acquisitions and
exploratory and development drilling. Acquisitions may not be available at
attractive prices or at all. The decision to purchase, explore or develop a
property depends in part on geophysical and geological analyses and engineering
studies that are often inconclusive or subject to varying interpretations. As a
consequence, our acquisition, exploration and development activities may not
result in significant additional reserves or reserves that are economically
recoverable. Without the acquisition, discovery or development of additional
reserves, our proved reserves and production will decline materially.

OUR FAILURE TO REMAIN COMPETITIVE WITH OUR NUMEROUS COMPETITORS, MANY OF WHICH
HAVE SUBSTANTIALLY GREATER RESOURCES THAN WE DO, COULD ADVERSELY AFFECT OUR
RESULTS OF OPERATIONS.

The oil and natural gas industry is highly competitive in the search for,
and development and acquisition of, reserves and in the marketing of oil and
natural gas production. We compete with major oil and natural gas

17

companies, other independent oil and natural gas concerns and individual
producers and operators in most aspects of our business, including the
following:

- the acquisition of oil and natural gas businesses and properties;

- the exploration, development, production and marketing of oil and natural
gas;

- the acquisition of properties and equipment; and

- the hiring and retention of personnel necessary to explore for, develop,
produce and market oil and natural gas.

Many of these competitors have substantially greater financial and other
resources than we do. If we are unable to successfully compete against our
competitors, our business, prospects, financial condition and results of
operations may be adversely affected.

WE ARE SUBJECT TO COMPLEX LAWS AND REGULATIONS, INCLUDING ENVIRONMENTAL
REGULATIONS, THAT MAY ADVERSELY AFFECT THE COST, MANNER OR FEASIBILITY OF DOING
BUSINESS.

Our 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. Please read "-- Regulation"
above. We are subject to various federal, state and local laws and regulations
relating to the discharge of materials into, and protection of, the environment.
These laws and regulations may, among other things:

- limit drilling locations or the rate of allowable hydrocarbon production
from a well;

- affect the cost, terms and availability of oil and natural gas
transportation by pipeline;

- impose liability on us under an oil and natural gas lease for the cost of
pollution clean-up and remediation resulting from operations;

- impose liability on us for personal injuries and property damage;

- subject us to liability for pollution damages, including oil spills,
discharge of hazardous materials and reclamation costs; and

- require suspension or cessation of operations in affected areas and
subject the lessee to administrative, civil and criminal penalties.

Any of these liabilities, penalties, suspensions, terminations or
regulatory changes could make it more expensive for us to conduct our business
or cause us to limit or curtail some of our operations.

Environmental laws have in recent years become more stringent and have
generally sought to impose greater liability on a larger number of potentially
responsible parties. While we are not currently aware of any situation involving
an environmental claim that would likely have a material adverse effect on our
business, it is always possible that an environmental claim with respect to one
or more of our current properties or a business or property that one of our
predecessors owned or used could arise and could involve the expenditure of a
material amount of funds. Although we maintain insurance coverage which we
believe is customary in the industry, we are not fully insured against all
environmental risks.

The Department of Transportation, through the Office of Pipeline Safety and
Research and Special Programs Administration, has implemented a series of rules
requiring operators of natural gas and hazardous liquid pipelines to develop
integrity management plans for pipelines that, in the event of failure, could
impact certain high consequence areas. These rules also require operators to
conduct baseline integrity assessments of all applicable pipeline segments
located in the high consequence areas. We continually are in the process of
identifying any of our pipeline segments that may be subject to these rules. We
have developed an integrity management plan for all covered pipeline segments.
We do not expect to incur significant costs in achieving compliance with these
rules.

18

Further, hydrocarbon-producing states regulate conservation practices and
the protection of correlative rights. These regulations affect our operations
and limit the quantity of hydrocarbons we may produce and sell.

The oil and natural gas regulatory environment could change in ways that
could substantially increase the cost of complying with the requirements of
environmental and other regulations. We cannot predict whether, or when, new
laws and regulations may be enacted or adopted, and we cannot predict the cost
of compliance with changing laws and regulations or their effects on oil and
natural gas use or prices.

WE HAVE LIMITED CONTROL OVER THE ACTIVITIES ON PROPERTIES THAT WE DO NOT
OPERATE, WHICH COULD HAVE A MATERIAL ADVERSE EFFECT ON THE REALIZATION OF OUR
TARGETED RETURNS OR LEAD TO UNEXPECTED FUTURE COSTS.

Although we operate most of the properties in which we have an interest,
other companies operate some of the properties. We have limited ability to
influence or control the operation or future development of these non-operated
properties or the amount of capital expenditures that we are required to fund
for their operation. Our dependence on the operator and other working interest
owners for these projects and our limited ability to influence or control the
operation and future development of these properties could have a material
adverse effect on the number of wells we drill, realization of our targeted
returns or lead to unexpected future costs.

THE CONCENTRATION OF OUR CUSTOMERS IN THE ENERGY INDUSTRY COULD INCREASE OUR
EXPOSURE TO CREDIT RISK, WHICH COULD RESULT IN LOSSES.

The concentration of our customers in the energy industry may impact our
overall exposure to credit risk, either positively or negatively, in that
customers may be similarly affected by prolonged changes in economic and
industry conditions. We perform ongoing credit evaluations of our customers and
do not generally require collateral in support of our trade receivables. We
maintain reserves for credit losses and, generally, actual losses have been
consistent with our expectations, with the exception of losses we sustained
relating to obligations of certain Enron entities to KCS.

IF WE ARE UNSUCCESSFUL TRANSPORTING OUR OIL AND NATURAL GAS TO MARKET AT
COMMERCIALLY ACCEPTABLE PRICES, OUR PROFITABILITY WILL DECLINE.

We deliver oil and natural gas through gathering systems and pipelines that
we do not own. Our ability to transport our oil and natural gas to market at
commercially acceptable prices or at all depends on, among other factors, the
following:

- the availability, proximity and capacity of third-party gathering
systems, processing facilities and pipelines;

- changes in supply and demand; and

- general economic conditions.

Our inability to respond appropriately to changes in any of the foregoing
factors could negatively affect our profitability.

In addition, the transportation by pipeline of oil and natural gas in
interstate commerce is heavily regulated by the FERC, including regulation of
the cost, terms and conditions for such transportation service, and in the case
of natural gas, the construction and location of pipelines. The transportation
by pipeline of oil and natural gas in intrastate commerce is generally subject
to varying degrees of state regulation of the cost, terms and conditions of
service. While we are not directly subject to these regulations, they affect the
cost and availability of transportation of our production to market.

UNINSURED JUDGMENTS OR A RISE IN INSURANCE PREMIUMS MAY ADVERSELY IMPACT OUR
RESULTS OF OPERATIONS.

Exploration for, and production of, oil and natural gas can be hazardous,
involving unforeseen occurrences. Accordingly, in the ordinary course of
business, we are subject to various claims and litigation. Although we maintain
insurance to cover certain potential claims and losses arising from our
operations in accordance with customary industry practices and in amounts that
management believes to be prudent, we

19

could become subject to a judgment for which we are not adequately insured and
beyond the amounts that we currently have reserved or anticipate reserving.
Additionally, the terrorist attacks of September 11, 2001 and the continued
hostilities in the Middle East and other sustained military campaigns may
adversely impact our ability to obtain insurance or impact the cost of this
insurance, either of which may adversely impact our results of operations.

TERRORIST ATTACKS AND CONTINUED HOSTILITIES IN THE MIDDLE EAST OR OTHER
SUSTAINED MILITARY CAMPAIGNS MAY ADVERSELY IMPACT OUR FINANCIAL CONDITION AND
OPERATIONS.

The terrorist attacks that took place in the United States on September 11,
2001 were unprecedented events that have created many economic and political
uncertainties, some of which may materially adversely impact our business. The
continued threat of terrorism and the impact of military and other action,
including U.S. military operations in Iraq, will likely lead to continued
volatility in prices for crude oil and natural gas and could affect the markets
for our operations. In addition, future acts of terrorism could be directed
against companies operating in the United States. The United States government
has issued public warnings that indicate that energy assets might be specific
targets of terrorist organizations. These developments have subjected our
operations, and those of our purchasers, to increased risks and, depending on
their ultimate magnitude, may adversely impact our financial condition and
operations.

OUR SUCCESS DEPENDS ON KEY MEMBERS OF SENIOR MANAGEMENT, THE LOSS OF WHOM COULD
DISRUPT OUR CUSTOMER RELATIONSHIPS AND BUSINESS OPERATIONS.

We believe our continued success depends in large part on the sustained
contributions of our chief executive officer and chairman of the board of
directors, James W. Christmas, our president and chief operating officer,
William N. Hahne, and our management team and technical personnel. We rely on
our executive officers and senior management to identify and pursue new business
opportunities and identify key growth opportunities. In addition, the
relationships and reputation that members of our management team have
established and maintained in the oil and natural gas community contribute to
our ability to maintain positive customer relations and to identify new business
opportunities. The loss of services of Messrs. Christmas or Hahne or one or more
senior management or technical staff could significantly impair our ability to
identify and secure new business opportunities and otherwise disrupt operations.
We do not maintain key person life insurance on any of our senior management
members.

WE ENGAGE IN HEDGING TRANSACTIONS, WHICH MAY LIMIT OUR POTENTIAL GAINS AND
EXPOSE US TO RISK OF FINANCIAL LOSS.

We periodically purchase or sell derivative instruments covering a portion
of our expected production in order to manage our exposure to price risk in
marketing our oil and natural gas. These instruments may include futures
contracts and options sold on the New York Mercantile Exchange and privately
negotiated forwards, swaps and options. These transactions may limit our
potential gains if oil and natural gas prices were to rise substantially over
the prices established by hedging. These transactions also may expose us to the
risk of financial loss in certain circumstances, including the following:

- production is less than the volume hedged;

- there is a widening of price differentials between delivery points for
our production and the delivery point assumed in hedging arrangements;

- the counterparties to our derivative instruments fail to perform their
contract obligations;

- we fail to make timely deliveries; and

- a sudden, unexpected event materially impacts oil or natural gas prices.

20

SHORTAGE OF DRILLING RIGS, EQUIPMENT, SUPPLIES OR PERSONNEL MAY DELAY OR
RESTRICT OUR OPERATIONS.

The oil and natural gas industry is cyclical and, from time to time, there
is a shortage of drilling rigs, equipment, supplies or personnel. During these
periods, the costs and delivery times of drilling rigs, equipment and supplies
are substantially greater. In addition, demand for, and wage rates of, qualified
drilling rig crews rise with increases in the number of active rigs in service.
Shortages of drilling rigs, equipment, supplies or personnel may increase
drilling costs or delay or restrict our exploration and development operations,
which in turn could impair our financial condition and results of operations.

OUR LEVERAGE AND DEBT SERVICE OBLIGATIONS MAY ADVERSELY AFFECT OUR CASH FLOW AND
OUR FINANCIAL AND OPERATING ACTIVITIES.

As of December 31, 2004, we had $175 million of total debt outstanding. Our
level of indebtedness may have important consequences for us, including the
following:

- our ability to obtain additional financing for acquisitions, working
capital or other expenditures could be impaired or financing may not be
available on acceptable terms;

- a substantial portion of our cash flow will be used to make interest and
principal payments on our debt, reducing the funds that would otherwise
be available for our operations and future business opportunities;

- a substantial decrease in our revenues as a result of lower oil and
natural gas prices, decreased production or other factors could make it
difficult for us to meet debt service requirements and force us to modify
our operations; and

- making us more vulnerable to a downturn in our business or the economy in
general.

IN ADDITION TO OUR CURRENT INDEBTEDNESS, WE MAY BE ABLE TO INCUR SUBSTANTIALLY
MORE DEBT. THIS COULD EXACERBATE THE RISKS DESCRIBED ABOVE.

Together with our subsidiaries, we may be able to incur substantially more
debt in the future. Although our bank credit facility and the indenture
governing our senior notes contain restrictions on our incurrence of additional
indebtedness, these restrictions are subject to a number of qualifications and
exceptions, and under certain circumstances, indebtedness incurred in compliance
with these restrictions could be substantial. Also, these restrictions do not
prevent us from incurring obligations that do not constitute indebtedness as
defined in the relevant agreement. As of December 31, 2004, we had $100 million
of borrowing capacity available under our bank credit facility and an unlimited
amount of capacity available under our indenture, in each case subject to a
number of qualifications. To the extent new debt is added to our current debt
levels, the risks described above could substantially increase.

WE ARE DEPENDENT ON OUR SUBSIDIARIES FOR OUR CASH FLOW.

We are a holding company with no material assets other than the equity
interests of our subsidiaries. Our subsidiaries conduct substantially all of our
operations and directly own substantially all of our assets. Therefore, our
operating cash flow and ability to meet our debt obligations will depend on the
cash flow provided by our subsidiaries in the form of loans, dividends or other
payments to us as a shareholder, equity holder, service provider or lender. The
ability of our subsidiaries to make such payments to us will depend on their
earnings, tax considerations, legal restrictions and restrictions under their
indebtedness.

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OUR BANK CREDIT FACILITY AND INDENTURE GOVERNING OUR SENIOR NOTES IMPOSE
RESTRICTIONS ON US THAT MAY AFFECT OUR ABILITY TO SUCCESSFULLY OPERATE OUR
BUSINESS AND OUR ABILITY TO MAKE PAYMENTS ON OUR INDEBTEDNESS.

Our bank credit facility and the indenture governing our senior notes
include covenants that, among other things, restrict our ability to:

- borrow money;

- create liens;

- sell or transfer any of our material property;

- merge into or consolidate with any third party or sell or dispose of all
or substantially all of our assets; and

- make capital expenditures.

We are also required by our bank credit facility to maintain specified
interest coverage and current ratios. All of these and other covenants may
restrict our ability to expand or to pursue our business strategies. Adverse
financial or economic developments may cause us to breach these covenants. The
breach of any of these covenants could result in a default under our debt,
causing the debt to become due and payable. We may not be able to repay the debt
due as a result of an acceleration.

From time to time, we may require consents or waivers from our lenders to
permit any necessary actions that are prohibited by our debt and financing
arrangements. If in the future our lenders refuse to provide any necessary
waivers of the restrictions contained in our debt and financing arrangements,
then we could be in default under our debt and financing arrangements, and we
could be prohibited from undertaking actions that are necessary to maintain and
expand our business.

ANTI-TAKEOVER PROVISIONS IN OUR CERTIFICATE OF INCORPORATION, BY-LAWS AND
DELAWARE LAW COULD DISCOURAGE A CHANGE OF CONTROL OF OUR COMPANY AND COULD
NEGATIVELY AFFECT OUR STOCK PRICE.

Provisions in our certificate of incorporation and by-laws, each as amended
to date, and applicable provisions of the Delaware General Corporation Law may
make it more difficult and expensive for a third party to acquire control of us
even if a change of control would be beneficial to the interests of our
stockholders. These provisions could discourage potential takeover attempts and
could adversely affect the market price of our common stock. Our certificate of
incorporation and by-laws, each as amended to date:

- classify the board of directors into staggered, three-year terms, which
may lengthen the time required to gain control of our board of directors;

- limit who may call special meetings;

- prohibit stockholder action by written consent, requiring all actions to
be taken at a meeting of the stockholders;

- do not permit cumulative voting in the election of directors, which would
otherwise allow holders of less than a majority of stock to elect some
directors;

- limit the ability of stockholders to remove directors by providing that
they may only be removed for cause; and

- allow our board of directors to determine the powers, preferences or
rights and the qualifications, limitations and restrictions of shares of
our preferred stock.

In addition, Section 203 of the Delaware General Corporation Law may
discourage, delay or prevent a change in control by prohibiting us from engaging
in a business combination with an interested stockholder for a period of three
years after the person becomes an interested stockholder.

22

COMPETITION

We operate in the highly competitive exploration and production segment of
the oil and gas industry. We compete with major oil and natural gas companies,
other independent oil and natural gas concerns and individual producers and
operators in the areas of reserve and leasehold acquisitions and the
exploration, development, production and marketing of oil and natural gas, as
well as contracting for equipment and the hiring of personnel. The principal
competitive factors in acquiring, discovering, producing and marketing oil and
natural gas reserves are the availability and hiring of qualified personnel,
technology and financial resources. We may be at a disadvantage to many of our
competitors in one or more of these areas due to our size relative to other
companies in the industry.

MARKETING AND CUSTOMERS

We market the majority of the natural gas and oil production from
properties we operate for both our account and the account of the other working
and royalty interest owners in these properties. In some instances, we also
market our non-operated natural gas and crude oil production to enhance price
realization and cash flow. The production is sold to a variety of purchasers.
The terms of sale under the majority of existing contracts are short-term,
usually one to three months in duration. The prices received for natural gas and
oil sales are tied to monthly or daily indices as quoted in industry
publications.

In order to achieve more predictable cash flow and reduce exposure to price
volatility of natural gas and crude oil, we utilize fixed price sales and
derivative agreements for a portion of our production with unaffiliated third
parties. Please read Note 11 to our Consolidated Financial Statements for
information regarding our derivative instruments.

In 2004, one customer, Louis Dreyfus Energy Services LP, accounted for 19%
of our consolidated revenue. Other than the amortization of deferred revenue
associated with the Production Payment, no customer accounted for more than 10%
of our consolidated revenues in 2003 or 2002.

SEASONALITY

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

EMPLOYEES

As of December 31, 2004, we employed a total of 133 persons. None of our
employees are represented by a labor union. Relations between us and our
employees are considered to be satisfactory.

AVAILABLE INFORMATION

Our Internet website is www.kcsenergy.com. The Investor Relations portion
of our Internet website is www.kcsenergy.com/html/investor.html and it contains
information about us, including our 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. These reports are available free of charge on
the Investor Relations portion of our Internet website on the same day that we
electronically file these materials with, or furnish these materials to, the
Securities and Exchange Commission.

ITEM 2. PROPERTIES.

Reference is made to Item 1. Business, "-- Oil and Gas Properties," "-- Oil
and Natural Gas Reserves," "-- Production," "-- Acreage," "-- Title to
Interests," "-- Drilling Activities" and "-- Other Facilities" included
elsewhere in this annual report on Form 10-K.

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ITEM 3. LEGAL PROCEEDINGS.

Reference is made to Note 12 to our Consolidated Financial Statements
included elsewhere in this annual report on Form 10-K.

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

No matter was submitted to a vote of our security holders through the
solicitation of proxies or otherwise during the fourth quarter of the fiscal
year ended December 31, 2004.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES.

Our common stock is traded on the New York Stock Exchange under the symbol
"KCS." As of March 1, 2005, there were approximately 917 holders of record of
our 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 following
table sets forth, for each quarterly period during fiscal 2004 and 2003, the
high and low sales price per share of our common stock, as reported in the
composite transaction reporting system.

On March 11, 2005, the last reported sales price of our common stock on the
New York Stock Exchange was $16.26 per share.

DIVIDEND POLICY

We have not declared or paid any cash dividends on our common stock since
1999. We intend to retain earnings for use in the operation and expansion of our
business, and therefore do not anticipate declaring or paying a cash dividend on
our common stock in the foreseeable future. In addition, our bank credit
facility prohibits the payment of cash dividends on our common stock.

24

EQUITY COMPENSATION PLAN INFORMATION

The following table sets forth information with respect to shares of our
common stock that may be issued upon the exercise of options, warrants and
rights under all of our existing equity compensation plans as of December 31,
2004.

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

(1) Represents options granted under our 2001 Employee and Directors Stock Plan.
Excludes warrants to purchase 200,000 shares of our common stock whose
exercise price is $4.00 per share. The warrants were exercised in full in
March 2005 and therefore are no longer outstanding. Please read Note 8 to
our Consolidated Financial Statements for more information on the warrants.

(2) Includes 977,606 shares authorized for issuance pursuant to our 2001
Employee and Directors Stock Plan, 754,070 shares authorized for issuance
pursuant to our employee stock purchase program and 657,316 shares
authorized for issuance in connection with our 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, or 2001 Stock
Plan. The 2001 Stock Plan was adopted as part of our plan of reorganization, or
the Plan, under Chapter 11 of Title 11 of the United States Bankruptcy Code. The
Plan was approved by our stockholders and creditors. However, our stockholders
did not consider and vote on the 2001 Stock Plan independently of their
consideration of the Plan. The 2001 Stock Plan provides that stock options,
stock appreciation rights, restricted stock and bonus stock may be granted to
our employees. The 2001 Stock Plan provides that each non-employee director will
be granted stock options for 1,000 shares of our common stock on an annual
basis. The 2001 Stock Plan also provides that in lieu of cash, each non-employee
director may be issued shares of our common stock with a fair market value equal
to 50% of the non-employee directors' annual retainer. The 2001 Stock Plan
provides that the option price of shares issued under the plan shall be equal to
the market price on the date of grant. All options expire ten years after the
date of grant. The 2001 Stock Plan provides for the issuance of up to 4,362,868
shares of our common stock. As of December 31, 2004, grants of 586,279
restricted shares were outstanding under the 2001 Stock Plan. Please read Note 5
to our Consolidated Financial Statements for a discussion of the terms of the
restricted stock.

Other Plans. Shortly after our formation in May 1988, we adopted, among
other benefit programs, an employee stock purchase plan and a savings and
investment plan. The stockholders of our former parent company did not
specifically vote to approve these plans, but they did approve a plan
authorizing our spin-off and formation that 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 us 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 amount for our employees is the
number of shares costing no more than 10% of the eligible employee's annual base
salary. The maximum annual purchase amount for our directors is 6,000 shares.
Please read Note 5 to our Consolidated Financial Statements for more
information.

25

Savings and Investment Plan. Under the savings and investment plan,
eligible employees may contribute a portion of their compensation, as defined in
the plan, to the savings and investment plan, subject to certain Internal
Revenue Service limitations. We may provide matching contributions, currently
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 and investment plan also contains a profit-sharing component whereby the
board of directors may declare annual discretionary profit-sharing
contributions. Our matching contributions and discretionary profit-sharing
contributions vest over a four-year employment period. Once the four-year
employment period has been satisfied, all of our matching contributions and
discretionary profit-sharing contributions immediately vest. Please read Note 4
to our Consolidated Financial Statements for more information.

ITEM 6. SELECTED FINANCIAL DATA.

The following table sets forth our selected historical financial data for
each of the five years in the period ended December 31, 2004. The selected
historical financial data set forth below has been derived from our audited
consolidated financial statements included elsewhere in this annual report on
Form 10-K. Please read "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and our audited consolidated financial
statements and related notes included elsewhere in this annual report on Form
10-K for a discussion of factors that affect the comparability of this
information and material uncertainties that may cause this information not to be
indicative of our future financial condition or results of operations.

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

(1) Includes a $13.9 million income tax benefit related to the reversal of the
remaining portion of our valuation allowance against net deferred income tax
assets.

(2) Includes a $20.2 million income tax benefit related to the reversal of a
portion of our valuation allowance against net deferred income tax assets
and a $0.9 million non-cash charge related to the cumulative effect of an
accounting change as a result of the adoption of SFAS No. 143, "Accounting
for Asset Retirement Obligations."

27

(3) Includes a $15.9 million non-cash write-down 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.

(4) Excludes debt classified as current liability.

(5) Included in current liabilities.

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 our consolidated
financial statements and related notes included elsewhere in this annual report
on 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, and Section 21E of the Securities Exchange Act of 1934,
as amended. All statements, other than statements of historical facts, included
herein concerning, among other things, planned capital expenditures, increases
in oil and natural gas production, the number of anticipated wells to be drilled
in the future, future cash flows and borrowings, pursuit of potential
acquisition opportunities, our 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 "may," "will," "expect," "estimate," "project," "plan,"
"believe," "achievable," "anticipate" and similar terms and phrases. Although we
believe that the expectations reflected in any forward-looking statements are
reasonable, they do involve certain assumptions, risks and uncertainties. Our
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 our drilling activities;

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

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

- our ability to successfully identify, execute or effectively integrate
future acquisitions;

- the usual hazards associated with the oil and gas industry (including
fires, natural disasters, well blowouts, adverse weather conditions, pipe
failure, spills, explosions and other unforeseen hazards);

- our ability to effectively transport and market our oil and natural gas;

- the results of our hedging transactions;

- the availability of rigs, equipment, supplies and personnel;

- our ability to acquire or discover additional reserves;

- our ability to satisfy future capital requirements;

- changes in regulatory requirements;

- the credit risks associated with our customers;

- economic and competitive conditions;

- our ability to retain key members of senior management and key employees;

- uninsured judgments or a rise in insurance premiums;

- our outstanding indebtedness;

28

- continued hostilities in the Middle East and other sustained military
campaigns and acts of terrorism or sabotage; and

- if underlying assumptions prove incorrect.

These and other risks are described in greater detail in "Business -- Risk
Factors" included elsewhere in this annual report on Form 10-K. All
forward-looking statements attributable to us or persons acting on our behalf
are expressly qualified in their entirety by these factors. Other than as
required under the securities laws, we do 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.

OVERVIEW

The year ended December 31, 2004 was an outstanding year for us. We drilled
a record 130 wells during 2004, of which 126 were completed, resulting in a 97%
success rate and significantly increased production and reserves. In 2004, gross
production increased 15%, to 40 Bcfe, while net production after production
payment delivery obligations that do not contribute to cash flow from operating
activities increased 25% compared to 2003. Natural gas and oil reserves
increased 22% to 328 Bcfe as of December 31, 2004 compared to 268 Bcfe as of
December 31, 2003. In total, we added 94.5 Bcfe of proved reserves during 2004,
of which 97% was through the drill bit. Total oil and gas capital expenditures
were $166.7 million.

In 2004, we continued to execute our strategies of focusing on low-risk
development and exploitation drilling in our core operating areas and to commit
approximately 15% of our capital expenditure budget to moderate-risk,
higher-potential exploration prospects primarily in the onshore Gulf Coast
region. In 2005, we plan to commit approximately 15% to 20% of our capital
expenditure budget to such exploration projects. We continue to focus primarily
on natural gas prospects. We have continued our disciplined hedging program
designed to protect against price declines while participating to a large extent
in future price increases. In this way, we endeavor to ensure that we generate a
sufficient level of cash flow to carry out a capital expenditure program
sufficient to at least replace our expected production and still benefit if
prices rise.

We further strengthened our financial condition in 2004 and provided
additional financial flexibility by completing a $175 million senior notes
offering. The new senior notes bear interest at an annual rate of 7 1/8% and
mature in 2012. The proceeds of this issuance were used to redeem our $125
million 8 7/8% senior subordinated notes due 2006, including an early redemption
premium, and to repay the $22 million outstanding under our bank credit
facility. As of December 31, 2004, we had $6.6 million of cash on hand and $100
million of unused committed borrowing capacity under our bank credit facility.
We plan to maintain a conservative capital structure. Please read Note 6 to our
Consolidated Financial Statements for more information regarding our senior
notes and our bank credit facility.

In the Mid-Continent region, we concentrate our drilling programs primarily
in north Louisiana, east Texas, Oklahoma (Anadarko and Arkoma basins) and west
Texas. Our Mid-Continent region operations provide us with a solid base for
production and reserve growth. We plan to continue to exploit areas within the
various basins that require low-risk exploitation wells for additional reservoir
drainage. Our exploitation wells are generally step-out and extension type wells
with moderate reserve potential. During 2004, we drilled 101 wells in this
region with a success rate of 97%. In 2005, we plan to drill 90 to 115 wells in
this region, approximately half of which are planned in the Elm Grove Field
which is our largest field. We will also pursue drilling programs in the Sawyer
Canyon, Joaquin, Terryville and Talihina fields and have budgeted $20 million to
commence development of the properties being acquired in April 2005.

In the Gulf Coast region, we concentrate our drilling programs primarily in
south Texas. We also have working interests in several minor non-operated
offshore and Mississippi salt basin properties. We conduct development programs
and pursue moderate-risk, higher potential exploration drilling programs in this
region. Our Gulf Coast operations have numerous exploration prospects that are
expected to provide us additional growth. During 2004, we drilled 13 exploratory
and 16 development wells in this region with a success rate of 97%. We
anticipate drilling 40 to 50 wells in this region in 2005, approximately
three-fourths of which will be

29

exploratory. In 2004, exploration success was achieved in the La Reforma and
Coquat fields. In the third quarter of 2004, we acquired a 42,300 acre lease on
the O'Connor Ranch and license to approximately 100 square miles of 3D seismic
data in Goliad County, Texas. The 2005 drilling program will be concentrated in
O'Connor Ranch, La Reforma, Coquat and Austin Deep fields and the West Mission
Valley area.

We believe that the steps taken over the last several years position us to
continue growing our reserves and production through a balanced investment
program including low-risk exploitation and development activities in the
Mid-Continent and Gulf Coast regions and moderate-risk, higher potential
exploration drilling programs primarily in the onshore Gulf Coast region.

MAJOR INFLUENCES ON RESULTS OF OPERATIONS

Oil and natural gas prices. Oil and natural gas prices have been, and are
expected to continue to be, volatile. Prices for oil and natural gas fluctuate
widely 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
beyond our control, including, among others, worldwide political conditions
(especially in the Middle East and other oil-producing regions), the domestic
and foreign supply of oil and natural gas, the level of consumer demand, weather
conditions, domestic and foreign governmental regulations and taxes, the price
and availability of alternative fuels and overall domestic and global economic
conditions.

The average price we receive for our natural gas production is generally 10
to 15 cents below NYMEX prices at the Henry Hub. The primary factors for this
differential are the geographic locations of our producing properties and the
Btu content of our natural gas. The average Btu content of our natural gas is in
excess of 1,000 Btu per cubic foot. The price we receive for our oil production
is generally $1.60 to $1.75 per barrel below the Koch West Texas Intermediate
posted prices for sweet crude in Texas/New Mexico.

We use commodity derivative contracts on a limited basis to manage our
exposure to oil and natural gas price volatility. Our strategy is to maintain a
disciplined approach by layering in a series of derivative contracts at
different price levels depending on market conditions and other factors. We
typically target hedging 30% to 50% of our near-term production. We do not enter
into derivative or other financial instruments for trading or speculative
purposes. Excluding the effect of impact of the terminated derivative
instruments discussed below, hedging activities decreased realized prices by
$0.10 and $0.02 in 2004 and 2003, respectively and increased realized prices by
$0.05 in 2002.

Certain terminated derivative instruments also affect our reported realized
prices. In February 2001, we terminated $2.055 per MMBtu swaps on 10.1 million
MMBtu through 2005 that we inherited when we acquired Medallion California
Properties Company and related entities. This resulted in a $28 million hedge
loss that is being amortized as a non-cash reduction of revenue over the
original term of the derivative instruments. The effect of this amortization of
the cost of these terminated swaps was to reduce realized prices by $0.11, $0.16
and $0.18 per Mcfe in 2004, 2003 and 2002, respectively.

Our reported realized prices for oil and natural gas are also affected by
the Production Payment we sold in February 2001 at a weighted average discounted
price realized of $4.05 per Mcfe which has the effect of lowering our reported
realized price in periods when cash prices exceed $4.05 per Mcfe and raising our
reported realized prices when cash prices are lower than $4.05 per Mcfe. The
effect of the Production Payment was to reduce realized prices by $0.27 per Mcfe
and $0.29 per Mcfe in 2004 and 2003, respectively, and to increase realized
prices by $0.20 per Mcfe in 2002.

Production. The primary factors affecting our production levels are
capital availability, the success of our drilling program and, in 2002, the
sales of certain non-core properties and the winding down and expiration of our
purchased VPP program.

In 2002, our main objective was to position ourselves to meet our senior
note obligations that were due in January 2003. In order to do so, we curtailed
our capital spending program and sold certain non-core producing properties. As
a result of the property sales and curtailed drilling, our production declined
significantly compared to 2001. In 2003 and 2004, we were able to direct our
cash flow to our drilling operations and significantly grow production levels
and natural gas and oil reserves.

30

In 2002, 2.5 Bcfe, or 7%, of our production was derived from our purchased
VPP program. We have not made any VPP investments since 1999. Final deliveries
under our existing VPPs were received in November 2002. Although specific terms
of our VPPs varied, we were generally entitled to receive delivery of the
scheduled oil and natural gas volumes at agreed delivery points, free of
drilling and lease operating expenses and free of state production taxes. During
the life of the program, we invested $213.6 million to acquire reserves of 120.3
Bcfe of natural gas and oil and realized approximately $293.9 million from the
sale of oil and natural gas acquired as well as an additional 10.6 Bcfe under a
VPP that was converted to a working interest.

Our reported production includes volumes dedicated to the Production
Payment discussed below. However, we view the net production after our delivery
obligations associated with the Production Payment as more important because it
is net production that generates cash flow. For example, while total production
increased 15%, from 34.7 Bcfe in 2003, to 40.0 Bcfe in 2004, our net production
actually increased 25%, from 27.9 Bcfe in 2003, to 34.8 Bcfe in 2004 as delivery
obligations associated with the Production Payment declined from 6.8 Bcfe in
2003 to 5.2 Bcfe in 2004. This 1.6 Bcfe less production committed to the
Production Payment obligations in 2004 resulted in incremental cash flow of
approximately $9.4 million.

Sale of Production Payment. In February 2001, we sold a Production Payment
in connection with our emergence from Chapter 11. The net proceeds from this
sale of approximately $175 million was recorded as deferred revenue and is
amortized over the five-year period that scheduled deliveries of production are
made. Deliveries under this Production Payment are recorded as non-cash oil and
gas revenue with a corresponding reduction of deferred revenue at the weighted
average discounted price realized of approximately $4.05 per Mcfe. We also
reflect the production volumes and depletion expense as deliveries are made.
However, the associated oil and natural gas reserves are excluded from our oil
and natural gas reserve data. Amortization of deferred revenue comprised 10%,
17% and 38% of our oil and gas revenue during 2004, 2003 and 2002, respectively.
As of December 31, 2004, 4.1 Bcfe remained to be delivered under the Production
Payment of which 3.9 Bcfe will be delivered in 2005 and 0.2 Bcfe in 2006.

Operating Costs. We monitor our business to control costs from both a
gross dollar standpoint and from a per unit of production perspective. We are
able to control our lease operating expenses because we are focused in certain
core areas which allows us to operate efficiently. Lease operating expenses were
$28.6 million in 2004, $24.6 million in 2003 and $22.9 million in 2002. These
costs reflect the levels of production and workover activities and, in 2004,
increased service costs experienced by the oil and gas industry. In order to
measure our operating performance, we monitor lease operating expenses on a per
unit of production basis. Lease operating expenses (excluding production from
purchased VPPs) per Mcfe were $0.72 in 2004, $0.71 in 2003 and $0.65 in 2002.

General and administrative expenses are monitored closely with the
objective of operating an efficient organization with an appropriate cost
structure. In 2002, we reduced our staff in response to limited capital
availability and curtailed drilling activity. In 2003 and 2004, we added staff
modestly in response to our resumed growth. General and administrative expenses
were $9.1 million, or $0.23 per Mcfe, in 2004, $8.0 million, or $0.23 per Mcfe,
in 2003 and $8.3 million, or $0.22 per Mcfe, in 2002.

FACTORS AFFECTING COMPARABILITY

Sale of Emission Credits. We sold emission credits totaling $4.9 million
in 2003 which are reflected in other, net in our statements of consolidated
operations. We did not sell any emission credits in 2002 and only a minor amount
in 2004. We currently do not anticipate any significant emission credit sales in
2005.

Stock Compensation. Stock compensation was $2.6 million, $2.7 million and
$0.8 million in 2004, 2003 and 2002, respectively. These non-cash expenses
reflect the amortization of restricted stock grants and expenses associated with
certain stock options granted in 2001 that are subject to variable accounting.
The stock option expenses can fluctuate significantly as the expense recognized
during a reporting period is directly related to the movement in the market
price of our common stock during that period.

31

Redemption Premium on Early Extinguishment of Debt. On May 1, 2004, we
redeemed our $125 million 8 7/8% senior subordinated notes due 2006. Pursuant to
the indenture, we paid an early redemption premium of $3.7 million, which was
charged against earnings in the second quarter of 2004.

Income Taxes. During the second quarter of 2002, uncertainty resulting
from relatively low commodity prices and the January 2003 maturity date for our
senior notes led management to increase the valuation allowance against net
deferred income tax assets by $15.9 million. This increase in the valuation
allowance reduced the carrying value of net deferred assets to zero and was
reflected as income tax expense on our statements of consolidated operations.
Since that time, we have generated significant levels of taxable income due to
drilling success and strong natural gas and oil prices. We believe that the
future outlook for continued generation of taxable income is positive based on
existing available information, including prices quoted on the New York
Mercantile Exchange and our production levels. During 2003, we reversed
approximately $37.6 million of the valuation allowance and in 2004 reversed the
remaining $44.2 million of the valuation allowance related to expected taxes on
future years' taxable income. These amounts are reflected as an income tax
benefit in our statements of consolidated operations. In 2005, while we continue
to utilize our net operating loss carryforwards and pay alternative minimum tax
of approximately 1% to 2% of pre-tax income, we anticipate that we will record
book income tax expense close to the statutory corporate income tax rate of 35%.

Accounting Changes. Our 2002 results included a $6.2 million charge
against earnings related to our change to the unit-of-production method of
accounting for depreciation, depletion and amortization. This charge is
reflected as a cumulative effect of accounting change, net of tax. In 2003, we
adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," and
recorded a $0.9 million charge against earnings as a cumulative effect of an
accounting change, net of tax. There were no accounting changes that affected us
in 2004.

CRITICAL ACCOUNTING POLICIES

The discussion and analysis of our financial condition and results of
operations are based upon our consolidated financial statements, which have been
prepared in accordance with accounting principles generally accepted in the
United States, or GAAP. The preparation of these financial statements requires
us to make estimates and judgments that affect our financial condition and
results of operations. Our significant accounting policies are described in Note
1 to our 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 the audit committee of our board of directors. The following
discussion details the more significant accounting policies, estimates and
judgments.

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: (i) the successful efforts
method; and (ii) 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, we capitalize all acquisition, exploration and development costs into
one country-wide cost center. These costs include lease acquisitions, geological
and geophysical services, drilling, completion, equipment, certain salaries and
other internal costs directly attributable to these activities. These costs are
then amortized over the remaining life of the aggregate oil and natural 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 the full cost method of accounting is appropriate
and accurately reflects the economics of our programs for the acquisition,
exploration and development of oil and natural gas

32

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 they 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 NATURAL GAS RESERVE ESTIMATES

Estimates of our proved oil and natural gas reserves are based on the
quantities of oil and natural gas that 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 natural 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 may 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 natural gas reserves are used throughout our financial
statements. For example, as we use the unit-of-production method of calculating
depletion expense, 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 large part on the quantity of our proved reserves.
Finally, these reserves are the basis for our supplemental oil and gas
disclosures.

The estimates of our proved oil and natural gas reserves have been audited
or prepared by Netherland, Sewell & Associates, Inc., independent petroleum
engineers.

AMORTIZATION OF OIL AND GAS PROPERTIES

Effective January 1, 2002, we began amortizing the capitalized costs
related to our oil and gas properties under the unit-of-production, or UOP,
method using proved oil and natural gas reserves. Under the UOP method, the
depreciation, depletion and amortization rate is computed based on the ratio of
production to total reserves. 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 with proved reserves). The calculation of
depreciation, depletion and amortization requires the use of significant
estimates pertaining to oil and natural gas reserves and future development
costs.

BAD DEBT EXPENSE

We routinely review all material trade and other receivables to determine
the timing and probability of collection. Many of our receivables are from joint
interest owners on properties we operate. Therefore, we may have the ability to
withhold future revenue disbursements to recover any non-payment of joint
interest billings. We market the majority of our production and these
receivables are generally collected within a month. The receivables for the
remaining production are typically collected within two months. We accrue a
reserve for a receivable when, based on the judgment of management, it is
doubtful that the receivable will be collected in full and the amount of any
reserve required can be reasonably estimated.

REVENUE RECOGNITION

Oil and natural gas revenues are recognized when production is sold to a
purchaser at fixed or determinable prices, when delivery has occurred and title
has transferred and collection of the revenue is probable. We follow the sales
method of accounting for natural gas revenues. Under this method of accounting,
revenues are recognized based on actual production volume sold. The volume of
natural gas sold may differ from the volume to which we are entitled based on
our WI. An imbalance is recognized as a liability only when the estimated
remaining reserves will not be sufficient to enable the under-produced

33

owner(s) to recoup its entitled share through future production. Natural 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 natural gas sold by each owner may
differ from its allowable percentage. Two principal accounting practices have
evolved to account for natural gas imbalances. These methods differ as to
whether revenue is recognized based on the actual sale of natural 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. If we used the
entitlement method, our reported revenues may 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. In making this assessment, we perform an extensive analysis
of our operations to determine the sources of future taxable income. The
analysis consists of a detailed review of all available data, including our
budget for the ensuing year, forecasts based on current as well as historical
prices, and the independent petroleum 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 we will generate in the future. Our current net operating loss
carryforwards aggregating approximately $162 million have remaining lives
ranging from 14 to 18 years. However, we examine 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.

ASSET RETIREMENT OBLIGATIONS

We have significant obligations to remove equipment and restore land at the
end of oil and natural gas production operations. Our removal and restoration
obligations are primarily associated with plugging and abandoning wells.
Estimating future asset removal costs is difficult and requires management to
make estimates and judgments as most of the removal obligations are many years
in the future and because contracts and regulations often contain vague
descriptions of what constitutes removal. Asset removal technologies and costs
are constantly changing, as are political, environmental, safety and public
relations considerations.

SFAS No. 143 "Accounting for Asset Retirement Obligations" 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.

Inherent in the present value calculation are numerous assumptions and
judgments including the ultimate settlement amounts, inflation factors, credit
adjusted discount rates, timing of settlement, and changes in the legal,
regulatory, environmental and political environments. To the extent future
revisions to these assumptions impact the present value of the existing asset
retirement obligation, a corresponding adjustment is made to the oil and gas
property balance. In addition, increases in the discounted asset retirement
obligation resulting from the passage of time will be reflected as accretion
expense in the consolidated statement of operations.

DERIVATIVES

We use commodity derivative contracts to manage our exposure to oil and
natural gas price volatility. We account for our commodity derivative contracts
in accordance with Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities," or SFAS No. 133.
Realized gains and losses from our cash flow hedges, including terminated
contracts, are generally recognized

34

in oil and natural gas production revenue when the hedged volumes are produced
and sold. We do not enter into derivative or other financial instruments for
speculative or trading purposes.

RESULTS OF OPERATIONS

Income before income taxes and cumulative effect of accounting change for
2004 increased 76% to $86.5 million compared to $49.3 million in 2003. This
increase was primarily attributable to a 15% increase in natural gas and oil
production (25% increase in net production contributing to cash flow from
operating activities) and a 19% increase in natural gas and oil prices,
partially offset by lower non-oil and gas revenue, higher operating expenses and
a $3.7 million redemption premium associated with the early redemption of our
8 7/8% senior subordinated notes due in 2006. Income tax benefit for 2004 was
$13.9 million compared to $20.2 million in 2003 due to changes in our valuation
allowance against our net deferred tax asset. Please read Note 10 to our
Consolidated Financial Statements. In 2003, we recorded a cumulative effect of
accounting change of $0.9 million, or a $0.02 loss per basic and diluted share,
as a result of the adoption of SFAS No. 143. Income available to common
stockholders in 2004 was $100.4 million, or $2.06 per basic share and $2.03 per
diluted share, compared to $67.7 million, or $1.71 per basic and $1.61 per
diluted share, in 2003.

Income before income taxes and cumulative effect of accounting change for
2003 was $49.3 million compared to $9.8 million in 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 natural gas
production due to the expiration of our VPP program and the effect of the sale
of certain non-core oil and gas properties in 2002. Income tax benefit for 2003
was $20.2 million compared to an income tax expense of $13.8 million in 2002 due
to changes in our valuation allowance against our net deferred tax asset. Please
read Note 10 to our Consolidated Financial Statements. The cumulative effect of
accounting change was $0.9 million, or a $0.02 loss per basic and diluted share,
in 2003 resulting from the adoption of SFAS No. 143. In 2002, the cumulative
effect of accounting change was $6.2 million, or a $0.17 loss per basic and
diluted share, which reflected the change from the future gross revenue method
of accounting for amortization of capitalized costs related to oil and gas
properties to the UOP method. Income available to common stockholders in 2003
was $67.7 million, or $1.71 per basic share and $1.61 per diluted share,
compared to a loss of $11.1 million, or $0.31 per basic and diluted share, in
2002.

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

(a) Includes delivery obligations dedicated to the Production Payment.
Production includes 5,170 MMcfe in 2004, 6,807 MMcfe in 2003 and 11,196
MMcfe in 2002 dedicated to the Production Payment. Please read Note 1 to
our Consolidated Financial Statements for more information on the
Production Payment.

(b) We sold properties in 2002 to reduce debt.

(c) We discontinued making new investments in VPPs in 1999 and final deliveries
from our VPP program were received in November 2002. The average production
cost per Mcfe in 2002 excludes the production received under our purchased
VPP program because that production was free from these expenses.

(d) The average realized prices reported above include the non-cash effects of
volumes delivered under the Production Payment as well as the unwinding of
various derivative contracts terminated in 2001. These items do not
generate cash to fund our operations. Excluding these items, the average
realized price per Mcfe was $5.85, $5.05 and $3.19 in 2004, 2003 and 2002,
respectively. For further information, please read, "-- Major Influences on
Results of Operations."

Natural Gas Revenue. In 2004, natural gas revenue increased $55.6 million,
to $190.4 million, compared to $134.8 million in 2003 as a result of a 20%
increase in production and a 17% increase in realized natural gas prices. The
production increase was primarily due to our successful drilling program.

In 2003, natural gas revenue increased $38.3 million, to $134.8 million,
compared to $96.5 million in 2002 as a result of a 47% increase in realized
natural gas prices and a 5% decrease in production. The production decrease was
primarily due to the expiration of our VPP program, as new production from the
successful drilling program essentially offset the impact of 2002 property sales
and the natural decline of producing wells.

Oil and Liquids Revenue. In 2004, oil and liquids revenue increased $3.4
million to $28.4 million due to a 23% increase in average realized prices,
partially offset by an 8% decrease in production. In 2003, oil and liquids
revenue increased $1.5 million to $25.0 million due to a 25% increase in average
realized prices offset by a 15% decrease in production. The decrease in oil and
natural gas liquids production reflected the natural decline associated with our
oil and natural gas liquids properties as our drilling program over the last
several years has been focused almost entirely on natural gas prospects.

Other, net. In 2004, other, net was a loss of $1.5 million, of which $1.1
million was due to losses associated with certain derivatives that did not
qualify for hedge accounting treatment pursuant to SFAS No. 133. This compares
to other, net revenue of $5.0 million in 2003 which was primarily attributed to
the sale of emission reduction credits. Other, net was $5.0 million in 2003
compared to a net cost of $1.2 million in 2002. The increase was primarily
attributed to the sale of emission reduction credits. We do not anticipate that
there will be any significant sales of emission credits in 2005.

36

LEASE OPERATING EXPENSES

For the year ended December 31, 2004, lease operating expenses, or LOE,
increased $4.0 million, to $28.6 million, compared to $24.6 million in 2003 due
to generally higher service costs experienced industry-wide and the increase in
the number of producing wells as a result of our expanded drilling program. On a
per unit of production basis, LOE was $0.72 per Mcfe of WI production in 2004
compared to $0.71 per Mcfe in 2003.

For the year ended December 31, 2003, LOE increased $1.7 million, to $24.6
million, compared to $22.9 million in 2002. The increase was primarily
attributed to a higher level of workover activity on oil and gas wells in 2003.
On a per unit of production basis, LOE was $0.71 per Mcfe of WI production in
2003 compared to $0.65 per Mcfe in 2002.

PRODUCTION AND OTHER TAXES

Production and other taxes increased $4.2 million to $14.2 million in 2004,
compared to $10.0 million in 2003. The increase was primarily attributable to
increased production (severance) taxes due to higher oil and gas revenue and
higher ad valorem taxes due to the higher value of our oil and gas properties.

Production and other taxes increased $2.0 million to $10.0 million in 2003,
compared to $8.0 million in 2002. The increase was primarily attributable to
higher oil and natural gas revenue and higher production tax rates in Louisiana
where we significantly increased our production in the Elm Grove Field.

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative expenses, or G&A, increased $1.1 million to $9.1
million in 2004, compared to $8.0 million in 2003 primarily due to increased
costs to comply with corporate governance initiatives mandated by the
Sarbanes-Oxley Act of 2002 and the New York Stock Exchange and higher insurance
costs. On a per unit of the production basis, G&A was $0.23 per Mcfe in 2004 and
2003.

G&A decreased $0.3 million to $8.0 million in 2003, compared to $8.3
million in 2002. On a per unit of production cost basis, G&A was $0.23 per Mcfe
for 2003 and $0.24 for 2002. The overall decrease resulted from lower labor
costs associated with a reduced work force, partially offset by a 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 FASB Interpretation No. 44, "Accounting for Certain Transactions Involving
Stock Compensation," or FIN 44, 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 our common stock during that
period. For 2004, stock compensation was $2.6 million compared to $2.7 million
in 2003.

Stock compensation was $2.7 million in 2003 compared to $0.8 million in
2002 primarily due to the significant increase in the market price of our common
stock during 2003.

ACCRETION OF ASSET RETIREMENT OBLIGATION

Effective January 1, 2003, we adopted SFAS No. 143. Accretion of our asset
retirement obligation was $1.0 million in 2004 and $1.1 million in 2003.

DEPRECIATION, DEPLETION AND AMORTIZATION

We amortize our oil and gas properties using the UOP method based on proved
reserves. For the year ended December 31, 2004, depreciation, depletion and
amortization expense was $57.3 million ($1.43 per Mcfe) compared to $47.9
million ($1.38 per Mcfe) for the year ended December 31, 2003. This $9.4 million

37

increase reflects the higher production associated with our successful drilling
program and the increased cost of drilling wells.

For the year ended December 31, 2003, depreciation, depletion and
amortization expense was $47.9 million ($1.38 per Mcfe) compared to $49.3
million ($1.41 per Mcfe) for the year ended December 31, 2002. This $1.4 million
decrease was primarily attributable to reduced production as a result of the
expiration of our VPP program and the sale of certain non-core oil and gas
properties in 2002.

INTEREST AND OTHER INCOME

Interest and other income was $0.3 million in 2004 compared to $0.1 million
in 2003 and $0.3 million in 2002. These amounts primarily represent interest
income earned on accumulated cash and cash equivalents.

REDEMPTION PREMIUM ON EARLY EXTINGUISHMENT OF DEBT

On May 1, 2004, we redeemed our $125 million 8 7/8% senior subordinated
notes due 2006. Pursuant to the indenture, we paid an early redemption premium
of $3.7 million, which was charged against earnings in the second quarter of
2004.

INTEREST EXPENSE

Interest expense was $14.3 million in 2004 compared to $21.0 million in
2003. This significant decrease in interest expense in 2004 reflects reduced
amounts of average outstanding debt and substantially lower borrowing costs.

Interest expense was $21.0 million in 2003 compared to $19.9 million in
2002. The higher interest expense in 2003 reflects the $2.8 million write-off of
deferred financing costs and a $0.5 million early termination fee paid to a
previous lender as a result of amending and restating our bank credit facility
in November 2003 to increase availability and reduce future interest costs.
Interest expense excluding amortization of deferred financing costs was $1.2
million lower in 2003 compared to 2002 primarily due to lower average
outstanding debt in 2003.

INCOME TAXES

Income tax benefits were $13.9 million in 2004 compared to $20.2 million in
2003 and income tax expense of $13.8 million in 2002. These amounts reflect
changes in our valuation allowance against net deferred income tax assets. In
making our assessment of the valuation allowance, we perform an extensive
analysis of our operations to determine the sources of future taxable income.
The analysis consists of a detailed review of all available data, including our
budget for the ensuing year, forecasts based on current as well as historical
prices, and our oil and gas reserve report.

During the second quarter of 2002, uncertainty resulting from relatively
low commodity prices and the January 2003 maturity date for our senior notes led
management to increase the valuation allowance by $15.9 million. This increase
in the valuation allowance reduced the carrying value of net deferred assets to
zero. Since that time, we have generated significant levels of taxable income
due to drilling success and strong natural gas and oil prices. We believe that
the future outlook for continued generation of taxable income is positive based
on existing available information, including current prices quoted on the New
York Mercantile Exchange. Therefore, during 2003, we reversed approximately
$37.6 million of the valuation allowance and in 2004 reversed the remaining
$44.2 million of the valuation allowance related to expected taxes on future
years' taxable income.

LIQUIDITY AND CAPITAL RESOURCES

Our primary cash requirements are for the exploration, development and
acquisition of oil and gas properties, operating expenses and debt service. We
expect to fund our drilling activities primarily with internally generated cash
flow and to have sufficient capital resources available to allow us the
flexibility to be opportunistic with our drilling program and to fund larger
acquisitions and working capital requirements. We

38

believe this approach allows us to maintain an appropriate capital structure
that allows us to increase our oil and gas reserves and to reduce debt per Mcfe.
In 2004, we accelerated our drilling program given the relatively high oil and
gas price environment and drilled 130 wells with a 97% success rate. As a
result, we were able to significantly increase oil and gas production, reserves
and cash flow. Cash used in investing activities, primarily for our drilling
program, was $155.1 million. Net cash provided by operating activities was
$134.1 million. Proceeds from our senior notes offering discussed below funded
the remainder of our drilling program.

In April 2004, we completed a private placement of $175 million of 7 1/8%
senior notes due 2012. The net proceeds of this issuance were used to redeem our
$125 million 8 7/8% senior subordinated notes due 2006, to repay the $22 million
outstanding under our bank credit facility and for general corporate purposes,
including our drilling program. On May 1, 2004, we redeemed our $125 million
8 7/8% senior subordinated notes due 2006. Pursuant to the indenture, we paid an
early redemption premium of $3.7 million. Please read Note 6 to our Consolidated
Financial Statements for more information regarding our senior notes, including
a discussion of restrictive covenants.

We also have a bank credit facility that currently provides up to $100
million of revolving credit capacity and matures on November 20, 2006. There
were no outstanding borrowings under this facility as of December 31, 2004.
Borrowing capacity under the bank credit facility is subject to a borrowing base
(currently $100 million) and is reviewed at least semi-annually and may be
adjusted based on the lenders' valuation of our oil and natural gas reserves and
other factors. Please read Note 6 to our Consolidated Financial Statements for
more information regarding our bank credit facility, including a discussion of
restrictive covenants.

In February 2005, we entered into a purchase and sale agreement to acquire
certain oil and gas properties and related assets for approximately $94.7
million, subject to certain purchase price adjustments. The transaction is
subject to due diligence and other conditions prior to closing, which is
scheduled to occur in mid-April 2005. We expect to initially finance the
acquisition with cash on hand and borrowings under our bank credit facility.
Please read Note 15 to our Consolidated Financial Statements for more
information regarding this acquisition.

In 2005, we have budgeted approximately $190 million for capital
investments in natural gas and oil properties, excluding the cost of
acquisitions, and anticipate drilling approximately 150 wells. We expect to fund
our 2005 exploration and development activities primarily through internally
generated cash flows. The amount and allocation of our capital investment
program is subject to change based on operational developments, commodity
prices, service costs, acquisitions and numerous other factors. Generally, we do
not budget for acquisitions.

Our net working capital position as of December 31, 2004 was a deficit of
$28.7 million. On that date, we had $100.0 million of unused availability under
our bank credit facility and $6.6 million of cash on hand. Working capital
deficits are not unusual in our industry. We, like many other oil and gas
companies, typically maintain relatively low cash reserves and use any excess
cash to fund our capital expenditure program or pay down borrowings under our
bank credit facility. The December 31, 2004 working capital deficit was higher
than usual due mainly to the high level of accrued drilling costs ($21.9
million) as a result of our active drilling program.

We believe that cash on hand, net cash generated from operations and unused
committed borrowing capacity under our bank credit facility will be adequate to
fund our capital expenditure program and satisfy our liquidity needs. In the
future, we may also utilize various financing sources available to us, including
the issuance of debt or equity securities under our shelf registration statement
or through private placements. Our ability to complete future debt and equity
offerings and the timing of these offerings will depend upon various factors
including prevailing market conditions, interest rates and our financial
condition.

CASH FLOW FROM OPERATING ACTIVITIES

Net cash provided by operating activities for 2004 was $134.1 million
compared to $71.0 million in 2003. The 89% improvement in our cash flow in 2004
was primarily due to higher production, higher realized oil and

39

natural gas prices and decreased delivery obligations under the Production
Program. The net increase in trade accounts receivable also reflects the higher
natural gas and oil price environment in 2004 and the timing of cash receipts
for sales of our increased production. The net change in accounts payable and
accrued liabilities is primarily attributable to our expanded drilling program.

Net cash provided by operating activities for 2003 was $71.0 million
compared to $20.8 million 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. The net
increase 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 increased
drilling well pre-payments received from non-operating working interest owners
and higher incentive compensation accruals.

INVESTING ACTIVITIES

Net cash used in investing activities in 2004 was $155.1 million, virtually
all of which was for oil and gas properties, compared to net cash used in
investing activities of $79.0 million in 2003 and $18.1 million in 2002. In
2003, we invested $78.1 million in oil and gas properties, and in 2002, we
invested $48.6 million in oil and gas properties and realized $30.5 million from
the sale of non-core properties.

Capital expenditures for the year ended December 31, 2004 were $167.2
million, including $132.1 million used for development activities, $34.1 million
used for lease acquisitions, seismic surveys and exploratory drilling, $0.5
million in capitalized asset retirement obligation and $0.5 million used for
other assets. These amounts include costs that were incurred and accrued as of
December 31, 2004 but are not reflected in the net cash used in investing
activities above until payment is made in 2005.

Capital expenditures for the year ended December 31, 2003 were $88.8
million, including $78.2 million used for development activities, $9.9 million
used for lease acquisitions, seismic surveys and exploratory drilling and $0.7
million used for other assets. These amounts include costs that were incurred
and accrued as of December 31, 2003 but not reflected in the net cash used in
investing activities above until payment was made in 2004.

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

FINANCING ACTIVITIES

Net cash provided by financing activities in 2004 was $25.4 million due to
the refinancing of our debt as discussed above and in Note 6 to our Consolidated
Financial Statements. Net cash provided by financing activities was $3.2 million
in 2003 and net cash used in financing activities was $18.8 million in 2002. In
2003, net proceeds from our common stock offering were $52.0 million, proceeds
from borrowings under the bank credit facility were $69.3 million, repayments of
debt were $114.1 million and net payments of deferred financing costs and other
were $4.0 million. In 2002, proceeds from borrowings were $0.5 million,
repayments of debt were $18.5 million and payments for deferred financing costs
and other were $0.7 million.

SHELF REGISTRATION STATEMENT/COMMON STOCK OFFERING

In September 2003, we, along with two of our operating subsidiaries, KCS
Resources, Inc. and Medallion California Properties Company, filed a $200.0
million universal shelf registration statement with the Securities and Exchange
Commission. The shelf registration statement covers 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 of those securities. We may, in one or more offerings, offer and
sell common stock, preferred stock, warrants and units. We may also, in one or
more offerings, offer and sell senior unsecured and senior subordinated debt
securities. Under our shelf registration statement, our senior

40

unsecured and senior subordinated debt securities may be fully and
unconditionally guaranteed by KCS Resources, Inc. and Medallion California
Properties Company.

During the fourth quarter of 2003, in a public offering under our shelf
registration statement, we sold 6.9 million shares of our common stock at $8.00
per share. We used a portion of the net proceeds of approximately $52.0 million
to repay borrowings under our bank credit facility and to accelerate our
drilling program in certain core areas.

As of December 31, 2004, there was $144.8 million remaining under our shelf
registration statement.

CONTRACTUAL CASH OBLIGATIONS

The following table summarizes our future contractual cash obligations as
of December 31, 2004 (in thousands).

The above table does not include the liability for dismantlement,
abandonment and restoration cost of oil and gas properties. Please read Note 2
to our Consolidated Financial Statements for further discussion.

OTHER COMMERCIAL COMMITMENTS

In connection with the Production Payment, we have obligations to deliver
3.9 Bcfe in 2005 and 0.2 Bcfe in 2006. As of December 31, 2004, we had $2.5
million of surety bonds that remain outstanding until specific events or
projects are completed and any claims that may be made are settled.

OFF-BALANCE SHEET ARRANGEMENTS

We do not utilize and are not currently contemplating using any off-balance
sheet arrangements with unconsolidated entities to enhance liquidity and capital
resource positions or for any other purpose. Any future transactions involving
off-balance sheet arrangements will be scrutinized and disclosed by our
management.

NEW ACCOUNTING PRINCIPLES

The Securities and Exchange Commission issued Staff Accounting Bulletin No.
106, or SAB No. 106, effective October 1, 2004. SAB No. 106 provides
interpretive guidance on how full cost companies should reflect asset retirement
obligations, or ARO, in their full cost ceiling and depreciation, depletion and
amortization expense calculations. SAB No. 106 requires future cash outflows
associated with settling ARO's that have accrued on the balance sheet to be
excluded from the computation of the present value of estimated future net
revenues for purposes of the full cost ceiling calculation. SAB No. 106 also
requires the inclusion of the estimated amount of ARO that will be incurred as a
future development activity on proved reserves in the costs to be amortized.
Since we were already applying the provisions of SAB No. 106, there was no
impact on us after adoption.

On December 16, 2004, the Financial Accounting Standards Board, or FASB,
issued FASB Statement No. 123 (Revised 2004) "Share-Based Payment," or SFAS
123(R), which is a revision of SFAS Statement No. 123, "Accounting for
Stock-Based Compensation." SFAS 123(R) requires all share-based payments to
employees, including grants of employee stock options, to be recognized in the
financial statements based on their fair values. We are currently evaluating the
impact of this revised standard which is effective on July 1, 2005.

41

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

All information and statements included in this section, other than
historical information and statements, are "forward-looking statements." Please
read "Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Forward-Looking Statements."

COMMODITY PRICE RISK

Our major market risk exposure is to oil and natural 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. We have utilized, and may continue to utilize, derivative
contracts, including swaps, futures contracts, options and collars to manage
this price risk. We do not enter into derivative or other financial instruments
for trading or speculative purposes. While these derivative contracts are
structured to reduce our exposure to decreases in the price associated with the
underlying commodity, they also limit the benefit we might otherwise receive
from price increases. We maintain a system of controls that includes a policy
covering authorization, reporting and monitoring of derivative activity.

As of December 31, 2004, we had derivative instruments outstanding covering
8.6 million MMBtu of 2005 natural gas production, 1.4 million MMBtu of 2006
natural gas production and 0.2 million barrels of 2005 oil production, with a
fair market value of $1.3 million. In addition, we had commodity basis swaps
outstanding covering 0.5 million MMBtu.

As of December 31, 2003, we had derivative instruments outstanding covering
8.8 million MMBtu of 2004 natural gas production and 0.1 million barrels of 2004
oil production, with a fair market value of $0.7 million.

The following table sets forth information with respect to our oil and
natural gas hedged position as of December 31, 2004. There were no derivative
instruments outstanding beyond the first quarter of 2006.

In addition to the information set forth in the table above, we will
deliver 3.9 Bcfe in 2005 and 0.2 Bcfe in 2006 under the Production Payment and
amortize deferred revenue at a weighted average discounted price of
approximately $4.05 per Mcfe.

During 2004, we delivered approximately 13% of our production under the
Production Payment and entered into derivative arrangements designed to reduce
price downside risk for approximately 53% of the balance of our production.
During 2003, we delivered approximately 20% of our production under the
Production Payment and also entered into derivative contracts that covered
approximately 20% of the balance of our production.

Commodity Price Swaps. Commodity price swap agreements require us to make
payments to, or entitle us to 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 us 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, we are
able to set a floor price for a specified quantity of our oil or natural gas
production. By selling a "call" option, we receive an upfront premium from
selling the right for a counter party to buy a specified quantity of oil or
natural gas production at a fixed price.

Price Collars. Selling a call option and buying a put option creates a
"collar" whereby we establish 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 establishes a "3-way collar" that entitles us to capture the benefit
of price increases above that call price.

Commodity Basis Swaps. Commodity basis swap agreements require the us to
make payments to, or receive payments from, the counterparties based upon the
differential between certain pricing indices and a stated differential amount.

Please read Note 11 to our Consolidated Financial Statements for more
information regarding our derivatives.

43

INTEREST RATE RISK

We use fixed and variable rate long-term debt to finance our capital
spending program and for general corporate purposes. Our variable rate debt
instruments expose us to market risk related to changes in interest rates. Our
fixed rate debt and the associated weighted average interest rate was $175.0
million at 7 1/8% as of December 31, 2004 and $125.0 million at 8 7/8% as of
December 31, 2003. We had no variable rate debt outstanding as of December 31,
2004. Our variable rate debt and weighted average interest rate was $17.0
million at 3.6% as of December 31, 2003.

The tables below present principal cash flows and related average interest
rates by expected maturity date for our debt obligations as of December 31, 2004
and 2003 (dollars in millions).

44

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

MANAGEMENT'S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING

Management of KCS, including the Chief Executive Officer and the Chief
Financial Officer, is responsible for establishing and maintaining adequate
internal control over financial reporting, as defined in Rules 13a-15(f) and
15d-15(f) of the Securities Exchange Act of 1934, as amended, for KCS. Our
internal control system was designed to provide reasonable assurance as to the
reliability of our financial reporting and the preparation and fair presentation
of the consolidated financial statements for external purposes in accordance
with accounting principles generally accepted in the United States.

Management conducted an assessment of the effectiveness of our internal
control over financial reporting as of December 31, 2004 based on the framework
in Internal Control -- Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. This assessment included
review of the documentation of controls, evaluation of the design effectiveness
of controls, testing of the operating effectiveness of controls and a conclusion
on this assessment. Through this assessment, we did not identify any material
weaknesses in our internal control over financial reporting. There are inherent
limitations in the effectiveness of any system of internal control over
financial reporting; however, based on our assessment, we have concluded that
our internal control over financial reporting was effective as of December 31,
2004 based on the aforementioned criteria.

Ernst & Young LLP, our independent registered public accounting firm, has
issued an attestation report on management's assessment of internal control over
financial reporting, which is included on the following page of this report.

45

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited management's assessment, included in the accompanying
Management's Report on Internal Control Over Financial Reporting, that KCS
Energy, Inc. and subsidiaries maintained effective internal control over
financial reporting as of December 31, 2004, based on criteria established in
Internal Control -- Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO criteria). KCS Energy, Inc.'s
management is responsible for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness of internal
control over financial reporting. Our responsibility is to express an opinion on
management's assessment and an opinion on the effectiveness of the company's
internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating management's assessment, testing
and evaluating the design and operating effectiveness of internal control, and
performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our
opinion.

A company's internal control over financial reporting is a process designed
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that KCS Energy, Inc. and
subsidiaries maintained effective internal control over financial reporting as
of December 31, 2004, is fairly stated, in all material respects, based on the
COSO criteria. Also, in our opinion, KCS Energy, Inc. and subsidiaries
maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2004, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the consolidated balance
sheets of KCS Energy, Inc. and subsidiaries as of December 31, 2004 and 2003,
and the related consolidated statements of operations, stockholders' equity
(deficit), and cash flows for each of the three years in the period ended
December 31, 2004 and our report dated March 11, 2005 expressed an unqualified
opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas
March 11, 2005

46

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying consolidated balance sheets of KCS Energy,
Inc. and subsidiaries as of December 31, 2004 and 2003, and the related
consolidated statements of operations, stockholders' equity (deficit), and cash
flows for each of the three years in the period ended December 31, 2004. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.

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

In our opinion, the 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, 2004 and 2003 and the consolidated
results of their operations and their cash flows for each of the three years
ended December 31, 2004, in conformity with U.S. generally accepted accounting
principles.

As described in Note 2, effective January 1, 2002, the company changed its
method of accounting for the amortization of its oil and gas properties. In
addition, as described in Note 2, effective January 1, 2003, the Company changed
its method of accounting for asset retirement obligations in accordance with
Statement of Financial Accounting Standards No. 143.

We also have audited in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the effectiveness of KCS Energy,
Inc. and subsidiaries' internal control over financial reporting as of December
31, 2004, based on criteria established in Internal Control -- Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission and our report dated March 11, 2005 expressed an unqualified opinion
thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas
March 11, 2005

47

KCS ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED OPERATIONS

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

48

KCS ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

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

49

KCS ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY (DEFICIT)

The accompanying notes are an integral part of these financial statements.
50

KCS ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

The accompanying notes are an integral part of these financial statements.
51

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, development and production of natural gas and crude
oil with operations predominately in the Mid-Continent and Gulf Coast regions of
the United States.

PRINCIPLES OF CONSOLIDATION

The consolidated financial statements include the accounts of KCS Energy,
Inc. and its wholly-owned subsidiaries ("KCS" or "Company"). The Company
consolidates all investments in which it, either through direct or indirect
ownership, has more than a fifty percent voting interest and/or control. All
significant intercompany accounts and transactions have been eliminated in
consolidation.

RECLASSIFICATIONS

Certain previously reported amounts have been reclassified to conform to
current year presentation.

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 as of 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.

CASH EQUIVALENTS

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

DERIVATIVE INSTRUMENTS

Oil and natural 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 or range of prices of certain sales volumes for certain time periods.

The Company accounts for derivative instruments in accordance with
Statement of Financial Accounting Standards ("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. SFAS No. 133, as amended, 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, or 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, net 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 continues 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 with a
terminated derivative will immediately be reclassified from OCI into earnings.
If the contract is not
52

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

designated as a hedge, changes in fair value are recorded to other, net in the
Statement of Consolidated Operations.

FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying value of certain financial instruments, including cash, cash
equivalents and revolving credit debt approximates estimated fair value due to
their short-term maturities and variable 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, and other internal costs directly associated
with acquisition, exploration and development activities. Historically, total
capitalized internal costs in any given year have not been material to the total
oil and gas costs capitalized in that year. 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. Prior to
January 1, 2002, the Company utilized the future gross revenue method for
providing depreciation, depletion and amortization. Effective January 1, 2002,
the Company began providing for depreciation, depletion and amortization, or
DD&A, of evaluated costs using the unit-of-production method based on proved
reserves, including reserves associated with the Production Payment. Prior to
2003, future development costs and asset retirement obligations were added to
the amortizable base. Beginning in 2003, the Company adopted SFAS No. 143
"Accounting for Asset Retirement Obligations" that changed its accounting for
dismantlement, restoration and abandonment costs. The Company includes the
estimated amount of asset retirement obligations that will be incurred in
connection with future development activity on proved reserves in the costs to
be amortized. Please read Note 2 to Consolidated Financial Statements for more
information about these accounting changes. Costs directly associated with the
acquisition and evaluation of unproved properties are excluded from the
depreciation, depletion and amortization 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 $11.2
million and $6.8 million as of December 31, 2004 and 2003, respectively. The
Company will begin to amortize these costs when proved reserves are established
or impairment is determined.

The Company performs quarterly "ceiling test" calculations as capitalized
costs of oil and gas properties, net of accumulated depreciation, depletion and
amortization and related deferred taxes, are limited to the sum of the present
value of estimated future net revenues from proved oil and natural gas reserves
at current prices discounted at 10%, plus the lower of cost or fair value of
unproved properties, net of related tax effects. To the extent that the
capitalized costs exceed this "ceiling" limitation at the end of any quarter,
the excess is expensed. Upon the adoption of SFAS No. 143 in the beginning of
2003, the Company began including the capitalized cost of its asset retirement
obligations in the oil and gas property balance and excluding the corresponding
cash outflow associated with future abandonment cost from future development
cost when calculating the pre-tax present value of future net revenues. In
September 2004, the SEC issued Staff Accounting Bulletin No. 106 ("SAB No. 106")
effectively mandating this treatment. Accordingly, SAB No. 106 had no effect on
the Company's accounting.

53

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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
(generally more than 25%) of the Company's proved reserves are sold.

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

Oil and natural gas revenues are recognized when production is sold to a
purchaser at fixed or determinable prices, when delivery has occurred and title
has transferred and collectibility of the revenue is probable. The Company
follows the sales method of accounting for natural gas revenues. Under this
method of accounting, revenues are recognized based on volumes sold. The volume
of natural gas volumes sold may differ from the volume to which the Company 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. Under the sales method, no receivables are recorded where the
Company has taken less than its share of production. Natural gas imbalances are
reflected as adjustments to proved natural gas reserves and future cash flows in
the unaudited supplemental oil and gas disclosures. Cash received relating to
future revenue is deferred and recognized when all revenue recognition criteria
have been met.

In February, 2001, the Company sold a 43.1 Bcfe (38.3 Bcf of natural gas
and 797,000 barrels of oil) production payment, or Production Payment, to be
delivered in accordance with an agreed schedule over a five-year period for net
proceeds of approximately $175.0 million. The Company recorded the net proceeds
from the sale of the Production Payment as deferred revenue on the balance
sheet. Deliveries under this Production Payment are recorded as non-cash oil and
natural 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 natural gas reserves are excluded from the Company's reserve data.
During 2004, the Company delivered 5.2 Bcfe under this Production Payment and
recorded $21.4 million of oil and natural gas revenue. During 2003, the Company
delivered 6.8 Bcfe under the Production Payment and recorded $27.9 million of
oil and gas revenue. During 2002, the Company delivered 11.2 Bcfe under the
Production Payment and recorded $45.2 million of oil and gas revenue previously
deferred. Since the sale of the Production Payment in February 2001 through
December 31, 2004, the Company has delivered 38.9 Bcfe, or 90% of the total
quantity to be delivered. For 2005, scheduled deliveries under the Production
Payment are 3.9 Bcfe.

STOCK COMPENSATION

The cost of awards of restricted stock, determined as the market value of
the shares as of the date of grant, is expensed ratably over the restricted
period. Stock options issued under the 2001 Stock Plan within six months of the
cancellation of options in connection with our plan of reorganization are
subject to variable accounting in accordance with Financial Accounting Standards
Board Interpretation No. 44, "Accounting for Certain Transaction Involving Stock
Compensation." 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 our common stock during that period. Please read Note 5
for more information on the Company's stock option and incentive plans.

As permitted under SFAS No. 123 "Accounting for Stock-Based Compensation,"
or SFAS No. 123, as amended, the Company has elected to continue to account for
stock options under the provisions of Accounting Principles Board ("APB")
Opinion No. 25 "Accounting for Stock Issued to Employees." Under
54

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

this method, the Company does not record any 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,
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 $4.9 million as of December 31, 2004 and 2003. Included in the
allowance is $3.7 million that represents a 79% reserve against receivables from
various Enron entities currently 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
natural gas sales and joint interest owner receivables, to various companies in
the oil and gas industry. These extensions of credit may result in a
concentration of credit risk. The concentration of credit risk may be affected
by changes in economic or other
55

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 numerous parties.

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 as of the end of each year. A
valuation allowance is recognized as a charge against earnings if, at the time,
it is anticipated that some or all of a deferred tax asset may not be realized.

COMMON STOCK OUTSTANDING

SEGMENT REPORTING

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

NEW ACCOUNTING PRINCIPLES

The SEC issued SAB No. 106. SAB No. 106 provides interpretive guidance on
how full cost companies should reflect asset retirement obligations ("ARO") in
their full cost ceiling and DD&A calculations. SAB No. 106 requires future cash
outflows associated with settling ARO's that have accrued on the balance sheet
to be excluded from the computation of the present value of estimated future net
revenues for purposes of the full cost ceiling calculation. SAB No. 106 also
requires the inclusion of the estimated amount of ARO that will be incurred as a
future development activity on proved reserves in the costs to be amortized. As
discussed above, the Company had been following this approach. Accordingly,
adoption of SAB No. 106 had no impact on the Company.

On December 16, 2004, the Financial Accounting Standards Board issued SFAS
No. 123 (Revised 2004) "SFAS 123(R)," "Share-Based Payment," which is a revision
of SFAS No. 123, "Accounting for Stock-Based Compensation." SFAS 123(R)
supersedes APB Opinion No. 25, and amends SFAS Statement No. 95, "Statement of
Cash Flows." Generally, the approach in SFAS 123(R) is similar to the approach
described in SFAS 123. However, SFAS 123(R) requires all share-based payments to
employees, including grants of employee stock options, to be recognized in the
income statement based on their fair values. Pro forma disclosure is no longer
an alternative.

56

KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

SFAS 123(R) permits public companies to adopt its requirements using one of
two methods:

A "modified prospective" method in which compensation cost is recognized
beginning with the effective date (a) based on the requirements of SFAS 123(R)
for all share-based payments granted after the effective date and (b) based on
the requirements of SFAS 123 for all awards granted to employees prior to the
effective date of SFAS 123(R) that remain unvested on the effective date.

A "modified retrospective" method which includes the requirements of the
modified prospective method described above, but also permits entities to
restate based on the amounts previously recognized under SFAS 123 for purposes
of pro forma disclosures either (a) all prior periods presented or (b) prior
interim periods of the year of adoption.

The Company plans to adopt SFAS 123(R) on July 1, 2005 using the
modified-prospective method.

The impact of adoption of SFAS 123(R) on the Company's results of
operations cannot be predicted at this time because it will depend on levels of
share-based payments granted in the future. However, had we adopted SFAS 123(R)
in prior periods, the impact of that standard would have approximated the impact
of SFAS 123 as described in the table above. SFAS 123(R) will have no impact on
the Company's overall financial position.

2. ACCOUNTING CHANGES

ASSET RETIREMENT OBLIGATIONS

Effective January 1, 2003, the Company adopted 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.
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. Included in
other assets at December 31, 2004 is $2.5 million held in escrow accounts
related to certain asset retirement obligations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table illustrates the pro forma effects on income
attributable to common stock, earnings per share and asset retirement obligation
if the Company had adopted SFAS No. 143 as of January 1, 2002.

The following table summarizes the changes in the Company's total estimated
liability from the amount recorded upon adoption of SFAS No. 143 on January 1,
2003 through December 31, 2004:

AMORTIZATION OF OIL AND GAS PROPERTIES

Effective January 1, 2002, the Company began amortizing the capitalized
costs related to oil and gas properties on the unit-of-production, or UOP,
method using proved oil and natural gas reserves. Previously, the Company had
computed amortization on the basis of future gross revenues, or 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. 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.

3. 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.

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KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

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

4. RETIREMENT BENEFIT PLAN

The Company sponsors a Savings and Investment Plan, or Savings Plan, under
Section 401(k) of the Internal Revenue Code. Eligible employees may contribute a
portion of their compensation, as defined under the Savings Plan, to the Savings
Plan, subject to certain Internal Revenue Service limitations. The Company may
make matching contributions, which have been set by the Company's 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 Company's 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 shares of the
Company's 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 immediately vest. Company contributions to the Savings Plan were
$633,818 in 2004, $524,419 in 2003 and $531,103 in 2002.

5. STOCK OPTION AND INCENTIVE PLANS

The KCS Energy, Inc. 2001 Employees and Directors Stock Plan, or 2001 Stock
Plan, provides that stock options, stock appreciation rights, restricted stock
and bonus stock may be granted to employees of the

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Company. The 2001 Stock Plan also provides that annually, each non-employee
director receive shares of the Company's common stock with a fair market value
equal to 50% of their annual retainer in lieu of cash and grants of stock
options for 1,000 shares. 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 compensation vest immediately. All other
options vest ratably on the anniversary of the date of grant over a period of
time, typically three years. All options expire 10 years after the date of
grant. On February 20, 2001, in connection with the Plan of Reorganization, the
Company's 1992 Stock Plan and the 1994 Directors' Stock Plan and all outstanding
options thereunder were cancelled. Options issued under the 2001 Stock Plan
within six months of this cancellation are subject to variable accounting in
accordance with Financial Accounting Standards Board Interpretation No. 44,
"Accounting for Certain Transaction Involving Stock Compensation." 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 the
Company's common stock during that period. During 2004 and 2003, the Company
recorded $1.6 million and $1.9 million respectively as stock compensation in the
Statements of Consolidated Operations related to the options subject to variable
accounting. The Company did not record any stock compensation expense related to
stock options in 2002 since the stock options were "out of the money."

Restricted shares awarded under the 2001 Stock Plan have a restriction
period of three years. During the restriction period, 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. As of
December 31, 2004, there were 586,279 outstanding shares of restricted stock.

As of December 31, 2004, a total of 977,606 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 as
of December 31, 2004, 2003, and 2002 and changes during the years then ended is
presented in the table 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 2004: (1) risk-free
interest rate of 4.47%; (2) expected dividend yield of 0.00%; (3) expected life
of 10 years; and (4) expected stock price volatility of 90.7%. The weighted
average assumptions used for grants in 2003 were: (1) risk-free interest rate of
3.67%; (2) expected dividend yield of 0.00%; (3) expected life of 10 years; and
(4) expected stock price volatility of 88.6%. The

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KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

weighted average assumptions used for grants in 2002 were: (1) risk-free
interest rate of 5.3%; (2) expected dividend yield of 0.00%; (3) expected life
of 10 years; and (4) expected stock price volatility of 86.7%.

The following table summarizes information about stock options outstanding
as of December 31, 2004.

The Company has an employee stock purchase program, or Program. Under the
Program, 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. The maximum annual purchase for
directors is 6,000 shares. The number of shares issued in connection with the
Program was 2,525 shares, 19,394 shares and 8,209 shares during 2004, 2003 and
2002, respectively. As of December 31, 2004, there were 754,070 shares available
for issuance under the Program.

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KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

6. DEBT

The following table sets forth information regarding the Company's
outstanding debt.

Bank Credit Facility. The Company has a bank credit facility that provides
up to $100 million of revolving borrowing capacity and matures on November 20,
2006. Borrowing capacity under the bank credit facility is subject to a
borrowing base (currently $100 million) and is reviewed at least semi-annually
and may be adjusted based on the lenders' valuation of the Company's oil and
natural gas reserves and other factors. Substantially all of the Company's
assets, including the stock of all of its subsidiaries, are pledged to secure
the bank credit facility. Further, each of the Company's subsidiaries has
guaranteed its obligations under the bank credit facility.

Effective December 1, 2004, borrowings under the bank credit facility bear
interest, at the Company's option, at an interest rate of LIBOR plus 1.75% to
2.5% or the greater of (1) the Federal Funds Rate plus 0.5% or (2) the Base
Rate, plus 0.0% to 0.75%, depending on utilization. These rates will decrease by
0.5% after the final deliveries are made in connection with the Production
Payment entered into by the Company in 2001 and the lien on the subject property
is released. Also effective December 1, 2004, a commitment fee of 0.35% to 0.5%
per year, depending on utilization, is paid on the unused availability under the
bank credit facility. From November 18, 2003 through November 30, 2004, the
applicable margin for LIBO rate loans was 2.25% to 3.0%, the applicable margin
for base rate loans was 0.5% to 1.25%, depending on utilization and the
commitment fee was 0.5% per year on the unused availability under the credit
facility.

The bank credit facility contains various restrictive covenants, including
minimum levels of liquidity and interest coverage. The bank credit facility also
contains other usual and customary terms and conditions of a conventional
borrowing base facility, including prohibitions on a change of control,
prohibitions on the payment of cash dividends, restrictions on certain other
distributions and restricted payments, and limitations on the incurrence of
additional debt and the sale of assets.

As of December 31, 2004, we did not have any outstanding amounts under the
bank credit facility and had $100 million of unused borrowing capacity available
for future financing needs. In addition, the Company was in compliance with all
covenants under the bank credit facility as of that date.

Senior Notes. On April 1, 2004, the Company issued $175 million of 7 1/8%
senior notes due April 1, 2012 (the "Senior Notes"). The Senior Notes bear
interest at a rate of 7 1/8% per annum with interest payable semi-annually on
April 1 and October 1. The Company may redeem the Senior Notes at its option, in
whole or in part, at any time on or after April 1, 2008 at a price equal to 100%
of the principal amount plus accrued and unpaid interest, if any, plus a
specified premium which decreases yearly from 3.563% in 2008 to 0% in 2010 and
thereafter. In addition, at any time prior to April 1, 2007, the Company may
redeem up to a maximum of 35% of the aggregate principal amount with the net
cash proceeds of one or more equity offerings at a price equal to 107.125% of
the principal amount, plus accrued and unpaid interest. The Senior Notes are
senior unsecured obligations and rank subordinate in right of payment to all
existing and future secured debt,

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KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

including secured debt under the Company's bank credit facility, and will rank
equal in right of payment to all existing and future senior indebtedness.

The Senior Notes are jointly and severally and fully and unconditionally
guaranteed on a senior unsecured basis by all of the Company's current
subsidiaries. KCS Energy, Inc., the issuer of the Senior Notes, has no
independent assets or operations apart from the assets and operations of its
subsidiaries.

The indenture governing the Senior Notes contains covenants that, among
other things, restricts or limits the ability of the Company and the subsidiary
guarantors to: (i) borrow money; (ii) pay dividends on stock; (iii) purchase or
redeem stock or subordinated indebtedness; (iv) make investments; (v) create
liens; (vi) enter into transactions with affiliates; (vii) sell assets; and
(viii) merge with or into other companies or transfer all or substantially all
of the Company's assets.

In addition, upon the occurrence of a change of control (as defined in the
indenture governing the Senior Notes), the holders of the Senior Notes will have
the right to require the Company to repurchase all or any part of the Senior
Notes at a purchase price equal to 101% of the aggregate principal amount, plus
accrued and unpaid interest, if any.

The Company received $171.1 million in net proceeds from the issuance of
the Senior Notes. Net proceeds of the issuance were used to redeem the aggregate
principal amount of the Company's $125 million 8 7/8% senior subordinated notes
due 2006 (the "Senior Subordinated Notes") together with an early redemption
premium of $3.7 million, to repay the $22 million outstanding under the
Company's bank credit facility, and for general corporate purposes.

The Senior Subordinated Notes were redeemed on May 1, 2004 and the early
redemption premium of $3.7 million was charged against earnings in the second
quarter of 2004. In addition, the Company incurred an additional $0.9 million of
interest expense as both the Senior Subordinated Notes and the Senior Notes were
outstanding during the month of April 2004.

OTHER INFORMATION

The estimated fair value of the Company's Senior Notes was $184.2 million
based on quoted market values at December 31, 2004. The estimated fair value of
the Company's Senior Subordinated Notes was $130.0 million based on quoted
market values at December 31, 2003.

None of the Company's outstanding debt at December 31, 2004 is scheduled to
mature during the next five years.

Total interest payments were $15.3 million in 2004, $18.6 million in 2003
and $19.2 million in 2002. Capitalized interest was $0.6 million in 2004, $0.4
million in 2003 and $0.7 million in 2002.

7. SHELF REGISTRATION STATEMENT/COMMON STOCK OFFERING

On September 16, 2003, KCS Energy, Inc., 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. The shelf registration statement covers 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 of those securities. The Company may, in one or more offerings,
offer and sell common stock, preferred stock, warrants and units. The Company
may also, in one or more offerings, offer and sell senior unsecured and senior
subordinated debt securities. Under the Company's shelf registration statement,
its senior unsecured and senior subordinated debt securities may be fully and
unconditionally guaranteed by KCS Resources, Inc. and Medallion California
Properties Company.

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KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

On November 26, 2003, in a public offering under our shelf registration
statement, the Company sold 6.0 million shares of its common stock at $8.00 per
share. On December 11, 2003, the underwriters exercised their over-allotment
option and the Company sold an additional 0.9 million shares of common stock at
$8.00 per share. As of December 31, 2004, there was $144.8 million remaining
under our shelf registration statement.

8. REDEEMABLE CONVERTIBLE PREFERRED STOCK

On September 15, 2003, the Company issued a redemption notice to holders of
its Series A Convertible Preferred Stock in accordance with the provisions in
the Certificate of Designation, Preferences, Rights and Limitations of the
Preferred Stock, or Certificate of Designation. Under the Certificate of
Designation, the Company had the option to redeem the Preferred Stock if the
closing price of the Company's 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 conversion rights.

Background. In February 2001, the Company issued 30,000 shares of Series A
Convertible Preferred Stock, $0.01 par value, or Preferred Stock, at a price of
$1,000 per share. The Preferred Stock was convertible at any time into a total
of 10,000,000 shares of the Company's common stock at a conversion price of
$3.00 per share. Net proceeds from the issuance of the Preferred Stock were
$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. A dividend of
5% per year was paid quarterly in cash or, during the first two years following
issuance, in shares of the Company's 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. While outstanding, the Preferred Stock had no voting rights except
upon certain defaults or failure to pay dividends and as otherwise required by
law. The Preferred Stock had a liquidation preference of $1,000 per share plus
accrued and unpaid dividends and ranked senior to common stock or any subsequent
issue of preferred stock.

In connection with the issuance of the Preferred Stock, the Company also
issued warrants to the placement agent to purchase 400,000 shares of the
Company's common stock at $4.00 per share. In January 2004, one half of the
warrants were exercised and the remaining warrants were exercised in March 2005.

As a result of conversions of the Preferred Stock, 4.4 million and 1.0
million shares of common stock were issued in 2003 and 2002, respectively. In
addition 0.4 million shares of common stock were issued as dividends on the
preferred stock in 2002.

9. 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)
$1.7 million in 2005; (2) $0.4 million in 2006; and (3) less than $0.1 million
after 2006. Lease payments charged to operating expenses amounted to $2.0
million, $1.7 million and $1.3 million during 2004, 2003 and 2002, respectively.
In addition, the Company has unconditional purchase obligations, primarily
related to natural gas transportation contracts, of $3.0 million in 2005 and
$0.7 million in 2006.

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KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

10. 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:

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KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Federal alternative minimum tax payments, or AMT, of $1.0 million and $0.7
million were made in 2004 and 2003, respectively. No federal income tax payments
were made during 2002. There were no state income tax payments in 2004 or 2003.
State income tax payments were $0.5 million in 2002.

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 Company's oil and gas 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 $162.0 million have remaining lives ranging from 14 to 18 years,
management examines 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 our senior notes led
management to increase the valuation allowance by $15.9 million. This increase
in the valuation allowance reduced the carrying value of net deferred assets to
zero. Since that time, the Company has generated significant levels of taxable
income due to drilling success and strong natural gas and oil prices. The
Company believes that its future outlook for continued generation of taxable
income is positive based on existing available information, including current
prices quoted on the New York Mercantile Exchange. Therefore, during 2003, the
Company reversed approximately $37.6 million of the valuation allowance and in
2004 reversed the remaining $44.2 million of the valuation allowance related to
expected taxes on future years' taxable income.

As of December 31, 2004, the Company had tax net operating losses, or NOLs,
of approximately $162.0 million available to offset future taxable income,
including approximately $73.8 million that will expire in 2018, $34.1 million
that will expire in 2019, $26.0 million that will expire in 2020 and $28.1
million that will expire in 2022.

11. DERIVATIVES

Oil and natural 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 payments to, or entitle it to 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
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KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

or natural 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 natural 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.

Commodity Basis Swaps. Commodity basis swap agreements require the Company
to make payments to, or receive payments from, the counter parties based upon
the differential between certain pricing indices and a stated differential
amount.

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KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

As of December 31, 2004, the Company had derivative instruments outstanding
covering 8.6 million MMBtu of 2005 natural gas production, 1.4 million MMBtu of
2006 natural gas production, and 0.2 million barrels of 2005 oil production with
a fair market value of $1.3 million. In addition, there were commodity basis
swaps outstanding covering 0.5 million MMBtu. The following table sets forth the
Company's oil and natural gas hedged position as of December 31, 2004.

The Company realized $8.6 million in net hedging losses during 2004, of
which $4.5 million was net hedging losses due to reclassifications from OCI for
contracts terminated in 2001 and $4.1 million was from other commodity
derivatives accounted for as hedges pursuant to SFAS 133. During 2003, the
Company realized $6.2 million in net hedging losses, including $5.5 million net
hedging losses due to reclassifications from OCI for contracts terminated in
2001. During 2002, the Company realized $4.9 million in net hedging

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KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

losses including $5.0 million net hedge losses due to reclassifications from OCI
from contracts terminated prior to January 1, 2002.

The fair value of the Company's derivative instruments are reflected as
assets or liabilities in the Company's financial statements as presented in the
following table.

In addition to the information set forth in the first table above, the
Company will deliver 3.9 Bcfe in 2005 and 0.2 Bcfe in 2006 under the Production
Payment sold in February 2001 and amortize deferred revenue at a weighted
average discounted price of $4.05 per Mcfe.

As of December 31 2004, the Company had approximately $0.8 million of
derivative losses, net of tax, recorded in Accumulated Other Comprehensive
Income (Loss) ("AOCI") which included losses associated with terminated
commodity derivatives and other commodity derivatives. The following table
recaps the balance of AOCI at December 31, 2004 on both a pre-tax and after-tax
basis.

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

(a) During 2001, the Company terminated certain commodity derivative
instruments and recognized a charge to AOCI. As the original forecasted
transaction occurs, this loss is reclassified as a charge against earnings.
The following table details the activity of these terminated commodity
instruments on both a pre-tax and after-tax basis.

The $2.0 million after-tax loss remaining in AOCI at December 31, 2004
related to the terminated commodity derivatives, will be reclassified as a
charge against earnings in 2005.

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KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(b) The Company also has other commodity derivatives, which were accounted for
as hedges pursuant to SFAS No. 133. The following table details the
activity of those commodity derivatives on both a pre-tax and after-tax
basis.

12. LITIGATION

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 in the United States District Court for
the District of Wyoming, alleges underpayment of royalties to the Government of
the United States as a result of alleged mismeasurement of the produced natural
gas 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 into one proceeding. In April 1999, the Government of the
United States filed notice that it had decided not to intervene in these
actions. The plaintiff has not specified any damages related to the Company's
properties. 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 these proceedings and the Grynberg proceeding cannot be predicted
with certainty, management does not expect such matters to have a material
adverse effect, either individually or in the aggregate, on the financial
condition 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.

13. QUARTERLY FINANCIAL DATA (UNAUDITED)

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KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

14. OIL AND NATURAL 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 natural gas
acquisition, exploration, development and producing activities and is based on
estimates of year-end oil and natural 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 natural gas prices as of
December 31, 2004 are not necessarily reflective of the prices the Company
expects to receive in the future. Other than natural gas sold under contractual
arrangements, natural gas prices were based on year-end spot market prices of
$6.18, $5.97 and $4.74 per MMBtu, adjusted by lease for Btu content,
transportation fees and regional price differentials as of December 31, 2004,
2003 and 2002, respectively. Oil prices were based on West Texas Intermediate,
or WTI, posted prices of $40.25, $29.25 and $28.00 as of December 31, 2004, 2003
and 2002, respectively, adjusted by lease for gravity, transportation fees and
regional price differentials. Hedge-adjusted prices are not considered for
purposes of calculating future cash inflows.

Oil and natural gas reserves have been reduced to reflect the sale of the
Production Payment of 38.3 Bcf of natural gas and 797,000 barrels of oil in 2001
as discussed in Note 1.

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KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

PRODUCTION REVENUES AND COSTS (UNAUDITED)

Information with respect to production revenues and costs related to oil
and natural gas producing activities are set forth in the following table.

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(a) Includes amortization of deferred revenue of $21,370 in 2004, $27,886 in
2003, and $45,182 in 2002 related to volumes delivered under the Production
Payment sold in February 2001. See Note 1.

(b) Includes accretion of asset retirement obligation of $1,029 in 2004 and
$1,116 in 2003 as a result of adoption of SFAS 143. See Note 2.

(c) Includes the asset retirement costs incurred during the year.

DISCOUNTED FUTURE NET REVENUES (UNAUDITED)

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

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KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

DISCOUNTED FUTURE NET REVENUES RELATING TO PROVED OIL AND GAS RESERVES

CHANGES IN DISCOUNTED FUTURE NET REVENUES FROM PROVED RESERVE QUANTITIES

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(a) Includes the cash outflows associated with asset retirement obligations.

(b) Excludes $21,370, $27,886 and $66,582 of deferred revenue at December 31,
2004, 2003 and 2002, respectively, related to the Production Payment sold in
2001 as discussed in Note 1.

RESERVE INFORMATION (UNAUDITED)

The reserve estimates and associated revenues for all properties for the
years ended December 31, 2004 and 2003 were prepared by the Company and audited
by Netherland, Sewell & Associates, Inc., or NSAI. For the year ended December
31, 2002, the reserve estimates and associated revenues for all properties were

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KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

prepared by NSAI. Proved oil and gas reserves are estimated by the Company in
accordance with the Securities and Exchange Commission's definitions in Rule
4-10(a) of Regulation S-X. These definitions can be found on the SEC website at
http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas. All of the Company's
reserves are located within the United States.

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

(a) Excludes volumes produced and delivered with respect to the Production
Payment sold in February 2001 as discussed in Note 1.

(b) The Company sold a Production Payment in 2001 as discussed in Note 1. The
approximate 38.3 Bcf of natural gas and 797,000 barrels of oil Production
Payment was reflected as sales of reserves in place in 2001. In 2002, the
Company sold certain non-core properties.

Approximately 24% of the Company's reserves were classified as proved
undeveloped. Furthermore, approximately 15% of the Company's proved developed
reserves are classified as proved not producing. These reserves relate to zones
that are either behind pipe or that have been completed but not yet produced, or
zones that have been produced in the past but are not currently producing due to
mechanical reasons. These reserves may be regarded as less certain than
producing reserves because they are frequently based on volumetric calculations
rather than performance data.

15. SUBSEQUENT EVENT

On February 22, 2005, the Company entered into a purchase and sale
agreement ("Purchase Agreement") providing for the acquisition by the Company of
a package of oil and gas properties and related assets ("Assets") located
primarily in the Company's North Louisiana-East Texas core operating area. Upon
closing of the Purchase Agreement, the Company shall be entitled to all of the
rights of ownership (including, without limitation, the right to all production,
proceeds of production, and other proceeds) and will be responsible for all
operating expenses and liabilities, attributable to the Assets for the period of
time from and after January 1, 2005.

The purchase price for the Assets will be approximately $94.7 million,
subject to adjustment. The Company expects to initially finance the purchase of
the Assets with cash on hand and borrowings under its bank credit facility.

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KCS ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The transactions contemplated by the Purchase Agreement are expected to
close on April 13, 2005 or such other date as is agreed upon by the seller and
the Company, subject to the satisfaction of customary closing conditions and the
right of either the seller or the Company to terminate the Purchase Agreement in
certain circumstances, including the right to terminate in the event the sum of
certain title and environmental defects exceeds specified thresholds. The
Purchase Agreement may be terminated at any time prior to closing for the
following reasons, among others: (a) by seller, if its closing conditions have
not been satisfied on or before closing; (b) by the Company, if its closing
conditions have not been satisfied on or before closing and such conditions have
not been cured by seller within ten days of written notice thereof; and (c) by
seller or the Company if closing does not occur on or before April 23, 2005.

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

None.

ITEM 9A. CONTROLS AND PROCEDURES.

Evaluation of disclosure controls and procedures. Based on their
evaluation of our disclosure controls and procedures as of the end of the period
covered by this report, our Chief Executive Officer and Chief Financial Officer
have concluded that our disclosure controls and procedures are effective in
ensuring that the information required to be disclosed by us (including our
consolidated subsidiaries) in the reports that we file or submit under the
Securities Exchange Act of 1934, as amended, is recorded, processed, summarized
and reported, within the time periods specified in the Securities and Exchange
Commission's rules and forms.

Management's annual report on internal control over financial
reporting. Management's report on internal control over financial reporting and
the attestation report of our independent registered public accounting firm are
included under "Financial Statements and Supplementary Data," and such reports
are incorporated herein by reference.

Changes in internal control over financial reporting. There were no
changes in our internal control over financial reporting that occurred during
our last fiscal quarter that have materially affected, or are reasonably likely
to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION.

On March 2, 2005, the Board of Directors of KCS approved the following
actions of the Compensation Committee (the "Compensation Committee") of the
Board of Directors with regard to the compensation of the executive officers who
were named in the Summary Compensation Table of KCS' 2004 Proxy Statement and
who are expected to be named in the Summary Compensation Table of KCS' 2005
Proxy Statement:

2005 Base Salary Increases. The Compensation Committee approved increases
to the base salaries of the named executive officers, effective February 1,
2005. The base salaries of the named executive officers for 2005 are as follows:
James W. Christmas, Chairman and Chief Executive Officer ($400,000, a 4.1%
increase over 2004); William N. Hahne, President and Chief Operating Officer
($312,000, a 3.8% increase over 2004); Harry Lee Stout, Senior Vice President,
Marketing and Risk Management ($216,000, a 2.7% increase over 2004); Joseph T.
Leary, Vice President and Chief Financial Officer ($190,000, an 8.6% increase
over 2004); and Frederick Dwyer, Vice President, Controller and Secretary
($145,000, a 3.6% increase over 2004).

Annual Incentive Compensation Earned in 2004. The Compensation Committee
approved annual cash bonus awards earned during 2004 and to be paid on March 18,
2005 for the named executive officers. The amounts of the bonus awards are as
follows: Mr. Christmas ($219,900); Mr. Hahne ($156,200); Mr. Stout ($65,600);
Mr. Leary ($65,600); and Mr. Dwyer ($60,000). In addition to the aforementioned
bonus award, Mr. Dwyer was paid $30,000 in February 2005 in connection with a
retention agreement.

Other Compensation Information. KCS will provide additional information
regarding the compensation paid to the named executive officers for the 2004
fiscal year in KCS' proxy statement for the 2005 Annual Meeting of Shareholders,
which is expected to be filed with the SEC in April 2005.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

Information concerning our executive officers and directors is set forth in
the sections entitled "Election of Directors" and "Executive Officers" of our
Proxy Statement for the 2005 Annual Meeting of Stockholders, which sections are
incorporated in this annual report on Form 10-K by reference. Information
concerning compliance with Section 16(a) of the Securities Exchange Act of 1934,
as amended, is set forth in the section entitled "Section 16(a) Beneficial
Ownership Reporting Compliance" of our Proxy Statement for the 2005

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Annual Meeting of Stockholders, which section is incorporated in this annual
report on Form 10-K by reference.

Information concerning our audit committee and our audit committee
financial expert is set forth in the section entitled "Information Concerning
the Board of Directors and Certain Committees of the Board of Directors" in our
Proxy Statement for the 2005 Annual Meeting of Stockholders, which section is
incorporated in this annual report on Form 10-K by reference.

We have adopted a Code of Ethics applicable to our principal executive
officer, principal financial officer and principal accounting officer. The Code
of Ethics applicable to our principal executive officer, principal financial
officer and principal accounting officer was filed as Exhibit 14.1 to our annual
report on Form 10-K for the year ended December 31, 2003 and is available on our
Internet website at www.kcsenergy.com. If we amend the Code of Ethics or grant a
waiver, including an implicit waiver, from the Code of Ethics, we intend to
disclose the information on our Internet website within four business days of
such amendment or waiver.

CERTIFICATION

As required by New York Stock Exchange ("NYSE") listing standards, James W.
Christmas, our Chief Executive Officer, certified on August 3, 2004 that he was
not aware of any violation by KCS of NYSE corporate governance listing
standards. The certifications required by Section 302 of the Sarbanes-Oxley Act
were filed with the Securities and Exchange Commission on March 15, 2005 as
exhibits 31.1 and 31.2 to KCS' Annual Report on Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION.

Information for this item is set forth in the sections entitled "Executive
Compensation," "Compensation Committee Interlocks and Insider Participation,"
"Employment Agreements, Change in Control Agreements and Retention Agreements,"
and "Compensation of Directors" in our Proxy Statement for the 2005 Annual
Meeting of Stockholders, which sections are incorporated in this annual report
on Form 10-K by reference.

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

Information for this item is set forth in the section entitled "Security
Ownership of Certain Beneficial Owners and Management" in our Proxy Statement
for the 2005 Annual Meeting of Stockholders, which section is incorporated in
this annual report on Form 10-K by reference.

Information concerning securities authorized for issuance under our equity
compensation plans is set forth in Item 5 of this Form 10-K and is incorporated
in Item 12 of this annual report on Form 10-K by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

Information for this item is set forth in the section entitled "Certain
Relationships and Related Transactions" in our Proxy Statement for the 2005
Annual Meeting of Stockholders, which section is incorporated in this annual
report on Form 10-K by reference.

ITEM 14. PRINCIPLE ACCOUNTING FEES AND SERVICES.

Information for this item is set forth in the section entitled "Independent
Registered Public Accounting Firm" in our Proxy Statement for the 2005 Annual
Meeting of Stockholders, which section is incorporated in this annual report on
Form 10-K by reference.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

(a) List of Documents Filed as Part of the Report:

(1) Financial Statements. The following consolidated financial
statements and the related Report of Independent Registered Accounting Firm
are presented in Part II, Item 8 of this annual report on Form 10-K on the
pages indicated below.

(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 our consolidated
financial statements and related notes.

(3) Exhibits.

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

* Management contract or compensatory plan or arrangement.

+ Filed herewith.

80

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 15, 2005

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 and on the dates indicated.

81

EXHIBIT INDEX

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

* Management contract or compensatory plan or arrangement.

+ Filed herewith.

84