<PAGE> 1
Filed Pursuant to Rule 424(b)(4)
Registration No. 333-15581
PROSPECTUS
3,000,000 SHARES
KCS ENERGY, INC.
[KCS ENERGY INC. LOGO]
COMMON STOCK
($.01 PAR VALUE)
The shares of Common Stock, par value $.01 per share (the "Common Stock"), of
KCS Energy, Inc. ("KCS" or the "Company") being offered hereby (the "Shares")
are being issued and sold by the Company.
The Shares are being sold in two concurrent offerings (the "Offerings"), one
offering initially in the United States and Canada (the "U.S. Offering") through
U.S. underwriters (the "U.S. Underwriters") and one initially outside the United
States and Canada (the "International Offering") through international
underwriters (the "International Underwriters"). The U.S. Underwriters and the
International Underwriters are hereinafter collectively referred to as the
"Underwriters." Of the 3,000,000 Shares being offered, 2,400,000 are being
offered in the U.S. Offering and 600,000 are being offered in the International
Offering, subject to transfers between the U.S. Underwriters and the
International Underwriters. See "Underwriting."
The Common Stock is listed on the New York Stock Exchange under the symbol
"KCS." On January 29, 1997, the last reported sale price for the Common Stock,
as reported on the New York Stock Exchange Composite Transactions Tape, was
$39.625 per share. See "Price Range of Common Stock."
SEE "RISK FACTORS" BEGINNING ON PAGE 10 FOR A DISCUSSION OF CERTAIN FACTORS THAT
SHOULD BE CONSIDERED BY PROSPECTIVE PURCHASERS OF THE COMMON STOCK.
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
- --------------------------------------------------------------------------------
<TABLE>
<S> <C> <C> <C>
PRICE TO UNDERWRITING PROCEEDS TO
PUBLIC DISCOUNT COMPANY(1)
Per Share....................... $39.00 $1.80 $37.20
Total(2)........................ $117,000,000 $5,400,000 $111,600,000
</TABLE>
- --------------------------------------------------------------------------------
(1) Before deducting offering expenses payable by the Company, estimated at
$883,125.
(2) The Company has granted the Underwriters 30-day options to purchase up to an
aggregate of 360,000 and 90,000 additional shares of Common Stock,
respectively, at the Price to Public, less Underwriting Discount, solely to
cover over-allotments, if any. If the Underwriters exercise such options in
full, the total Price to Public, Underwriting Discount and Proceeds to
Company will be $134,550,000, $6,210,000 and $128,340,000, respectively. See
"Underwriting."
The Common Stock is offered subject to receipt and acceptance by the
Underwriters, to prior sale and to the Underwriters' right to reject any order
in whole or in part and to withdraw, cancel or modify the offer without notice.
It is expected that delivery of the Common Stock will be made at the office of
Salomon Brothers Inc, Seven World Trade Center, New York, New York, or through
the facilities of The Depository Trust Company, on or about February 4, 1997.
SALOMON BROTHERS INC
DONALDSON, LUFKIN & JENRETTE
SECURITIES CORPORATION
PRUDENTIAL SECURITIES INCORPORATED
MORGAN KEEGAN & COMPANY, INC.
SOUTHCOAST CAPITAL
CORPORATION
The date of this Prospectus is January 29, 1997.
<PAGE> 2
[INSIDE COVER PAGE CONTAINS MAP OF MIDDLE PORTION OF UNITED STATES WITH THE
COMPANY'S PRIMARY AREAS OF NATURAL GAS AND OIL ACTIVITY SHOWN GEOGRAPHICALLY IN
MONTANA, MICHIGAN, WYOMING, COLORADO, NEW MEXICO, OKLAHOMA, ARKANSAS, TEXAS,
LOUISIANA AND OFFSHORE OF TEXAS AND LOUISIANA]
IN CONNECTION WITH THE OFFERINGS, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON
STOCK AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET.
SUCH STABILIZING TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK STOCK
EXCHANGE OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT
ANY TIME.
2
<PAGE> 3
PROSPECTUS SUMMARY
The following summary is qualified in its entirety by the more detailed
information and financial statements (including the notes thereto) included
elsewhere in this Prospectus and in the documents incorporated herein by
reference. Unless the context otherwise requires, "Company" and "KCS" refer to
KCS Energy, Inc. and its consolidated subsidiaries. Except as otherwise
specified, all data set forth in this Prospectus assumes no exercise of the
Underwriters' over-allotment options. See "Glossary" for definitions of certain
terms used herein.
THE COMPANY
GENERAL
KCS Energy, Inc. ("KCS" or the "Company") is an independent oil and gas
company primarily engaged in the acquisition, exploitation, development and, to
a lesser extent, exploration of domestic oil and gas properties, and in the
production and marketing of oil and gas. Through its experienced management and
geological and engineering staff, the Company has successfully increased the
value of its properties through drilling and other exploitation techniques and
has substantially increased its reserves, production and cash flow. Over the
five-year period ended December 31, 1995, KCS replaced 400% of production and
increased proved oil and gas reserves 395% to 186.1 Bcfe at December 31, 1995.
During the same period, the Company increased its oil and gas production 392% to
20.3 Bcfe, representing a compound annual growth rate of 49%. In addition, the
Company increased EBITDA from $7.1 million in 1991 to $75.1 million in 1995.
The Company's operations to date have focused primarily on properties in
the onshore Gulf Coast and Rocky Mountain regions. KCS augments its working
interest ownership of properties with a volumetric production payment ("VPP")
program to acquire oil and gas from properties which to date have been located
primarily in the offshore Gulf Coast region and in the Niagaran Reef trend in
Michigan. As of December 31, 1996, the Company completed the arrangements for
the acquisition of InterCoast Oil and Gas Company (formerly Medallion Production
Company and renamed KCS Medallion Resources, Inc.) and certain of its affiliates
(the "Medallion Acquisition"), the Company's largest acquisition to date. The
Medallion Acquisition expanded the Company's operations to include a third core
operating area, the Mid-Continent region, encompassing west Texas, the Texas
Panhandle, northwest Oklahoma and north Louisiana. At June 30, 1996, on a pro
forma basis reflecting the Medallion Acquisition, proved oil and gas reserves
were 369.4 Bcfe (84% proved developed), approximately double the Company's
historical proved reserves at December 31, 1995, and represented a PV-10 value
of $408.3 million. Approximately 63% of the Company's reserves on a pro forma
basis are attributable to wells it operates.
Historically, the Company's most significant field was the Bob West Field
in south Texas, which accounted for approximately 16% (8% on a pro forma basis)
of the Company's production during the nine months ended September 30, 1996.
Most of the Company's natural gas sold from the Bob West Field was covered by an
above-market, take-or-pay contract (the "Tennessee Gas Contract") with Tennessee
Gas Pipeline Company ("Tennessee Gas"), which had been the subject of several
lawsuits. On December 23, 1996, the Company and Tennessee Gas entered into a
settlement covering all claims and litigation between them related to the
Tennessee Gas Contract. As part of the settlement, the Tennessee Gas Contract
was terminated effective January 1, 1997, approximately two years prior to its
expiration date. The parties also agreed to the dismissal of the contract
dispute that resulted in a November 1996 jury award to Tennessee Gas of $143.2
million (including punitive damages of approximately $114 million). The December
1996 settlement did not affect the Company's successful conclusion of litigation
earlier in the year relating to the validity and pricing provisions of the
Tennessee Gas Contract and its recovery of past underpayments that had accrued
under the contract (the "Tennessee Gas Receivable").
3
<PAGE> 4
BUSINESS STRATEGY
The Company has grown through a strategy of reserve acquisitions and
development and exploratory drilling. The Company plans to continue to broaden
its reserve base and increase production and cash flow through (i) the
acquisition of attractively priced oil and gas companies and producing
properties that provide additional development or exploratory potential, (ii)
the exploitation and development of its existing asset base, (iii) the operation
and ownership of a majority working interest in a significant number of its
properties to allow the Company greater control over future development,
drilling, completing and lifting costs and marketing of production, (iv) the
acquisition of oil and gas reserves through the VPP program, (v) the pursuit of
a balanced exploration program that includes a number of high-potential
opportunities, and (vi) the extensive use of advanced technologies, most notably
3-D seismic, computer-enhanced basin analysis, reservoir simulation and
specialized drilling applications and stimulation techniques to better delineate
or produce reserves.
To implement its strategy, the Company intends to take advantage of several
key strengths, including (i) an experienced and capable team of oil and gas
industry professionals with a meaningful financial stake in the success of the
Company, (ii) a significant inventory of attractive development and exploratory
drilling opportunities within its existing property base and undeveloped acreage
position, (iii) established relationships with proven industry partners that
provide opportunities to participate in diverse exploration prospects, (iv) an
efficient administrative and operating structure that emphasizes an
entrepreneurial and opportunistic approach, and (v) a strong financial focus
which manifests itself not only in innovative transactions, but also in asset
risk management.
ACQUISITION ACTIVITIES
Medallion Acquisition. As of December 31, 1996, the Company completed the
arrangements for the acquisition of all outstanding stock of InterCoast Oil and
Gas Company (formerly Medallion Production Company), GED Energy Services, Inc.
and InterCoast Gas Services Company (collectively referred to as "Medallion"),
indirect wholly-owned subsidiaries of MidAmerican Energy Holdings Company
("MidAmerican"), for a total purchase price of approximately $214.4 million,
consisting of $209.4 million in cash (reduced at closing by $15.3 million
principally to reflect free cash flow from Medallion's operations subsequent to
the July 1, 1996 effective date) and warrants to purchase 435,000 shares of
Common Stock. Medallion's principal assets, estimated as of June 30, 1996, were
202.1 Bcfe of proved oil and gas reserves, consisting of 161.3 Bcf of natural
gas (80% of total proved reserves) and 6.8 MMbbls of oil and condensate, located
primarily in the Mid-Continent region. Proved developed reserves account for 88%
of Medallion's total proved reserves, and approximately 68% of these reserves
are attributable to wells it operates. The Medallion Acquisition more than
doubled the Company's reserve base and added substantial management and
technical expertise, particularly in the new Mid-Continent core area.
Over the three and one half-year period ended June 30, 1996, Medallion
replaced 251% of its production and increased reserves 148% through property
acquisitions, its Extensional Infill Drilling ("EID") program and, to a lesser
extent, exploratory drilling, all of which the Company expects to continue.
Since its acquisition by MidAmerican in April 1992, Medallion has acquired 188.7
Bcfe of proved reserves through 31 acquisitions at an average acquisition cost
of $0.67 per Mcfe. Medallion's EID program allows it to drill and produce a
greater amount of reserves within producing fields than would otherwise be
produced without making a major capital investment in undeveloped leasehold
acreage. During the three-year period ended December 31, 1995, Medallion added
53.7 Bcfe of proved reserves at an average finding cost of $0.75 per Mcfe by
successfully completing 52 of 87 EID prospects.
Rocky Mountain Acquisition. In November 1995, the Company acquired
substantially all of the oil and gas assets of Natural Gas Processing Company
for a purchase price of approximately $33 million (the "Rocky Mountain
Acquisition"). The Company acquired interests in over 30 different fields,
principally in six producing basins located in Wyoming, Colorado, Montana and
North Dakota. Proved reserves attributable to the properties acquired were
estimated to be 66.7 Bcfe at September 30, 1995, consisting of 40.9 Bcf of
natural gas and 4.3 MMbbls of oil and representing an average acquisition cost
4
<PAGE> 5
of $0.49 per Mcfe. Since the acquisition, the Company has undertaken an
aggressive field development and acreage acquisition program in the Rocky
Mountain region which has resulted in several recent drilling successes and
prospective drilling opportunities, most notably in the Manderson Field in
Wyoming. Approximately half of the natural gas production from the acquired
properties is subject to multi-year contracts with local utility companies at
prices that range from $1.70 to $2.00 per Mcf.
Michigan Acquisition. In December 1995, the Company acquired 24.6 Bcfe of
proved reserves in the northern and southern Niagaran Reef trends in Michigan
for $31 million, including a volumetric production payment covering certain
reserves, escalating working interests in related properties and participation
rights and an overriding royalty interest in an exploration program,
representing an average acquisition cost of $1.26 per Mcfe (the "Michigan
Acquisition"). The VPP provides for the delivery to the Company of 13.7 Bcf of
natural gas and 1.1 MMbbls of oil to be delivered (without any burden of
development and lease operating expenses) from December 1995 through January
2006. Based on independent reserve reports as of September 30, 1995, the
separately acquired working interests added 3.1 Bcf of natural gas and 219 Mbbls
of oil to the Company's proved reserves.
DEVELOPMENT AND EXPLORATION ACTIVITIES
During the three-year period ended December 31, 1995, the Company
participated in the drilling of 61 development wells with a 98% success rate.
The majority of this development (38 wells and 38 completions) was in the Bob
West Field. During the first nine months of 1996, however, the Company
substantially increased its level of development drilling in other areas and
drilled 27 of 29 wells and completed 24 of 27 wells in areas other than the Bob
West Field. The Company's activities outside the Bob West Field are now focused
on the Manderson Field in the Big Horn Basin of Wyoming, the Sweet Grass Arch
area of Montana, the Langham Creek Area and Glasscock Ranch Fields in Texas and
the Laurel Ridge Field and the Tensas Parish Area in Louisiana. The Company has
currently identified over 450 development drilling and recompletion locations
and 170 EID locations, representing approximately a four-year inventory, and has
initially budgeted $70 million for development activities in 1997. The Company
intends to focus its development efforts primarily on the fields in the Rocky
Mountain and onshore Gulf Coast regions described above and on its newly
acquired properties in the Mid-Continent region.
During the three-year period ended December 31, 1995, the Company
participated in the drilling of 58 exploratory wells with a 50% success rate.
Discoveries included wells in the Bob West Field, Langham Creek Area and Laurel
Ridge Field. During the first nine months of 1996, the Company participated in
the drilling of 11 exploratory wells (all of which were outside the Bob West
Field) and completed five wells, two of which it operates. Discoveries in 1996
included the Aubrey and Wilsonia Fields in the Tensas Parish Area in Louisiana.
The Company has interests in more than 172,000 gross (140,000 net) undeveloped
acres and has established an initial budget of $25 million for exploration in
1997, including amounts for 3-D seismic data acquisition and analysis. The
Company intends to participate in up to 50 prospects in 1997, including both
low-risk and high-risk, high-potential projects in order to maintain a balanced
program with the potential for significant reserve additions. Exploration
activities will focus primarily on properties located in the onshore Gulf Coast
regions of Texas and Louisiana and in the Rocky Mountains. The Company also
intends to further analyze the undeveloped acreage it acquired in the Medallion
Acquisition for possible exploration projects and to continue its participation
in exploration projects in Michigan.
The Company's executive offices are located at 379 Thornall Street, Edison,
New Jersey 08837 and its telephone number is (908) 632-1770.
5
<PAGE> 6
THE OFFERINGS
<TABLE>
<S> <C>
Common Stock offered by the Company:
U.S. Offering........................... 2,400,000 shares
International Offering.................. 600,000 shares
--------------
Total.............................. 3,000,000 shares
Common Stock to be outstanding after the
Offerings.................................. 14,587,422 shares(1)
Use of proceeds.............................. The net proceeds will be used to reduce the
outstanding indebtedness under the Company's
Bank Credit Facilities, including the
Revolving Credit Agreement used to fund a
portion of the Medallion Acquisition. See
"Use of Proceeds" and "Business and
Properties -- Recent
Acquisitions -- Medallion Acquisition."
New York Stock Exchange symbol............... KCS
</TABLE>
- ---------------
(1) Does not include 529,575 shares of Common Stock reserved for issuance
pursuant to outstanding stock options and warrants to purchase 435,000
shares of Common Stock issued in connection with the Medallion Acquisition.
RISK FACTORS
In addition to the other information in this Prospectus, prospective
purchasers of the Common Stock should carefully consider certain risk factors in
evaluating an investment in the Common Stock. See "Risk Factors."
6
<PAGE> 7
SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
The following table sets forth selected historical and pro forma financial
information of the Company and should be read in conjunction with the financial
statements (including the notes thereto) of KCS Energy, Inc., the InterCoast
Entities (Medallion) and the Sawyer Canyon Properties and the information under
the captions "Pro Forma Financial Information" and "Management's Discussion and
Analysis of Financial Condition and Results of Operations" included elsewhere in
this Prospectus.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------------------------------- --------------------------------------------
PRO FORMA PRO FORMA
AS ADJUSTED(1)(2) AS ADJUSTED(2)(3)
1993 1994 1995 1995 1995 1996 1996
---------- ---------- ---------- ----------------- ---------- ----------- -----------------
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenue:
Oil and gas exploration
and production........ $ 40,455 $ 66,215 $ 86,629 $ 162,857 $ 63,425 $ 79,051 $ 134,020
Natural gas
transportation and
marketing............. 264,710 279,155 365,354 450,502 270,557 238,254 347,533
Intercompany............ (876) (3,657) (2,018) (2,018) (1,708) (701) (701)
---------- ---------- ---------- ---------- ---------- ----------- ----------
Total............. 304,289 341,713 449,965 611,341 332,274 316,604 480,852
Operating costs and
expenses:
Cost of natural gas
sales................. 253,435 265,076 356,186 437,763 264,097 231,063 337,609
Other operating and
administrative
expenses.............. 15,018 18,285 18,669 44,672 12,950 19,427 35,955
Depreciation, depletion
and amortization...... 8,036 19,740 39,209 66,732 29,299 33,933 54,377
---------- ---------- ---------- ---------- ---------- ----------- ----------
Total............. 276,489 303,101 414,064 549,167 306,346 284,423 427,941
---------- ---------- ---------- ---------- ---------- ----------- ----------
Operating income......... 27,800 38,612 35,901 62,174 25,928 32,181 52,911
Interest and other
income, net............. 704 1,039 3,713 3,713 2,311 4,850 4,850
Interest expense......... (1,983) (2,938) (7,732) (25,667) (4,912) (13,858) (18,073)
---------- ---------- ---------- ---------- ---------- ----------- ----------
Income before income
taxes................... 26,521 36,713 31,882 40,220 23,327 23,173 39,688
Federal and state income
taxes................... 7,910 12,556 10,576 13,568 7,645 8,367 14,266
---------- ---------- ---------- ---------- ---------- ----------- ----------
Net income............... $ 18,611 $ 24,157 $ 21,306 $ 26,652 $ 15,682 $ 14,806 $ 25,422
========== ========== ========== ========== ========== =========== ==========
Earnings per share....... $ 1.60 $ 2.05 $ 1.81 $ 1.81 $ 1.33 $ 1.25 $ 1.71
Average common shares
outstanding............. 11,658,370 11,804,989 11,760,701 14,760,701 11,766,011 11,886,434 14,886,434
Dividend per common
share................... $ 0.06 $ 0.09 $ 0.12 $ 0.12 $ 0.09 $ 0.09 $ 0.09
OTHER DATA:
EBITDA(4)................ $ 35,836 $ 58,352 $ 75,110 $ 128,906 $ 55,227 $ 66,114 $ 107,288
Capital expenditures..... 48,455 74,953 128,699 340,240 57,455 52,735 264,276
</TABLE>
<TABLE>
<CAPTION>
SEPTEMBER 30, 1996
----------------------------------------------------
PRO FORMA
HISTORICAL PRO FORMA(3) AS ADJUSTED(2)(3)
---------- ------------ -----------------
(UNAUDITED)
<S> <C> <C> <C>
BALANCE SHEET DATA:
Cash and cash equivalents................................... $ 53,597 $ 7,109 $ 7,109
Working capital............................................. 56,970 16,906 16,906
Oil and gas properties, net................................. 206,308 400,583 400,583
Total assets................................................ 341,152 528,311 528,311
Long-term debt.............................................. 149,830 306,343 195,626
Total stockholders' equity.................................. 116,312 121,310 232,027
</TABLE>
- ---------------
(1) Gives effect to the Medallion Acquisition, the acquisition of the Sawyer
Canyon Properties by Medallion, the Company's Rocky Mountain Acquisition and
Michigan Acquisition and the Company's Senior Notes offering as if each
transaction had occurred on January 1, 1995.
(2) Gives effect to the Offerings.
(3) Gives effect to the Medallion Acquisition and the acquisition of the Sawyer
Canyon Properties by Medallion and the application of $50.0 million of cash
to reduce long-term debt.
(4) EBITDA represents income before depletion, depreciation, amortization,
interest expense, interest and other income and income taxes. EBITDA is a
financial measure commonly used in the Company's industry and should not be
considered in isolation or as a substitute for net income, cash flow
provided by operating activities or other income or cash flow data prepared
in accordance with generally accepted accounting principles or as a measure
of a company's profitability or liquidity.
7
<PAGE> 8
SUMMARY HISTORICAL AND PRO FORMA OIL AND GAS RESERVE AND OPERATING DATA -- KCS
The following table sets forth summary information with respect to
estimates of the Company's proved oil and gas reserves at the end of the periods
indicated. The table also sets forth information with respect to estimates of
the pro forma proved reserves at June 30, 1996, after giving effect to the
Medallion Acquisition. Net production data and other data at September 30, 1996
are also shown giving pro forma effect to the Medallion Acquisition. For
additional information relating to the Company's oil and gas reserves and
operating data, see "Business and Properties," "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the notes to the
Consolidated Financial Statements included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
HISTORICAL
--------------------------------------------------
DECEMBER 31, PRO FORMA
------------------------------------- JUNE 30, JUNE 30,
1993 1994 1995 1996 1996
--------- --------- --------- -------- ---------
<S> <C> <C> <C> <C> <C>
RESERVE DATA:
Proved developed reserves:
Oil (Mbbls)............................ 1,579 1,336 3,808 4,377 10,856
Natural gas (MMcf)..................... 61,016 74,215 121,987 105,709 244,120
Total (MMcfe)........................ 70,490 82,231 144,835 131,971 309,256
Proved undeveloped reserves:
Oil (Mbbls)............................ 999 983 3,709 3,421 3,739
Natural gas (MMcf)..................... 8,724 14,969 18,976 14,833 37,753
Total (MMcfe)........................ 14,718 20,867 41,230 35,359 60,187
Total proved reserves:
Oil (Mbbls)............................ 2,578 2,319 7,517 7,798 14,595
Natural gas (MMcf)..................... 69,740 89,184 140,963 120,542 281,873
Total (MMcfe)........................ 85,208 103,098 186,065 167,330 369,443
Estimated future net revenue before
income taxes ($000) (1)(2)............. $ 334,209(3) $ 307,533 $ 405,049 $288,024(4) $602,375 (4)
Present value of estimated future net
revenues before income taxes ($000)
(2)(5)................................. $ 250,275(3) $ 241,705 $ 291,085 $196,826(4) $408,265 (4)
Standardized measure of discounted future
net cash flows ($000) (2)(6)........... $ 185,534(3) $ 179,660 $ 231,763 -- --
Reserve replacement percentage........... 412.8% 242.3% 527.2% -- --
Reserve life (in years).................. 10.6 8.2 9.2 -- --
</TABLE>
<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER
YEAR ENDED DECEMBER 31, 30,
-------------------------------------- ----------------------------
PRO FORMA PRO FORMA
1993 1994 1995 1995 1995 1996 1996
------ ------- ------- --------- ------ ------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
NET PRODUCTION DATA:
Oil (Mbbls)......................... 179 211 196 1,224 111 547 1,324
Natural gas (MMcf):
Tennessee Gas Contract............ 4,472 6,851 6,924 6,924 5,446 3,576 3,576
Other............................. 2,505 4,453 12,205 30,040 7,858 15,346 32,756
------ ------- ------- ------ ------- ------- -------
Total........................... 6,977 11,304 19,129 36,964 13,304 18,922 36,332
Total (MMcfe)....................... 8,051 12,570 20,305 44,308 13,970 22,204 44,276
OTHER DATA:
Average sales prices:
Oil (per bbl)..................... $17.57 $ 15.16 $ 17.28 $ 16.58 $17.53 $ 19.72 $ 19.24
Natural gas (per Mcf):
Tennessee Gas Contract.......... 7.09 7.49 7.90 7.90 7.84 8.38 8.38
Other........................... 2.02 1.81 1.62 1.64 1.56 2.29 2.13
Average......................... 5.27 5.54 4.29 3.02 4.60 3.61 2.84
Average equivalent sales price
(per Mcfe)........................ $ 5.02 $ 5.27 $ 4.27 $ 2.97 $ 4.54 $ 3.56 $ 2.90
Average lifting cost (per Mcfe)..... 0.62 0.56 0.33 0.48 0.31 0.37 0.47
General and administrative expense
(per Mcfe)(7)..................... 0.52 0.39 0.23 0.17 0.24 0.25 0.20
------ ------- ------- ------ ------- ------- -------
Cash margin (per Mcfe).............. $ 3.88 $ 4.32 $ 3.71 $ 2.32 $ 3.99 $ 2.94 $ 2.23
</TABLE>
- ---------------
(1) Reflects estimated future cash inflows less future production and
development costs.
(2) Estimates at December 31 in 1993, 1994 and 1995 reflect the contract price
to be paid for natural gas delivered from the Bob West Field under the
Tennessee Gas Contract until January 1999.
(3) Reflects data as of September 30, 1993, the Company's former fiscal year
end.
(4) As a result of the early termination of the Tennessee Gas Contract effective
January 1, 1997, estimates at each of Historical and Pro Forma June 30, 1996
reflect downward revisions from earlier reserve reports in the amounts of
$59.5 million for estimated future net revenues before income taxes (based
upon an estimated realized spot market price for natural gas of $2.10 per
Mcf at June 30, 1996) and $51.4 million for present value of estimated
future net revenues before income taxes. See "Business and
Properties -- Legal Proceedings -- Tennessee Gas Litigation."
(5) Reflects estimated future net revenue before income taxes discounted at 10%
per annum.
(6) Reflects present value of estimated future net revenue before income taxes,
less future income taxes discounted at 10% per annum.
(7) Includes all corporate general and administrative expenses.
8
<PAGE> 9
SUMMARY HISTORICAL AND PRO FORMA OIL AND GAS RESERVE AND OPERATING
DATA -- MEDALLION
The following tables set forth summary information with respect to
estimates of Medallion's proved oil and gas reserves at the end of the periods
indicated and production and prices for the periods indicated. For additional
information relating to Medallion's oil and gas reserves and operating data, see
"Business and Properties" and the notes to the Combined Financial Statements of
the InterCoast Entities (Medallion) included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------- JUNE 30,
1993 1994 1995 1996
-------- -------- -------- --------
<S> <C> <C> <C> <C>
RESERVE DATA:
Proved developed reserves:
Oil (Mbbls)........................ 8,173 6,717 8,255 6,479
Natural gas (MMcf)................. 100,660 115,099 111,189 138,411
Total (MMcfe)................... 149,698 155,401 160,719 177,285
Proved undeveloped reserves:
Oil (Mbbls)........................ 782 587 1,589 318
Natural gas (MMcf)................. 11,363 33,512 22,484 22,920
Total (MMcfe)................... 16,055 37,034 32,018 24,828
Total proved reserves:
Oil (Mbbls)........................ 8,955 7,304 9,844 6,797
Natural gas (MMcf)................. 112,023 148,611 133,673 161,331
Total (MMcfe)................... 165,754 192,435 192,737 202,113
Estimated future net revenue before
income taxes ($000)(1)............. $220,335 $221,513 $258,220 $314,351
Present value of estimated future net
revenues before income taxes
($000)(2).......................... $137,711 $144,595 $168,159 $211,439
Standardized measure of discounted
future net cash flows ($000)(3).... $118,202 $126,044 $136,924 --
Reserve replacement percentage....... 612.0% 263.0% 107.0% --
Reserve life (in years).............. 9.8 8.9 8.0 --
</TABLE>
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------------- --------------------
1993 1994 1995 1995 1996
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
NET PRODUCTION DATA:
Oil (Mbbls).......................... 691 1,024 1,028 780 777
Natural gas (MMcf)................... 12,742 15,591 17,835 12,991 17,410
Total (MMcfe)........................ 16,888 21,735 24,003 17,671 22,072
OTHER DATA:
Average sales prices:
Oil (per bbl)...................... $ 16.06 $ 14.93 $ 16.45 $ 16.54 $ 18.92
Natural gas (per Mcf).............. 2.04 1.82 1.65 1.58 2.00
Average equivalent sales price (per
Mcfe).............................. 2.20 2.01 1.93 1.89 2.24
Average lifting cost (per Mcfe)...... 0.56 0.69 0.61 0.62 0.56
</TABLE>
- ---------------
(1) Reflects estimated future cash inflows less future production and
development costs.
(2) Reflects estimated future net revenue before income taxes discounted at 10%
per annum.
(3) Reflects present value of estimated future net revenue before income taxes,
less future income taxes discounted at 10% per annum.
9
<PAGE> 10
RISK FACTORS
In addition to the other information set forth in this Prospectus,
prospective purchasers of the Common Stock should carefully consider the
following risk factors in evaluating an investment in the Common Stock. This
Prospectus contains forward-looking statements which involve certain
assumptions, risks and uncertainties. The Company's actual results could differ
materially from those anticipated in these forward-looking statements as a
result of certain factors, including those set forth in the following risk
factors and elsewhere in this Prospectus. See "Disclosure Regarding
Forward-Looking Statements."
VOLATILE NATURE OF OIL AND GAS MARKETS; FLUCTUATIONS IN PRICES
The Company's future financial condition and results of operations are
highly dependent on the demand and prices received for the Company's oil and gas
production and on the costs of acquiring, developing and producing reserves. Oil
and gas prices have historically been volatile and are expected by the Company
to continue to be volatile in the future. Prices for oil and gas are subject to
wide fluctuation in response to relatively minor changes in the supply of and
demand for oil and gas, market uncertainty and a variety of additional factors
that are beyond the Company's control. These factors include political
conditions in the Middle East and elsewhere, domestic and foreign supply of oil
and gas, the level of consumer demand, weather conditions, domestic and foreign
government regulations and taxes, the price and availability of alternative
fuels and overall economic conditions. A decline in oil or gas prices may
adversely affect the Company's cash flow, liquidity and profitability. Lower oil
or gas prices also may reduce the amount of the Company's oil and gas that can
be produced economically. It is impossible to predict future oil and gas price
movements with any certainty.
DEPENDENCE ON ACQUIRING AND FINDING ADDITIONAL RESERVES
The Company's prospects for future growth and profitability will depend
predominately on its ability to replace present reserves through acquisitions
and development, EID and exploratory drilling, as well as on its ability to
successfully develop additional reserves. The decision to acquire a business or
to purchase, explore or develop an interest or property will depend in part on
the evaluation of data obtained through geophysical and geological analyses and
engineering studies, the results of which are often inconclusive or subject to
varying interpretations. Acquisitions may not be available at attractive prices,
and there can be no assurance that the Company's acquisition and exploration
activities or planned development projects will result in significant additional
reserves or that the Company will have continuing success at drilling
economically productive wells. Without successfully acquiring or developing
additional reserves, the Company's proved reserves and revenues will decline.
SUBSTANTIAL CAPITAL REQUIREMENTS
The Company has made, and likely will continue to make, substantial capital
expenditures in connection with the acquisition, development and exploration of
oil and gas properties. Historically, the Company has funded its capital
expenditures with cash flow from operations and funds from long-term debt
financing, including bank financing secured by its oil and gas and natural gas
transportation assets (the "Master Note Facility"), its receivables (the
"Receivable Facility") and its VPP program assets (the "VPP Facility"). In July
1996, the Receivable Facility was repaid and terminated, and in September 1996,
the Master Note and VPP Facilities were consolidated into one revolving credit
facility (the "Credit Facility"). In addition, the Company entered into a new
revolving credit agreement simultaneously with the consummation of the Medallion
Acquisition (the "Revolving Credit Agreement") (the Credit Facility and the
Revolving Credit Agreement are collectively referred to as the "Bank Credit
Facilities"). The Company anticipates that the net proceeds from the Offerings,
together with its cash flow from operations, net proceeds from the sale of
non-strategic assets and the availability of credit under the Bank Credit
Facilities, will be sufficient to fund the approximately $160 million of capital
expenditures budgeted for drilling and acquisition activities in 1997. Future
cash flows and the availability of financing are subject to a number of
variables, such as the level of production from existing wells, prices of oil
and gas and the Company's success in locating and producing new reserves. If
revenues were to decrease as
10
<PAGE> 11
a result of lower oil and gas prices, decreased production or otherwise, and the
Company had no availability under its Bank Credit Facilities, the Company could
be limited in its ability to replace its reserves or to maintain production at
current levels, resulting in a decrease in production and revenue over time. If
the Company's cash flow from operations and availability under its Bank Credit
Facilities are not sufficient to satisfy its capital expenditure requirements,
there can be no assurance that additional debt or equity financing will be
available to meet these requirements.
RELIANCE ON ESTIMATES OF RESERVES AND FUTURE NET CASH FLOWS
There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves, including many factors beyond the Company's
control. This Prospectus includes independent engineering estimates of the
Company's oil and gas reserves and future net cash flows that are based on the
reports of three different firms. Reserve engineering is a subjective process of
estimating underground accumulations of oil and gas that cannot be measured in
an exact manner. Estimates of economically recoverable oil and gas reserves and
of future net cash flow necessarily depend upon a number of variable factors and
assumptions, such as historical production from the area compared with
production from other producing areas, the assumed effects of regulation by
governmental agencies and assumptions concerning future oil and gas prices,
operating costs, severance and excise taxes, development costs and workover and
remedial costs, all of which may in fact vary considerably from actual results.
For these reasons, estimates of the economically recoverable quantities of oil
and gas attributable to any particular group of properties, classifications of
such reserves based on risk of recovery and estimates of the future net cash
flows expected therefrom prepared by different engineers or by the same
engineers at different times may vary significantly. Actual production, revenues
and expenditures with respect to the Company's reserves likely will vary from
estimates, and such variances may be material. In addition, the Company's
reserves and future cash flows may be subject to revisions, based upon
production history, results of future development, oil and gas prices,
performance of counterparties under agreements to which the Company is a party,
operating and development costs and other factors. See "Business and
Properties -- Oil and Gas Reserves."
The PV-10 values referred to in this Prospectus should not be construed as
the current market value of the estimated oil and gas reserves attributable to
the Company's properties. In accordance with applicable requirements of the
Securities and Exchange Commission ("SEC"), PV-10 is generally based on prices
and costs as of the date of the estimate, whereas actual future prices and costs
may be materially higher or lower. Actual future net cash flows also will be
affected by factors such as the amount and timing of actual production, supply
and demand for oil and gas, curtailments or increases in consumption by natural
gas purchasers and changes in governmental regulations or taxation. The timing
of actual future net cash flows from proved reserves, and thus their actual
present value, will be affected by the timing of both the production and the
incurrence of expenses in connection with development and production of oil and
gas properties. In addition, the 10% discount factor, which is required by the
SEC to be used to calculate PV-10 for reporting purposes, is not necessarily the
most appropriate discount factor based on interest rates in effect from time to
time and risks associated with the Company and its properties or the oil and gas
industry in general.
SUBSTANTIAL INDEBTEDNESS AND RESTRICTIONS
At December 31, 1996, the Company had outstanding $150 million in 11%
Senior Notes (the "Senior Notes") issued pursuant to an indenture governing the
Senior Notes (the "Indenture") and approximately $0.1 million of outstanding
indebtedness under the Credit Facility. In addition, in connection with the
consummation of the Medallion Acquisition, the Company incurred additional
indebtedness of $160.5 million. See "Capitalization." Giving effect to the
Offerings and the application of the net proceeds to repay amounts owed under
the Bank Credit Facilities, the Company expects to have approximately $156
million available for borrowing under the Bank Credit Facilities immediately
after the Offerings.
11
<PAGE> 12
The Company's level of indebtedness will have several important effects on
its future operations. A significant portion of the Company's cash flow from
operations must be dedicated to the payment of interest on its indebtedness and
will not be available for other purposes. The covenants contained in the Bank
Credit Facilities and the Indenture require the Company to meet certain
financial tests. Other restrictions will limit its ability to borrow additional
funds and may affect the Company's flexibility in planning for and reacting to
changes in its business, including possible acquisition activities. The
Company's ability to obtain additional financing in the future for working
capital, capital expenditures, acquisitions, general corporate purposes or other
purposes may also be restricted. There can be no assurance that the Company will
be able to remain in compliance with the financial ratios prescribed under the
Bank Credit Facilities. Failure to do so would result in a default and could
lead to the acceleration of the Company's indebtedness under the Bank Credit
Facilities and the Indenture. Moreover, if the Company's revenues were to
decrease as a result of lower oil and gas prices, decreased production or
otherwise, the borrowing base under the Bank Credit Facilities could be reduced
and could restrict the Company's future growth.
EXPLORATION RISKS
Exploratory drilling activities are subject to many risks, including the
risk that no commercially productive reservoirs will be encountered, and there
can be no assurance that new wells drilled by the Company will be productive or
that the Company will recover all or any portion of its investment. Drilling for
oil and gas may involve unprofitable efforts, not only from non-productive
wells, but from wells that are productive but do not produce sufficient net
revenues to return a profit after drilling, operating and other costs. The cost
of drilling, completing and operating wells is often uncertain. The Company's
drilling operations may be curtailed, delayed or canceled as a result of
numerous factors, many of which are beyond the Company's control, including
title problems, weather conditions, compliance with governmental requirements
and shortages or delays in the delivery of equipment and services.
MARKETING RISKS
The Company's ability to market oil and gas at commercially acceptable
prices is dependent on, among other factors, the availability and capacity of
gathering systems and pipelines, federal and state regulation of production and
transportation, general economic conditions and changes in supply and demand.
The Company's inability to respond appropriately to these changing factors could
have a negative effect on the Company's profitability.
ACQUISITION RISKS
Acquisitions of oil and gas businesses and properties and volumetric
production payments have been an important element of the Company's success, and
the Company will continue to seek acquisitions in the future. Even though the
Company performs a review (including a limited review of title and other
records) of the major properties it seeks to acquire that it believes is
consistent with industry practices, such reviews are inherently incomplete and
it is generally not feasible for the Company to review in-depth every property
and all records. Even an in-depth review may not reveal existing or potential
problems or permit the Company to become familiar enough with the properties to
assess fully their deficiencies and capabilities, and the Company may assume
environmental and other liabilities in connection with acquired businesses and
properties.
OPERATING RISKS
The Company's operations are subject to numerous risks inherent in the oil
and gas industry, including the risks of fire, explosions, blow-outs, pipe
failure, abnormally pressured formations and environmental accidents such as oil
spills, natural gas leaks, ruptures or discharges of toxic gases, the occurrence
of any of which could result in substantial losses to the Company due to injury
or loss of life, severe damage to or destruction of property, natural resources
and equipment, pollution or other environmental damage, clean-up
responsibilities, regulatory investigation and penalties and suspension
12
<PAGE> 13
of operations. The Company's operations may be materially curtailed, delayed or
canceled as a result of numerous factors, including the presence of
unanticipated pressure or irregularities in formations, accidents, title
problems, weather conditions, compliance with governmental requirements and
shortages or delays in the delivery of equipment. In accordance with customary
industry practice, the Company maintains insurance against some, but not all, of
the risks described above. There can be no assurance that the levels of
insurance maintained by the Company will be adequate to cover any losses or
liabilities. The Company cannot predict the continued availability of insurance,
or availability at commercially acceptable premium levels.
COMPETITIVE INDUSTRY
The oil and gas industry is highly competitive. The Company competes for
oil and gas business and property acquisitions and for the exploration,
development, production, transportation and marketing of oil and gas, as well as
for equipment and personnel, with major oil and gas companies, other independent
oil and gas concerns and individual producers and operators. Many of these
competitors have financial and other resources which substantially exceed those
available to the Company.
GOVERNMENT REGULATION
The Company's business is subject to certain federal, state and local laws
and regulations relating to the drilling for and production, transportation and
marketing of oil and gas, as well as environmental and safety matters. Such laws
and regulations have generally become more stringent in recent years, often
imposing greater liability on an increasing number of parties. Because the
requirements imposed by such laws and regulations are frequently changed, the
Company is unable to predict the effect or cost of compliance with such
requirements or their effects on oil and gas use or prices. In addition,
legislative proposals are frequently introduced in Congress and state
legislatures which, if enacted, might significantly affect the oil and gas
industry. In view of the many uncertainties which exist with respect to any
legislative proposals, the effect on the Company of any legislation which might
be enacted cannot be predicted. See "Business and Properties -- Regulation."
CERTAIN ANTI-TAKEOVER PROVISIONS
The Company's Certificate of Incorporation and Bylaws and the Delaware
General Corporation Law contain provisions that may have the effect of
discouraging unsolicited takeover proposals for the Company. These provisions,
among other things, provide for the classification of the Board of Directors,
restrict the ability of stockholders to take action by written consent,
authorize the Board of Directors to designate the terms of and issue new series
of preferred stock, limit the personal liability of directors, require the
Company to indemnify directors and officers to the fullest extent permitted by
applicable law and impose restrictions on business combinations with certain
interested parties.
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This Prospectus includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended (the "Securities Act"),
and Section 21E of the Securities Exchange Act of 1934, as amended (the
"Exchange Act"). All statements other than statements of historical facts
included in this Prospectus, including without limitation, statements under
"Prospectus Summary," "Risk Factors," "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and "Business and Properties,"
regarding planned capital expenditures, increases in oil and gas production, the
number of anticipated wells to be drilled after the date of this Prospectus, the
Company's financial position, business strategy and other plans and objectives
for future operations, are forward-looking statements. Although the Company
believes that the expectations reflected in such forward-looking statements are
reasonable, it can give no assurance that such expectations will prove to have
been correct. There are numerous uncertainties inherent in estimating quantities
of proved oil and gas reserves and in projecting future rates of production and
timing of development expenditures, including many
13
<PAGE> 14
factors beyond the control of the Company. Reserve engineering is a subjective
process of estimating underground accumulations of oil and gas that cannot be
measured in an exact way, and the accuracy of any reserve estimate is a function
of the quality of available data and of engineering and geological
interpretation and judgment. As a result, estimates made by different engineers
often vary from one another. In addition, results of drilling, testing and
production subsequent to the date of an estimate may justify revisions of such
estimate and such revisions, if significant, would change the schedule of any
further production and development drilling. Accordingly, reserve estimates are
generally different from the quantities of oil and gas that are ultimately
recovered. Additional important factors that could cause actual results to
differ materially from the Company's expectations are disclosed under "Risk
Factors" and elsewhere in this Prospectus, including without limitation in
conjunction with the forward-looking statements included in this Prospectus. All
subsequent written and oral forward-looking statements attributable to the
Company or persons acting on its behalf are expressly qualified in their
entirety by such factors.
USE OF PROCEEDS
The net proceeds to the Company from the Offerings are estimated to be
approximately $110.7 million ($127.5 million if the Underwriters' over-allotment
options are exercised in full), after deducting estimated offering expenses
payable by the Company. These net proceeds will be used by the Company to reduce
the outstanding indebtedness under the Bank Credit Facilities, including amounts
under the Revolving Credit Agreement used to fund a portion of the Medallion
Acquisition. Substantially all of the indebtedness incurred under the Bank
Credit Facilities was used to consummate the Medallion Acquisition.
At December 31, 1996, the outstanding balance under the Credit Facility was
$0.1 million. To consummate the Medallion Acquisition, the Company borrowed
$55.5 million under the Credit Facility and $105 million under the Revolving
Credit Agreement and paid the balance of the adjusted cash purchase price from
available cash. After receipt of the net proceeds from the Offerings, it is the
Company's intention to reduce the outstanding indebtedness under the Credit
Facility and the Revolving Credit Agreement by approximately $110.7 million,
leaving an outstanding balance under the Bank Credit Facilities of approximately
$54 million.
At January 29, 1997, the Credit Facility had a borrowing base of $75
million and bore interest at a rate of 7.2% per annum. At January 29, 1997, the
Revolving Credit Agreement had a borrowing base of $135 million and bore
interest at a rate of 9.5% per annum. It is secured by substantially all the
assets of Medallion and a pledge of Medallion's common stock. The interest rates
payable under the Bank Credit Facilities fluctuate based on certain published
interest rates. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Liquidity and Capital Resources -- Debt Financing."
14
<PAGE> 15
CAPITALIZATION
The following table sets forth as of September 30, 1996 (i) the actual
capitalization of the Company, (ii) the pro forma capitalization of the Company
after giving effect to the debt incurred pursuant to the Medallion Acquisition
under the Bank Credit Facilities, including the Revolving Credit Agreement, and
to the warrants to purchase 435,000 shares of Common Stock issued in connection
with the Medallion Acquisition and (iii) the pro forma as adjusted
capitalization of the Company after giving effect to the Offerings, the receipt
of the net proceeds therefrom and the application of such net proceeds as set
forth under "Use of Proceeds." The table should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations," "Pro Forma Financial Information" and the Company's Consolidated
Financial Statements (including the notes thereto) included elsewhere in this
Prospectus.
<TABLE>
<CAPTION>
SEPTEMBER 30, 1996
------------------------------------
PRO FORMA
ACTUAL PRO FORMA AS ADJUSTED
-------- --------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Long-term debt:
Bank Credit Facilities................................ $ 100 $156,613 $ 45,896
11% Senior Notes due 2003............................. 149,434 149,434 149,434
Other................................................. 296 296 296
-------- -------- --------
Total long-term debt.......................... 149,830 306,343 195,626
Stockholders' equity:
Preferred stock: 5,000,000 shares authorized; none
issued............................................. -- -- --
Common stock, par value $0.01 per share: 50,000,000
shares authorized; 12,488,120 issued; 15,488,120 as
adjusted........................................... 125 125 155
Stock warrants issued................................. 626 5,624 5,624
Additional paid-in capital............................ 25,371 25,371 136,058
Retained earnings..................................... 93,578 93,578 93,578
Less treasury stock, 900,748 shares at cost........... (3,388) (3,388) (3,388)
-------- -------- --------
Total stockholders' equity.................... 116,312 121,310 232,027
-------- -------- --------
Total capitalization.......................... $266,142 $427,653 $427,653
======== ======== ========
</TABLE>
15
<PAGE> 16
PRICE RANGE OF COMMON STOCK
The Common Stock is traded on the New York Stock Exchange under the symbol
"KCS." The high and low closing sales prices for the periods listed below were
taken from the New York Stock Exchange Composite Transactions Tape. The last
reported sales price of the Common Stock on January 29, 1997 was $39.625.
<TABLE>
<CAPTION>
HIGH LOW
------ ------
<S> <C> <C>
1994
First Quarter............................................... $29.00 $21.75
Second Quarter.............................................. 26.38 19.63
Third Quarter............................................... 21.88 16.13
Fourth Quarter.............................................. 18.75 12.25
1995
First Quarter............................................... 17.25 14.63
Second Quarter.............................................. 22.25 15.25
Third Quarter............................................... 21.88 13.75
Fourth Quarter.............................................. 16.75 9.88
1996
First Quarter............................................... 15.75 13.38
Second Quarter.............................................. 28.75 15.63
Third Quarter............................................... 35.63 26.75
Fourth Quarter.............................................. 44.13 28.88
1997
First Quarter (through January 29, 1997).................... 42.00 34.88
</TABLE>
There were 1,184 stockholders of record of the Common Stock on December 31,
1996.
DIVIDEND POLICY
The Company commenced paying cash dividends on its Common Stock in February
1992. For the years ended December 1993, 1994 and 1995, the Company's annual
dividends paid were $0.06, $0.09 and $0.12 per share, respectively. On November
21, 1996, the Company declared its most recent quarterly dividend of $0.03 per
share for record holders of its Common Stock as of January 10, 1997, payable on
February 20, 1997. The Company's policy is to retain a substantial portion of
its earnings to provide funds for reinvestment within the Company's business.
The Company is a holding company that conducts all of its operations through its
subsidiaries. As a result, the Company's ability to pay dividends is dependent
upon the cash flow of its subsidiaries. The payment of dividends is also
contingent upon, among other factors, business conditions, business results,
operating cash requirements and the financial condition of the Company, and will
be at the discretion of the Board of Directors. In addition, under the terms of
the Indenture and the Bank Credit Facilities, the payment of dividends is
limited to 50% of the Company's consolidated net income commencing October 1,
1995. See Note 4 to the Consolidated Financial Statements.
16
<PAGE> 17
PRO FORMA FINANCIAL INFORMATION
The following unaudited pro forma financial information is derived from the
historical financial statements of KCS Energy, Inc., the InterCoast Entities
(Medallion) and the Sawyer Canyon Properties included elsewhere in this
Prospectus.
The unaudited Pro Forma Statement of Consolidated Income for the year ended
December 31, 1995 reflects (i) the Company's Rocky Mountain Acquisition and
Michigan Acquisition, (ii) the sale of the Senior Notes, (iii) the Medallion
Acquisition (which includes Medallion's acquisition of the Sawyer Canyon
Properties in April 1996) and (iv) the Offerings and the application of the
estimated net proceeds therefrom as if each transaction had occurred on January
1, 1995.
The unaudited Pro Forma Statement of Consolidated Income for the nine
months ended September 30, 1996 reflects the Medallion Acquisition (which
includes Medallion's acquisition of the Sawyer Canyon Properties in April 1996),
the Offerings and the application of the estimated net proceeds therefrom as if
each transaction had occurred on January 1, 1995.
The unaudited Pro Forma Consolidated Balance Sheet as of September 30, 1996
reflects the Medallion Acquisition, the Offerings and the application of the
estimated net proceeds therefrom as if each transaction had occurred on
September 30, 1996.
The unaudited pro forma financial data should be read in conjunction with
the notes thereto and the Consolidated Financial Statements of the Company
(including the notes thereto) included elsewhere in this Prospectus. The
unaudited pro forma financial data does not purport to be indicative of the
financial position or results of operations that would actually have occurred if
the transactions described had occurred as presented in such statements or that
may be obtained in the future. In addition, future results may vary
significantly from the results reflected in such statements due to normal crude
oil and gas production declines, changes in prices received for crude oil and
gas, future acquisitions and dispositions of reserves, changes in estimates of
reserves and of the future net revenues therefrom and other factors.
17
<PAGE> 18
KCS ENERGY, INC.
PRO FORMA STATEMENT OF CONSOLIDATED INCOME
FOR THE YEAR ENDED DECEMBER 31, 1995
(UNAUDITED, DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
KCS
ACQUISITIONS
AND NOTE KCS MEDALLION ACQUISITION
KCS OFFERING PRO FORMA MEDALLION MEDALLION PRO FORMA AND OTHER
HISTORICAL ADJUSTMENTS COMBINED HISTORICAL ACQUISITIONS COMBINED ADJUSTMENTS
---------- ------------ --------- ---------- ------------- --------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Revenue........................ $ 449,965 $ 15,035(a) $ 465,000 $ 73,460 $ 72,881(a) $ 146,341 $ --
Operating costs and expenses:
Cost of natural gas sales..... 356,186 -- 356,186 24,361 57,216(a) 81,577 --
Other operating and
administrative expenses..... 18,669 4,769(a) 23,438 17,210 4,024(a) 21,234 --
Depreciation, depletion and
amortization................ 39,209 5,207(b) 44,416 21,705 -- 21,705 611(b)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating costs and expenses.. 414,064 9,976 424,040 63,276 61,240 124,516 611
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating income............ 35,901 5,059 40,960 10,184 11,641 21,825 (611)
Interest and other income,
net........................... 3,713 -- 3,713 -- -- -- --
Interest expense............... (7,732) (11,108)(c) (18,840) -- -- -- (6,827)(d)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Income before income taxes
(benefit)..................... 31,882 (6,049) 25,833 10,184 11,641 21,825 (7,438)
Federal and state income taxes
(benefit)..................... 10,576 (2,117)(e) 8,459 3,638 4,074(e) 7,712 (2,603)(e)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Net income (loss)......... $ 21,306 $ (3,932) $ 17,374 $ 6,546 $ 7,567 $ 14,113 $ (4,835)
========== ========== ========== ========== ========== ========== ==========
Earnings per share............. $ 1.81
==========
Average shares outstanding..... 11,760,701 3,000,000
========== ==========
<CAPTION>
PRO FORMA
AS ADJUSTED
-----------
<S> <C>
Revenue........................ $ 611,341
Operating costs and expenses:
Cost of natural gas sales..... 437,763
Other operating and
administrative expenses..... 44,672
Depreciation, depletion and
amortization................ 66,732
----------
Operating costs and expenses.. 549,167
----------
Operating income............ 62,174
Interest and other income,
net........................... 3,713
Interest expense............... (25,667)
----------
Income before income taxes
(benefit)..................... 40,220
Federal and state income taxes
(benefit)..................... 13,568
----------
Net income (loss)......... $ 26,652
==========
Earnings per share............. $ 1.81
==========
Average shares outstanding..... 14,760,701
==========
</TABLE>
See accompanying Notes to Unaudited Pro Forma Consolidated Financial Statements.
18
<PAGE> 19
KCS ENERGY, INC.
PRO FORMA STATEMENT OF CONSOLIDATED INCOME
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1996
(UNAUDITED, DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
MEDALLION ACQUISITION
KCS MEDALLION SAWYER CANYON PRO FORMA AND OTHER PRO FORMA
HISTORICAL HISTORICAL PROPERTIES(F) COMBINED ADJUSTMENTS AS ADJUSTED
----------- ----------- ---------------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Revenue........................ $ 316,604 $ 160,508 $ 3,740 $ 164,248 $ -- $ 480,852
Operating costs and expenses:
Cost of natural gas sales.... 231,063 106,546 -- 106,546 -- 337,609
Other operating and
administrative expenses.... 19,427 15,883 645 16,528 -- 35,955
Depreciation, depletion and
amortization............... 33,933 20,360 -- 20,360 84(g) 54,377
----------- ----------- ----------- ----------- ----------- -----------
Operating costs and
expenses................... 284,423 142,789 645 143,434 84 427,941
----------- ----------- ----------- ----------- ----------- -----------
Operating income........... 32,181 17,719 3,095 20,814 (84) 52,911
Interest and other income,
net.......................... 4,850 -- -- -- -- 4,850
Interest expense............... (13,858) (992) -- (992) (3,223)(h) (18,073)
----------- ----------- ----------- ----------- ----------- -----------
Income before income taxes
(benefit).................... 23,173 16,727 3,095 19,822 (3,307) 39,688
Federal and state income taxes
(benefit).................... 8,367 5,973 1,083(i) 7,056 (1,157)(i) 14,266
----------- ----------- ----------- ----------- ----------- -----------
Net income (loss)..... $ 14,806 $ 10,754 $ 2,012 $ 12,766 $ (2,150) $ 25,422
=========== =========== =========== =========== =========== ===========
Earnings per share............. $ 1.25 $ 1.71
=========== ===========
Average shares outstanding..... 11,886,434 3,000,000 14,886,434
=========== =========== ===========
</TABLE>
See accompanying Notes to Unaudited Pro Forma Consolidated Financial Statements.
19
<PAGE> 20
KCS ENERGY, INC.
PRO FORMA CONSOLIDATED BALANCE SHEET
AS OF SEPTEMBER 30, 1996
(UNAUDITED, DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
ACQUISITION PRO
KCS MEDALLION AND OTHER FORMA OFFERING PRO FORMA
HISTORICAL HISTORICAL ADJUSTMENTS COMBINED ADJUSTMENTS AS ADJUSTED
---------- ---------- ----------- --------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents........... $ 53,597 $ 3,542 $ (50,030)(m) $ 7,109 $ -- $ 7,109
Trade accounts receivable, net...... 39,146 29,740 -- 68,886 -- 68,886
Fuel inventories.................... 884 -- -- 884 -- 884
Other current assets................ 5,055 2,332 -- 7,387 -- 7,387
-------- -------- ---------- -------- ---------- --------
Current assets.................... 98,682 35,614 (50,030) 84,266 -- 84,266
Property, plant and equipment, net:
Oil and gas properties, net......... 206,308 199,427 (5,152)(j) 400,583 -- 400,583
Natural gas transportation systems,
net............................... 22,296 2,950 2,050(j) 27,296 -- 27,296
Other property, plant and
equipment......................... 2,979 1,174 (674)(j) 3,479 -- 3,479
-------- -------- ---------- -------- ---------- --------
Property, plant and equipment,
net............................. 231,583 203,551 (3,776) 431,358 -- 431,358
-------- -------- ---------- -------- ---------- --------
Investments and other assets.......... 10,887 5,066 (3,266)(j) 12,687 -- 12,687
-------- -------- ---------- -------- ---------- --------
$341,152 $244,231 $ (57,072) $528,311 $ -- $528,311
======== ======== ========== ======== ========== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable.................... $ 34,680 $ 21,461 $ -- $ 56,141 $ -- $ 56,141
Accrued liabilities................. 7,032 4,187 -- 11,219 -- 11,219
-------- -------- ---------- -------- ---------- --------
Current liabilities............... 41,712 25,648 -- 67,360 -- 67,360
Deferred credits and other
liabilities......................... 33,298 31,866 (31,866)(j) 33,298 -- 33,298
Long-term debt........................ 149,830 52,402 104,111(k)(m) 306,343 (110,717)(n) 195,626
Stockholders' equity:
Preferred stock..................... -- -- -- -- -- --
Common stock........................ 125 3 (3)(j) 125 30(n) 155
Additional paid-in capital.......... 25,997 100,769 (95,771)(l) 30,995 110,687(n) 141,682
Retained earnings................... 93,578 33,543 (33,543)(j) 93,578 -- 93,578
Less treasury stock................. (3,388) -- -- (3,388) -- (3,388)
-------- -------- ---------- -------- ---------- --------
Total stockholders' equity.... 116,312 134,315 (129,317) 121,310 110,717 232,027
-------- -------- ---------- -------- ---------- --------
$341,152 $244,231 $ (57,072) $528,311 $ -- $528,311
======== ======== ========== ======== ========== ========
</TABLE>
See accompanying Notes to Unaudited Pro Forma Consolidated Financial Statements.
20
<PAGE> 21
KCS ENERGY, INC.
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
(DOLLARS IN THOUSANDS)
The accompanying pro forma financial statements have been prepared to
reflect certain adjustments to the historical consolidated financial statements
of the Company.
Unaudited Pro Forma Statement of Consolidated Income for the Year Ended December
31, 1995:
(a) Adjustments to reflect revenues, cost of sales and other operating
expenses from January 1, 1995, until the dates of the Rocky Mountain
Acquisition and the Michigan Acquisition by the Company, the Sawyer Canyon
and other acquisitions of Medallion, and the Medallion Acquisition by the
Company.
(b) Adjustments to reflect depreciation, depletion and amortization
expense calculated using the future gross revenue method applied to the
adjusted basis of the acquired properties and entities using the purchase
method of accounting.
(c) Adjustment to reflect additional interest expense calculated,
assuming the Company's As Adjusted debt balance at December 31, 1995
($170,529), was outstanding for the entire year, including amortization of
deferred financing cost.
(d) Adjustment to reflect incremental interest expense under the Bank
Credit Facilities ($15,488) to fund the $206,543 cash payment for the
Medallion Acquisition, and to reflect the interest expense savings ($8,661)
resulting from the application of the estimated net proceeds of $110,717
from the Offerings ($117,000 in gross proceeds net of $6,283 in estimated
underwriting discount and expenses and an offering price of $39.00 per
share).
(e) Adjustments to the provision for income taxes related to the above
adjustments.
Unaudited Pro Forma Statement of Consolidated Income for the Nine Months ended
September 30, 1996:
(f) Reflects results of operations for the Sawyer Canyon Properties
for the three months ended March 31, 1996, prior to their acquisition by
Medallion on April 1, 1996.
(g) Adjustment to reflect depreciation, depletion and amortization
expense calculated using the future gross revenue method applied to the
adjusted basis of the Medallion Acquisition using the purchase method of
accounting.
(h) Adjustment to reflect interest expense savings ($1,915) based on
the assumption that the September 30, 1996 debt balance had been
outstanding for the entire nine-month period, to reflect incremental
interest expense under the Bank Credit Facilities ($11,616) to fund the
$206,543 cash payment for the Medallion Acquisition, and to reflect the
interest expense savings ($6,478) as a result of the application of the
estimated net proceeds of $110,717 from the Offerings.
(i) Adjustment to the provision for income taxes related to the above
adjustments.
Unaudited Pro Forma Consolidated Balance Sheet as of September 30, 1996:
(j) Adjustment to (i) eliminate the historical basis of certain assets
and liabilities of Medallion and (ii) reflect the adjusted basis of these
items using the purchase method of accounting. (See detail of the purchase
price and related allocation to assets and liabilities in the table below.)
(k) Adjustment to reflect the elimination of the historical debt of
Medallion of $52,402 and additional debt under the Bank Credit Facilities
of $206,543 used to fund a portion of the Medallion Acquisition.
21
<PAGE> 22
KCS ENERGY, INC.
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS)
(l) Adjustment to reflect the elimination of the historical paid-in
capital of Medallion and the issuance of warrants to purchase 435,000
shares of Common Stock granted in connection with the Medallion Acquisition
presented at estimated fair value ($4,998).
(m) Reflects the application of $50,030 from cash to reduce long-term
debt.
(n) Adjustment to reflect the application of the estimated net
proceeds of $110,717 from the Offerings to reduce long-term debt.
The following table summarizes elements of the Medallion Acquisition, which was
accounted for by the Company as a purchase transaction:
<TABLE>
<S> <C>
Consideration:
Cash Purchase Price....................................... $ 209,396
Adjustment to reflect free cash flow from Medallion's
operations subsequent to the effective date of July 1,
1996 and through September 30, 1996.................... (2,853)
Cash paid to seller....................................... 206,543
Common stock warrants issued to seller.................... 4,998
Liabilities Assumed:
Current liabilities....................................... 25,648
Assets Acquired:
Current assets............................................ (35,614)
Other assets.............................................. (1,800)
---------------
$ 199,775
===============
</TABLE>
22
<PAGE> 23
KCS ENERGY, INC.
SELECTED HISTORICAL FINANCIAL INFORMATION
The historical financial data presented below is derived from the Company's
financial statements. The information in this table should be read in
conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and the Consolidated Financial Statements (including
the notes thereto) included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------------------------------------------- -----------------------
1991 1992 1993 1994 1995 1995 1996
---------- ---------- ---------- ---------- ---------- ---------- ----------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA) (UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenue:
Oil and gas exploration and
production....................... $ 9,302 $ 13,496 $ 40,455 $ 66,215 $ 86,629 $ 63,425 $ 79,051
Natural gas transportation and
marketing........................ 108,549 141,562 264,710 279,155 365,354 270,557 238,254
Intercompany....................... (624) (779) (876) (3,657) (2,018) (1,708) (701)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total........................ 117,227 154,279 304,289 341,713 449,965 332,274 316,604
Operating costs and expenses:
Cost of natural gas sales.......... 100,072 133,590 253,435 265,076 356,186 264,097 231,063
Other operating and administrative
expenses......................... 10,017 10,806 15,018 18,285 18,669 12,950 19,427
Depreciation, depletion and
amortization..................... 3,227 3,800 8,036 19,740 39,209 29,299 33,933
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total........................ 113,316 148,196 276,489 303,101 414,064 306,346 284,423
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating income.................... 3,911 6,083 27,800 38,612 35,901 25,928 32,181
Interest and other income, net...... 787 757 704 1,039 3,713 2,311 4,850
Interest expense.................... (1,239) (1,297) (1,983) (2,938) (7,732) (4,912) (13,858)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Income before income taxes.......... 3,459 5,543 26,521 36,713 31,882 23,327 23,173
Federal and state income taxes...... 885 1,533 7,910 12,556 10,576 7,645 8,367
---------- ---------- ---------- ---------- ---------- ---------- ----------
Net income.......................... $ 2,574 $ 4,010 $ 18,611 $ 24,157 $ 21,306 $ 15,682 $ 14,806
========== ========== ========== ========== ========== ========== ==========
Earnings per share.................. $ 0.24 $ 0.36 $ 1.60 $ 2.05 $ 1.81 $ 1.33 $ 1.25
Average common shares outstanding... 10,750,490 11,138,157 11,658,370 11,804,989 11,760,701 11,766,011 11,886,434
Dividends per common share.......... $ 0.01 $ 0.03 $ 0.06 $ 0.09 $ 0.12 $ 0.09 $ 0.09
OTHER DATA:
EBITDA.............................. $ 7,138 $ 9,883 $ 35,836 $ 58,352 $ 75,110 $ 55,227 $ 66,114
Capital expenditures................ 7,809 13,867 48,455 74,953 128,699 57,455 52,735
BALANCE SHEET DATA (AT END OF
PERIOD):
Cash and cash equivalents........... $ 1,914 $ 4,292 $ 5,369 $ 988 $ 5,846 $ 4,187 $ 53,597
Working capital..................... 4,002 5,966 10,368 16,215(1) 60,090(1) 43,437(1) 56,970
Oil and gas properties, net......... 19,028 30,828 70,477 125,621 204,958 146,130 206,308
Total assets........................ 72,077 88,220 165,990 214,423 360,609 271,982 341,152
Long-term debt...................... 15,707 21,637 36,289 61,970 165,529 90,800 149,830
Total stockholders' equity.......... 26,317 30,233 59,765 80,668 101,576 95,626 116,312
</TABLE>
- ---------------
(1) Includes the Tennessee Gas Receivable at such dates.
23
<PAGE> 24
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following is a discussion and analysis of the Company's financial
condition and results of operations and should be read in conjunction with the
Company's Consolidated Financial Statements (including the notes thereto)
included elsewhere in this Prospectus.
GENERAL
In the past year, several important developments have had and will continue
to have a significant impact on the Company's financial condition and results of
operations. On December 23, 1996, the Company and Tennessee Gas entered into a
settlement covering all claims and litigation between them related to the
Tennessee Gas Contract. As part of the settlement, the Tennessee Gas Contract
was terminated effective January 1, 1997, approximately two years prior to its
expiration date. The parties also agreed to the dismissal of the contract
dispute that resulted in a November 1996 jury award to Tennessee Gas of $143.2
million (including $114 million in punitive damages). See "Business and
Properties -- Legal Proceedings -- Tennessee Gas Litigation." The early
termination of the Tennessee Gas Contract with its above-market pricing
provisions resulted in downward revisions in the amounts of $59.5 million for
estimated future net revenues before income taxes (based upon a natural gas
price of $2.10 per Mcf, the assumed realized spot market price on June 30, 1996)
and $51.4 million for PV-10, as compared to prior reserve reports prepared as of
June 30, 1996. Except for the revisions to future net revenues, the Company's
financial statements will not be directly affected as a result of the settlement
and early termination of the contract.
The December 1996 settlement did not affect the Company's successful
conclusion of litigation earlier in the year relating to the validity and
pricing provisions of the Tennessee Gas Contract and its recovery of past
underpayments (including interest and net of severance taxes and other payables
related to the contract) that had accrued under the contract. On September 30,
1996, Tennessee Gas paid the Company approximately $70 million, representing the
amount of the Tennessee Gas Receivable at that date.
As of December 31, 1996, the Company completed the arrangements for the
acquisition of all of the outstanding stock of Medallion for a total purchase
price of approximately $214.4 million, consisting of $209.4 million in cash
(reduced at the January 2, 1997 closing by $15.3 million principally to reflect
free cash flow from Medallion's operations subsequent to the July 1, 1996
effective date) and warrants to purchase 435,000 shares of Common Stock. The
Company has also made two other significant recent acquisitions. In November
1995, the Company acquired substantially all of the oil and gas assets of
Natural Gas Processing Company for a purchase price of approximately $33 million
and in December 1995, the Company acquired 24.6 Bcfe of proved reserves in the
northern and southern Niagaran Reef trend in Michigan for $31 million.
These developments have transformed the Company from an enterprise
dependent upon the Bob West Field and the Tennessee Gas Contract to a more
diversified enterprise focusing on the acquisition and development of oil and
gas assets located in three core operating areas -- the Gulf Coast region, the
Rocky Mountain region and the Mid-Continent region -- and on its VPP program.
NINE MONTHS ENDED SEPTEMBER 30, 1996 AND 1995
Results of Operations -- Consolidated
For the nine months ended September 30, 1996, net income was $14.8 million
($1.25 per share), compared to $15.7 million ($1.33 per share) for the same
period in 1995. Significantly higher oil and gas production, along with higher
oil and gas prices in the current year for non-Tennessee Gas Contract sales were
offset by lower production from properties covered by the Tennessee Gas
Contract, higher interest costs and a higher effective income tax rate.
24
<PAGE> 25
Results of Operations -- Business Segments
Segment information reflects volumes, revenues and expenses associated with
transactions involving affiliates which are eliminated in consolidation.
Oil and Gas Exploration and Production
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
-------------------------
1995 1996
------- -------
(UNAUDITED, DOLLARS IN THOUSANDS
EXCEPT PER UNIT DATA)
<S> <C> <C>
Revenue........................................ $63,425 $79,051
Production (lifting) costs..................... 4,353 8,253
Depreciation, depletion and amortization....... 28,447 32,865
Other operating expenses....................... 1,816 2,877
------- -------
Operating income.......................... $28,809 $35,056
======= =======
Oil production (Mbbl).......................... 111 547
Natural gas production (MMcf):
Tennessee Gas Contract....................... 5,446 3,576
Other........................................ 7,858 15,346
------- -------
Total natural gas production.............. 13,304 18,922
======= =======
Average sales price:
Oil (per bbl)................................ $ 17.53 $ 19.72
Natural gas (per Mcf)........................ 4.60 3.61
Average equivalent sales price (per Mcfe).... 4.54 3.56
Average lifting cost (per Mcfe)................ 0.31 0.37
DD&A as a percent of revenue................... 44.9% 41.6%
</TABLE>
Oil and gas production increased 59% to 22,204 MMcfe for the nine months
ended September 30, 1996, compared to the corresponding period in 1995. The
increase in production during 1996 resulted from newly added properties and
reflected the Company's overall growth strategy to increase its percentage of
non-Tennessee Gas Contract production. Non-Tennessee Gas Contract production
accounted for 84% of total production during the 1996 period, up from 61% during
the 1995 period. Approximately 5,851 MMcfe of the increase in non-Tennessee Gas
Contract production was attributable to the Company's VPP program, with the
remainder attributable to increased exploitation and development drilling. For
the nine months ended September 30, 1996, sales to Tennessee Gas decreased to
3,576 MMcf, compared to 5,446 MMcf during 1995, when Tennessee Gas took
additional deliveries to offset earlier curtailments.
Average natural gas prices were $3.61 per Mcf for the nine months ended
September 30, 1996, compared to $4.60 per Mcf for the same period in 1995. This
decrease reflects the lower Tennessee Gas Contract production which offset the
significant increase in non-Tennessee Gas Contract production and higher average
spot market prices. Average non-Tennessee Gas Contract gas prices were $2.29
during the 1996 period, compared to $1.56 during the same period in 1995.
Natural gas sale prices under the Tennessee Gas contract, excluding severance
tax reimbursements, were $8.38 during the nine-month period ended September 30,
1996, compared to $7.84 during the same period in 1995.
The increases in costs and expenses were mainly attributable to the
increase in production volume.
25
<PAGE> 26
Natural Gas Transportation and Marketing
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
-------------------------
1995 1996
-------- --------
(UNAUDITED, DOLLARS IN
THOUSANDS
EXCEPT PER UNIT DATA)
<S> <C> <C>
Revenue.......................................... $270,557 $238,254
Cost of natural gas sales........................ 265,213 231,343
-------- --------
Gross margin................................ 5,344 6,911
Depreciation..................................... 803 1,007
Other operating expenses......................... 5,825 6,183
-------- --------
Operating loss.............................. $ (1,284) $ (279)
======== ========
Transportation volume (Bcf)...................... 19.4 20.1
Transportation gross margin (per Mcf)............ $ 0.159 $ 0.186
Marketing volume (Bcf)........................... 167.1 87.2
Marketing gross margin (per Mcf)................. $ 0.014 $ 0.036
Marketing operating expense (per Mcf)............ 0.027 0.050
</TABLE>
The marketing operations had an operating loss of $1.3 million for the nine
months ended September 30, 1996, compared to a loss of $2.3 million for the same
period in 1995. The significant decline in marketed volumes and revenue during
the 1996 period reflect a strategic shift away from higher volume low margin
"gas trading" activities and toward an emphasis on the core retail customer
base. Coupled with higher natural gas prices in 1996, this resulted in the
increases in gross margin per Mcf of marketing volumes.
The natural gas transportation operations had operating income of $1.0
million in each of the nine-month periods ended September 30, 1996 and 1995. The
increases in transportation volumes and gross margin per Mcf were offset by
higher operating and maintenance expenses.
Interest and Other Income, Net
Interest income accrued on the Tennessee Gas Receivable was $4.7 million
for the nine months ended September 30, 1996, compared to $1.9 million during
the same period in 1995. See "-- Liquidity and Capital Resources."
Interest Expense
For the nine months ended September 30, 1996, interest expense was $13.9
million, compared to $4.9 million for the same period in 1995. The increase in
1996 was due to higher average borrowings, along with higher average interest
rates principally resulting from the sale of $150 million of the 11% Senior
Notes in January 1996. The Company did not collect the contract price from
Tennessee Gas throughout 1995 and therefore increased its borrowings to expand
its oil and gas exploration and production operations. These borrowings included
approximately $64 million for the Rocky Mountain and Michigan Acquisitions,
completed during the fourth quarter of 1995.
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
Results of Operations -- Consolidated
Net income was $21.3 million ($1.81 per share) in 1995, compared to $24.2
million ($2.05 per share) in 1994 and $18.6 million ($1.60 per share) in 1993.
Lower natural gas prices in 1995 affected each of the Company's operating
businesses, and combined with higher net interest costs incurred to fund the
growth of the Company's oil and gas exploration and production operations to
reduce 1995 earnings compared to 1994. Milder than normal winter weather
conditions and an oversupply of natural
26
<PAGE> 27
gas during the winter of 1994-1995 resulted in a 10% decline in average natural
gas prices for the Company's non-Tennessee Gas Contract production in 1995,
which reduced somewhat the benefits of significantly increased natural gas
production. The mild weather and lower natural gas prices particularly affected
the Company's natural gas marketing operations, which posted a significant
decline in operating income during 1995.
The increase in earnings in 1994 compared to 1993 was due mainly to
increased natural gas production, principally from the Company's acreage in the
Bob West Field dedicated under the Tennessee Gas Contract. See Note 7 to the
Consolidated Financial Statements for information regarding the Tennessee Gas
Contract.
Results of Operations -- Business Segments
Segment information reflects all volumes, revenue and expenses, including
those associated with transactions involving affiliates which are eliminated in
consolidation. Each of the Company's business segments was adversely affected by
low natural gas prices during most of 1995.
Oil and Gas Exploration and Production
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1993 1994 1995
------- ------- -------
(DOLLARS IN THOUSANDS
EXCEPT PER UNIT DATA)
<S> <C> <C> <C>
Revenue.................................... $40,455 $66,215 $86,629
Production (lifting) costs................. 5,011 7,063 6,623
Depreciation, depletion and amortization... 7,004 18,538 37,988
Other operating expenses................... 1,785 2,671 2,373
------- ------- -------
Operating income...................... $26,655 $37,943 $39,645
======= ======= =======
Oil production (Mbbl)...................... 179 211 196
Natural gas production (MMcf):
Tennessee Gas Contract................... 4,472 6,851 6,924
Other.................................... 2,505 4,453 12,205
------- ------- -------
Total natural gas production.......... 6,977 11,304 19,129
======= ======= =======
Average sales price:
Oil (per bbl)............................ $ 17.57 $ 15.16 $ 17.28
Natural gas (per Mcf).................... 5.27 5.54 4.29
Average equivalent sales price (per
Mcfe)................................. 5.02 5.27 4.27
Average lifting cost (per Mcfe)............ 0.62 0.56 0.33
DD&A as a percent of revenue............... 17.3% 28.0% 43.9%
</TABLE>
The 69% increase in natural gas production in 1995 compared to 1994 was due
mainly to newly added properties not covered by the Tennessee Gas Contract.
Approximately 7.4 Bcf of the increase in non-Tennessee Gas Contract natural gas
production was attributable to the Company's VPP program, with the remainder
attributable to increased exploration and development drilling. Non-Tennessee
Gas Contract oil and gas production accounted for 66% of total production in
1995, compared to 45% in 1994 and 44% in 1993. The increase in non-Tennessee Gas
Contract production as a percentage of total production, while an integral part
of the Company's overall growth strategy during this period, made the Company
more sensitive to fluctuations in the market price of oil and gas. Accordingly,
while total production and revenue were up significantly in 1995, a 10% decline
in average non-Tennessee Gas Contract natural gas prices had a negative impact
on the overall profitability of this segment. Average non-Tennessee Gas Contract
natural gas prices were approximately $1.62 in 1995, compared to $1.81 in 1994
and $2.02 in 1993.
27
<PAGE> 28
Tennessee Gas Contract production increased slightly in 1995 compared to
1994 largely as a result of the continued development of the Bob West Field,
which was able to more than offset the normal production decline from existing
wells. With planned development of known producing horizons nearly completed,
the Company anticipates that, absent any new discoveries, it will not be able to
completely offset normal production declines and therefore 1996 production from
this field will be less than in 1995 and will continue to decline thereafter.
Average sales prices under the Tennessee Gas Contract, excluding severance tax
reimbursements, were $7.90 in 1995, $7.49 in 1994 and $7.09 in 1993. The
Tennessee Gas Contract was terminated effective January 1, 1997, and sales
prices beyond that date will be made at lower spot market prices. See Note 7 to
the Consolidated Financial Statements for information regarding the Tennessee
Gas Contract.
The increase in DD&A in 1995 reflected the increase in production, as well
as an increase in the DD&A rate. The DD&A rate reflects, among other things, the
higher average oil and gas property investment in 1995, lower natural gas prices
and an increase in the percentage of total proved reserves not covered by the
Tennessee Gas Contract. In addition, the increase in the Company's reserves
attributable to the VPP program (which bear no lease operating expenses) as a
percentage of total reserves, contributed to the increase in the DD&A rate. The
effect of the higher DD&A rate was partially offset by a 41% reduction in
average lifting costs to $0.33 per Mcfe.
The significant growth of revenue and operating income in 1994 compared to
1993 was largely attributable to increased natural gas production, principally
as a result of the development of the Bob West Field and as a result of
acquisitions and further development of other producing properties.
The increase in total costs and expenses in 1994 compared to 1993 reflected
the significant expansion of oil and gas operations. Production costs and DD&A
increased mainly due to higher natural gas production.
Natural Gas Transportation and Marketing
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------
1993 1994 1995
-------- -------- --------
(DOLLARS IN THOUSANDS
EXCEPT PER UNIT DATA)
<S> <C> <C> <C>
Revenue............................... $264,710 $279,155 $365,354
Cost of natural gas sales............. 254,029 267,959 357,523
-------- -------- --------
Gross margin..................... 10,681 11,196 7,831
Depreciation.......................... 998 1,178 1,157
Other operating expenses.............. 6,105 7,129 8,023
-------- -------- --------
Operating income (loss).......... $ 3,578 $ 2,889 $ (1,349)
======== ======== ========
Transportation volume (Bcf)........... 24.3 20.9 25.9
Transportation gross margin (per
Mcf)................................ $ 0.135 $ 0.176 $ 0.172
Marketing volume (Bcf)................ 122.9 153.1 226.3
Marketing gross margin (per Mcf)...... $ 0.060 $ 0.049 $ 0.015
Marketing operating expense (per
Mcf)................................ 0.040 0.036 0.027
</TABLE>
The combination of (i) lower natural gas prices, (ii) increased competitive
pressures within the industry and (iii) the absence of severe weather conditions
during the 1994-1995 winter heating season were the primary reasons for the
decrease in operating income in 1995 compared to 1994, offsetting the increase
in marketing and transportation volumes. Average natural gas sales prices for
this segment were approximately 15% lower in 1995 compared to 1994 and average
marketing gross margins per Mcf were approximately 69% lower.
The increase in other operating expenses in 1995 compared to 1994 was
primarily due to costs associated with the expanded activities of the marketing
operations, the expansion of the gathering
28
<PAGE> 29
system associated with the Company's Texas intrastate pipeline and the timing of
routine pipeline repairs and maintenance.
The increase in revenue in 1994 compared to 1993 was due in part to the
unusually cold 1993-1994 winter in the northeastern part of the United States.
During this period of high demand for natural gas, the Company successfully
obtained supply and transportation at competitive prices and sold a significant
portion of its natural gas in the northeastern markets at "peaking" rates. The
decrease in marketing gross margin per Mcf in 1994 reflected the sales to
higher-volume, lower-margin customers, while the increase in transportation
gross margin per Mcf in 1994 was due mainly to an increase in higher-margin
volumes from the Company's gathering systems, along with higher margins on sales
and transportation to certain high-priority, weather-sensitive customers during
the 1993-1994 peak winter heating season.
The increase in operating expenses in 1994 compared to 1993 reflected
higher personnel and marketing costs to support the significant growth in
operations.
Interest and Other Income, Net
Interest and other income was $3.7 million in 1995, compared to $1.0
million in 1994 and $0.7 million in 1993. Of the 1995 amount, $3.1 million was
interest income recorded on the Tennessee Gas Receivable. See "-- Liquidity and
Capital Resources." In addition, the Company had $0.6 million of income from
other investments. The 1994 increase over 1993 was primarily due to a one-time
receipt of $0.5 million for interest on funds that were previously held by the
operator of the jointly-owned wells covered by the Tennessee Gas Contract.
Interest Expense
Interest expense was $7.7 million in 1995, compared to $2.9 million in 1994
and $2.0 million in 1993. These increases were primarily due to higher average
borrowings used to expand the Company's oil and gas exploration and production
operations, including acquisitions under its VPP program which began in late
1994. In 1995, the increase in borrowings was largely the result of interim
agreements with Tennessee Gas, whereby the Company received only partial cash
payments from Tennessee Gas for sales of natural gas production under the
Tennessee Gas Contract. See "-- Liquidity and Capital Resources" and Note 7 to
the Consolidated Financial Statements. Until the Tennessee Gas Receivable was
paid, the Company was required to utilize its credit facilities to a greater
extent in order to finance its capital spending program. The increase in
interest expense in 1995 was partially offset by the increase in interest income
as previously discussed. Higher average interest rates were also a contributing
factor in the year to year increases.
Income Taxes
The income tax provision was $10.6 million in 1995, representing an
effective tax rate of 33.2%, compared to 34.2% and 29.8% in 1994 and 1993,
respectively. See Note 6 to Consolidated Financial Statements for the
reconciliation of the statutory federal income tax rate to the Company's
effective tax rates. A substantial portion of the income taxes provided for by
the Company during these periods is deferred to future years.
LIQUIDITY AND CAPITAL RESOURCES
Tennessee Gas Litigation
On August 16, 1996, the Texas Supreme Court denied Tennessee Gas' petition
for a rehearing of the Court's April 1996 decision in favor of the Company
regarding the validity and pricing provisions of the Tennessee Gas Contract, and
on September 30, 1996, Tennessee Gas paid the Company approximately $70 million,
representing the Tennessee Gas Receivable at that date.
29
<PAGE> 30
The Company had been accruing an accounts receivable amount (which included
interest as provided for in the contract) due from Tennessee Gas that included
the difference between the price that would have been paid for natural gas
pursuant to the terms of the Tennessee Gas Contract and the amount actually paid
for natural gas delivered from September 17, 1994 through April 30, 1996
pursuant to interim agreements whereby Tennessee Gas paid $3.00 per MMBtu for
all natural gas purchased during that period. Tennessee Gas paid the contract
price for natural gas deliveries subsequent to April 30, 1996 and through the
termination of the Tennessee Gas Contract effective January 1, 1997.
On December 23, 1996, the Company and Tennessee Gas entered into a
settlement covering all claims and litigation between them related to the
Tennessee Gas Contract. As part of the settlement, the Tennessee Gas Contract
was terminated effective January 1, 1997, approximately two years prior to its
expiration date. The parties also agreed to the dismissal of the contract
dispute that resulted in a November 1996 jury award to Tennessee Gas of $143.2
million (including $114 million in punitive damages). This settlement did not
affect the April 1996 decision of the Texas Supreme Court or the Company's prior
recovery of the Tennessee Gas Receivable. By resolving this major uncertainty
and avoiding any requirement to post a supersedeas bond of nearly $150 million
in order to appeal the verdict, the Company believes it is better positioned to
continue its strategic plan to grow and diversify its proved oil and gas
reserves and reduce its dependency on production from the Bob West Field.
Posting a supersedeas bond of such magnitude would have significantly and
adversely affected the amount of capital available for future investment,
therefore constraining the growth of the Company.
The early termination of the Tennessee Gas Contract with its above-market
pricing provisions resulted in downward revisions in the amounts of $59.5
million for estimated future net revenues before income taxes (based upon a
natural gas price of $2.10 per Mcf, the assumed realized spot market price on
June 30, 1996) and $51.4 million for PV-10, as compared to prior reserve reports
prepared as of June 30, 1996. Except for the revisions to future net revenues,
the Company's financial statements will not be directly affected as a result of
the settlement and early termination of the contract.
Cash Flow From Operating Activities
Net income adjusted for noncash charges was $54.2 million for the nine
months ended September 30, 1996, compared to $53.7 million during the same
period in 1995. Net cash provided by operating activities was $105.1 million
during the current year nine-month period, compared to $28.7 million in the
prior-year period. This increase resulted primarily from the receipt of the
Tennessee Gas Receivable on September 30, 1996 and, to a lesser extent, the
timing of cash receipts and payments. See Note 7 to the Consolidated Financial
Statements.
Net income adjusted for non-cash charges increased to $71.1 million in
1995, compared to $54.7 million in 1994. However, net cash provided by operating
activities declined from $50.1 million in 1994 to $30.1 million in 1995,
primarily as a result of interim agreements under which Tennessee Gas had been
paying $3.00 per MMBtu. This price was less than the contract price which
Tennessee Gas had been paying until September 1994.
Trade accounts receivable increased $11.7 million and accounts payable
increased $15.3 million in 1995 primarily due to the timing of cash receipts and
cash payments related to the high volume activity of the natural gas marketing
operations and, to a lesser extent, the timing of cash receipts and payments of
the oil and gas exploration and production operations.
Investing Activities
Capital expenditures in 1995 were $128.7 million, of which $121.3 million
was invested in oil and gas properties. Of the $121.3 million, $43.8 million was
for the purchase of oil and gas reserves under the Company's VPP program
(including the Michigan Acquisition), $33 million was for the Rocky Mountain
Acquisition and $19.4 million was for the development of the Bob West Field. The
remainder was largely for lease acquisitions, seismic evaluations and
exploratory drilling ($16.9 million) and development drilling ($7.5 million) on
non-Tennessee Gas Contract properties. The Company funded its capital
30
<PAGE> 31
expenditures through a combination of additional borrowings under its credit
facilities and internally generated cash.
Following the completion of two significant oil and gas property
acquisitions in late 1995, totaling $64 million, the Company established an
initial $70 million capital budget for 1996. Included in the total was $30
million for oil and gas property acquisitions, $22 million for development
drilling and $15 million for exploration. Capital expenditures under the program
for the nine months ended September 30, 1996 were $52.7 million, of which $50.6
million were invested in oil and gas operations. Of that total, $30.2 million
was for development drilling, $8.0 million for the purchase of proved reserves
under the Company's VPP program and $12.4 million for lease acquisitions,
seismic surveys and exploratory drilling. The expenditures were financed
principally with $16.4 million of proceeds from the sale of certain
non-strategic oil and gas properties and internally generated cash.
The 1996 capital budget was increased to $100 million in August, after the
Texas Supreme Court denied Tennessee Gas' petition for rehearing of the Court's
April 1996 decision in the Tennessee Gas Contract litigation. The additional
funds were allocated principally for development drilling in the Rocky Mountains
and for property acquisitions.
As of December 31, 1996, the Company completed the arrangements for the
purchase of Medallion. The Medallion Acquisition was funded by a cash payment of
$194.1 million (reflecting the $209.4 million cash purchase price reduced at the
January 2, 1997 closing by $15.3 million principally to reflect free cash flow
from Medallion's operations subsequent to the July 1, 1996 effective date) and
the issuance of warrants to purchase 435,000 shares of Common Stock. See
"Business and Properties -- Recent Acquisitions -- Medallion Acquisition." The
Company financed the cash portion of the purchase price by using its available
cash, borrowings under its existing Credit Facility and borrowings under the new
Revolving Credit Agreement secured by the assets acquired in the Medallion
Acquisition. See "-- Debt Financing." The net proceeds from the Offerings will
be used to reduce the amounts outstanding under the Bank Credit Facilities.
Giving effect to the Medallion Acquisition, the Company made gross
estimated capital expenditures of approximately $285 million in 1996. Of that
total, $199 million represents the Medallion Acquisition and the remaining $86
million was for exploration and development drilling on the Company's other
properties and for oil and gas property acquisitions. For 1997, the Company has
set a capital budget of $160 million. Of that total, $70 million has been
allocated to development and exploitation drilling, $25 million for exploration
and $65 million for oil and gas property acquisitions, including reserves
acquired under the VPP program. The Company believes that internally generated
cash, sales of certain non-strategic assets and borrowings under the Bank Credit
Facilities will be sufficient to fund its 1997 capital budget.
Debt Financing
On January 25, 1996, the Company completed the sale of $150 million
principal amount of 11% Senior Notes due 2003. The net proceeds of approximately
$145 million (after deducting expenses of the offering which were deferred and
are being amortized over the term of the Senior Notes) were utilized to reduce
the outstanding indebtedness under existing bank credit facilities and to repay
a note sold to a third party. Also during 1996, the Company consolidated its
existing bank credit facilities into one Credit Facility as described below and
entered into an additional Revolving Credit Agreement to fund a portion of the
purchase price for the Medallion Acquisition as described below.
Credit Facility
At June 30, 1996, the Company maintained three separate bank credit
facilities to support its operations. The Master Note Facility was utilized
primarily to support the expansion of the Company's exploration and production
and natural gas transportation businesses. The Company's natural gas marketing
subsidiary had two credit facilities, the Receivable Facility and the VPP
Facility, which were used primarily for working capital purposes and to support
the acquisition of oil and gas properties through volumetric production
payments.
31
<PAGE> 32
In July 1996, the Receivable Facility was paid in full and terminated. On
September 25, 1996, the Company consolidated the Master Note Facility and the
VPP Facility to create one revolving credit facility (the "Credit Facility"),
which will mature on September 30, 2000. The Credit Facility is secured by the
same collateral that was pledged to secure the Master Note and VPP facilities.
The borrowing base under the Credit Facility is a function of the lender's
determination of the value of the Company's oil and gas reserves, and as of
October 31, 1996, was limited to $75 million under the terms of the Indenture
governing the Senior Notes. The Credit Facility bears interest at a spread over
the prime rate or LIBOR, determined each quarter based on the Company's
consolidated debt-to-EBITDA ratio. As of December 31, 1996, $0.1 million was
outstanding under the Credit Facility and simultaneously with the Medallion
Acquisition, the Company borrowed an additional $55.5 million to fund a portion
of the Medallion Acquisition purchase price.
Revolving Credit Agreement for Medallion Acquisition
Simultaneously with the consummation of the Medallion Acquisition, the
Company entered into a new Revolving Credit Agreement with a group of banks. Of
the Revolving Credit Agreement's $135 million initial borrowing base, $30
million is structured as a term loan with a maturity of March 31, 1997; the
remaining $105 million revolving loan matures on September 30, 2000.
The Company's obligations under the Revolving Credit Agreement are secured
by substantially all of the oil and gas assets of Medallion and a pledge of
Medallion's common stock. The Revolving Credit Agreement permits the Company to
borrow at interest rates based upon the banks' prime rate or LIBOR. The
applicable spread over the prime rate or LIBOR is determined each quarter based
on the Company's consolidated debt-to-EBITDA ratio. Simultaneously with the
Medallion Acquisition, the Company borrowed $105 million under the Revolving
Credit Agreement to fund a portion of the purchase price of the Medallion
Acquisition.
Impact of Recently Issued Accounting Standards
The Financial Accounting Standards Board issued Statement of Financial
Accounting Standards ("SFAS") No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of." SFAS No. 121 is
effective for financial statements for fiscal years beginning after December 15,
1995. Adoption of SFAS No. 121 had no impact on the financial position or
results of operations of the Company.
32
<PAGE> 33
BUSINESS AND PROPERTIES
GENERAL
KCS is an independent oil and gas company primarily engaged in the
acquisition, exploitation, development and, to a lesser extent, exploration of
domestic oil and gas properties, and in the production and marketing of oil and
gas. Through its experienced management and geological and engineering staff,
the Company has successfully acquired and increased the value of its properties
through drilling and other exploitation techniques and has substantially
increased its reserves, production and cash flow. Over the five-year period
ended December 31, 1995, KCS replaced 400% of production and increased proved
oil and gas reserves 395% to 186.1 Bcfe at December 31, 1995. During the same
period, the Company increased its oil and gas production 392% to 20.3 Bcfe,
representing a compound annual growth rate of 49%. In addition, the Company
increased EBITDA from $7.1 million in 1991 to $75.1 million in 1995.
The Company's operations to date have focused primarily on properties in
the onshore Gulf Coast and Rocky Mountain regions. KCS augments its working
interest ownership of properties with the VPP program to acquire oil and gas
from properties which to date have been located primarily in the offshore Gulf
Coast region and in the Niagaran Reef trend in Michigan. As of December 31, 1996
the Company completed the arrangements for the acquisition of InterCoast Oil and
Gas Company (formerly Medallion Production Company and renamed KCS Medallion
Resources, Inc.) and certain of its affiliates, the Company's largest
acquisition to date. The Medallion Acquisition expanded the Company's operations
to include a third core operating area, the Mid-Continent region, encompassing
west Texas, the Texas Panhandle, northwest Oklahoma and north Louisiana. At June
30, 1996, on a pro forma basis reflecting the Medallion Acquisition, proved oil
and gas reserves were 369.4 Bcfe (84% proved developed), approximately double
the Company's historical proved reserves at December 31, 1995, and represented a
PV-10 value of $408.3 million. On a pro forma basis, the Company holds working
interests in 3,011 producing wells, 38% of which it operates. Approximately 63%
of the Company's reserves on a pro forma basis are attributable to wells it
operates.
Historically, the Company's most significant field was the Bob West Field
in south Texas, which accounted for approximately 16% (8% on a pro forma basis)
of the Company's production during the nine months ended September 30, 1996.
Most of the Company's natural gas sold from the Bob West Field was covered by
the Tennessee Gas Contract, which had been the subject of several lawsuits. On
December 23, 1996, the Company and Tennessee Gas entered into a settlement
covering all claims and litigation between them related to the Tennessee Gas
Contract. As part of the settlement, the Tennessee Gas Contract was terminated
effective January 1, 1997, approximately two years prior to its expiration date.
The parties also agreed to the dismissal of the contract dispute that resulted
in a November 1996 jury award to Tennessee Gas of $143.2 million (including
punitive damages of approximately $114 million). The December 1996 settlement
did not affect the Company's successful conclusion of litigation earlier in the
year relating to the validity and pricing provisions of the Tennessee Gas
Contract and its recovery of the Tennessee Gas Receivable.
The Company also operates a natural gas transportation business and a
natural gas marketing and services business, which together recorded a $0.3
million operating loss during the nine months ended September 30, 1996. The
Company's natural gas transportation business consists of a 150-mile intrastate
pipeline system and related gathering lines located between Houston and Dallas,
Texas and 17 natural gas gathering systems (including the Texas system acquired
in the Medallion Acquisition) totaling more than 300 miles in Texas, Montana and
Louisiana. Through its natural gas marketing and services business, the Company
buys and resells natural gas directly to industrial and commercial end users and
also offers energy supply and transportation consulting services.
BUSINESS STRATEGY
The Company has grown through a balanced strategy of reserve acquisitions
and development and exploratory drilling. The Company plans to continue to
broaden its reserve base and increase production
33
<PAGE> 34
and cash flow through (i) the acquisition of attractively priced oil and gas
companies and producing properties that provide additional development or
exploratory potential, (ii) the exploitation and development of its existing
asset base, (iii) the operation and ownership of a majority working interest in
a significant number of its properties to allow the Company greater control over
future development, drilling, completing and lifting costs and marketing of
production, (iv) the acquisition of oil and gas reserves through the VPP
program, (v) the pursuit of a balanced exploration program that includes a
number of high-potential opportunities, and (vi) the extensive use of advanced
technologies, most notably 3-D seismic, computer-enhanced basin analysis,
reservoir simulation and specialized drilling applications and stimulation
techniques to better delineate and produce reserves.
To implement its strategy, the Company intends to take advantage of several
key strengths, including (i) an experienced and capable team of oil and gas
industry professionals with a significant financial stake in the success of the
Company, (ii) a significant inventory of attractive development and exploratory
drilling opportunities within its existing property base and undeveloped acreage
position, (iii) established relationships with proven industry partners that
provide opportunities to participate in diverse exploration prospects, (iv) an
efficient administrative and operating structure that emphasizes an
entrepreneurial and opportunistic approach, and (v) a strong financial focus
which manifests itself not only in innovative transactions, but also in asset
risk management.
RECENT ACQUISITIONS
Medallion Acquisition
As of December 31, 1996, the Company completed the arrangements for the
acquisition of all of the outstanding stock of InterCoast Oil and Gas Company
(formerly Medallion Production Company and renamed KCS Medallion Resources,
Inc.), GED Energy Services, Inc. and InterCoast Gas Services Company, (renamed
Medallion Gas Services, Inc.), indirect wholly-owned subsidiaries of
MidAmerican, for a total price of approximately $214.4 million, consisting of
$209.4 million in cash and warrants to purchase 435,000 shares of Common Stock
at an exercise price of $45.00 per share. The Medallion Acquisition was closed
on January 2, 1997, and the cash portion of the purchase price was reduced by
$15.3 million at closing principally to reflect free cash flow from Medallion's
operations subsequent to the July 1, 1996 effective date.
The information included in this Prospectus regarding Medallion has been
provided by Medallion. No assurance can be given by the Company as to the
accuracy or completeness of such information. Due diligence has been conducted
by the Company only on those properties and other assets of Medallion that the
Company believes have the most significant value. The Company received certain
representations, warranties and indemnification agreements from the sellers in
connection with the Medallion Acquisition. These representations, warranties and
indemnification agreements will survive the closing of the transaction for
specified periods. MidAmerican Capital Company, a direct wholly-owned subsidiary
of MidAmerican, has agreed to guaranty certain obligations of the sellers under
the agreements relating to the Medallion Acquisition, including the sellers'
indemnification agreements.
Medallion's principal oil and gas assets were estimated as of June 30, 1996
by an independent reserve engineer to be 202.1 Bcfe of proved oil and gas
reserves, consisting of 161.3 Bcf of natural gas (80% of total proved reserves)
and 6.8 MMbbls of oil and condensate. These reserves are located primarily in
the Mid-Continent region encompassing west Texas, the Texas panhandle, northwest
Oklahoma and north Louisiana. Proved developed reserves account for 88% of
Medallion's total proved reserves and the average reserve life at year-end 1995
was 8.0 years. Medallion owns interests in 2,061 gross (675 net) wells, and
approximately 68% of reserves are attributable to wells it operates. The
Medallion Acquisition more than doubles the Company's reserve base and adds
substantial management and technical expertise, particularly in the new
Mid-Continent core operating area. Descriptions of the principal producing
properties acquired are set forth under "Principal Working Interest Oil and Gas
Properties -- Medallion Acquisition Properties."
34
<PAGE> 35
Over the three and a half-year period ended June 30, 1996, and giving
effect to the acquisition of its Sawyer Canyon properties in April 1996,
Medallion replaced 251% of its production and increased reserves 148% through
property acquisitions, its EID program, and, to a lesser extent, exploratory
drilling, all of which the Company expects to continue. Since its acquisition by
MidAmerican in April 1992, Medallion has acquired 188.7 Bcfe of proved reserves
through 31 acquisitions at an average acquisition cost of $0.67 per Mcfe.
Medallion's EID program targets drilling prospects that enhance the
economic recovery of oil and gas in producing areas and horizons to a level
greater than that previously achieved by the owners of the prevailing leasehold
by increasing the density of wells that penetrate known reservoirs. Typically,
development of EID prospects requires that Medallion obtain some or all of the
rights to drill on acreage that is held by production, thus providing the
opportunity to drill without making significant capital expenditures for
undeveloped leasehold acreage. The EID program has been implemented by members
of Medallion's current management team (who are expected to continue with the
Company following the Medallion Acquisition) since 1985. During the three-year
period ended December 31, 1995, Medallion developed 53.7 Bcfe of proved reserves
at an average finding cost of $0.75 per Mcfe through its EID program by
successfully completing 52 of 87 prospects. At September 30, 1996, Medallion had
identified more than 170 potential EID locations in its core operating areas and
has 41 proved undeveloped locations on its acreage. In September 1996, average
daily production from the Medallion properties was 3,453 bbls of oil and
condensate and 63,834 Mcf of natural gas, equivalent to 84,552 Mcfe. Medallion
also operates a 37-mile Texas gathering system and has natural gas marketing
operations based in Tulsa, Oklahoma, which had average sales volumes of 210,000
Mcf per day in September 1996.
Medallion has a demonstrated track record of consistent growth in reserves,
production, revenues and cash flow every year since its inception in 1992. It
utilizes a balanced approach to drilling and reserve acquisitions and has
assembled a high quality, entrepreneurial management and technical team
consisting of 72 employees at December 31, 1996, located principally in its
Tulsa, Oklahoma headquarters. KCS anticipates that substantially all of these
employees will remain with Medallion following the acquisition and that
Medallion will continue to pursue its current operational strategies.
Rocky Mountain Acquisition
In November 1995, the Company acquired substantially all of the oil and gas
assets of Natural Gas Processing Company for a purchase price of approximately
$33 million. The Company acquired interests in 531 gross (301 net) wells located
in over 30 different fields, principally in six producing basins located in
Wyoming, Colorado, Montana and North Dakota. Proved reserves attributable to the
acquired properties were estimated by independent reserve engineers at September
30, 1995 to be 66.7 Bcfe, consisting of 40.9 Bcf of natural gas and 4.3 MMbbls
of oil and representing an average acquisition cost of $0.49 per Mcfe. Since the
acquisition, the Company has undertaken an aggressive field development and
acreage acquisition program in the Rocky Mountain region which has resulted in
several recent drilling successes and prospective drilling opportunities,
primarily in the Manderson Field in north central Wyoming. As of June 30, 1996,
the Company's well count in the Rocky Mountain region had increased to 587
wells, of which 374 (or approximately 64%) are operated by the Company.
Approximately half of the natural gas production from the acquired properties is
subject to multi-year contracts with local utility companies at prices that
ranged from $1.70 to $2.00 per Mcf.
In addition, the Rocky Mountain Acquisition included approximately 197,000
gross (160,000 net) acres of largely underdeveloped properties. As the result of
additional property acquisitions, the Company has increased the lease holdings
in this area to approximately 240,000 gross (196,700 net) developed and
undeveloped acres as of September 30, 1996. The Company also acquired a
significant inventory of oil and gas equipment and supplies, vehicles, and
buildings as well as natural gas gathering systems consisting of approximately
200 miles of pipeline. Following the acquisition, the Company hired highly
experienced and technically competent exploration and operational personnel with
experience in the Rocky Mountain region who were formerly employed by the
seller, and following additional hiring, the Company's staff in the region
totaled 55 persons as of December 31, 1996.
35
<PAGE> 36
Michigan Acquisition
In December 1995, the Company acquired 24.6 Bcfe of proved reserves in the
northern and southern Niagaran Reef trends in Michigan for $31 million,
including a volumetric production payment covering certain reserves, escalating
working interests in related properties and participation rights and an
overriding royalty interest in an exploration program, representing an average
acquisition cost of $1.26 per Mcfe. The VPP provides for the delivery to the
Company of certain oil and gas reserves totaling 20.3 Bcfe scheduled to be
delivered from December 1995 through January 2006, without any burden of
development and lease operating expenses. The VPP reserves were estimated as of
September 30, 1995 to consist of 13.7 Bcf of natural gas and 1.1 MMbbls of oil.
Based on independent reserve reports as of September 30, 1995, the working
interests in related properties that were acquired in the Michigan Acquisition
separate from the VPP added 3.1 Bcf of natural gas and 219 Mbbls of oil to the
Company's proved reserves.
OIL AND GAS PRODUCTION AND EXPLORATION
All of the Company's production and exploration activities are located
within the United States.
Development and Production Activities
During the three-year period ended December 31, 1995, the Company
participated in the drilling of 61 development wells with a 98% success rate.
The majority of this development was in the Bob West Field, where the Company
drilled 38 wells and completed 38. During the first nine months of 1996, the
Company substantially increased its level of development drilling in other areas
and drilled 27 of 29 wells and completed 24 of 27 wells in areas other than the
Bob West Field. The Company's activities are now focused on the Manderson Field
in the Big Horn Basin of Wyoming, the Sweet Grass Arch area in Montana, the
Langham Creek Area and Glasscock Ranch Field in Texas and the Laurel Ridge Field
and the Tensas Parish Area in Louisiana. For 1996, the Company established an
initial development drilling budget of $22 million, which was subsequently
increased to $40 million in August 1996 as a result of the favorable decision of
the Texas Supreme Court on the Tennessee Gas Contract. For details on major
development activities on a field-by-field basis, see "-- Principal Working
Interest Oil and Gas Properties."
The Company has currently identified over 450 development drilling and
recompletion locations and 170 EID locations, representing approximately a
four-year inventory, and has initially budgeted $70 million for development
activities in 1997. The Company plans to drill, recomplete and workover as many
as 150 wells in 1997 and focus its development drilling program primarily on the
fields in the Rocky Mountain and onshore Gulf Coast regions discussed above and,
with the consummation of the Medallion Acquisition, on the Sawyer Canyon Field
and several of Medallion's prospects in the west Texas, ArkLaTex, Anadarko and
Arkoma areas located in the Mid-Continent region. See "Principal Working
Interest Oil and Gas Properties."
Exploration Activities
During the three-year period ended December 31, 1995, the Company
participated in the drilling of 58 exploratory wells with a 50% success rate.
Discoveries included wells in the Bob West Field, Langham Creek Area and Laurel
Ridge Field. During the first nine months of 1996, the Company participated in
the drilling of 11 exploratory wells and completed five wells, two of which it
operates. Of the 1996 exploration budget of $15 million, $12.4 million was spent
during the nine months ended September 30, 1996, which included expenditures for
lease acquisitions, seismic surveys and exploratory drilling. Discoveries in
1996 included the St. Jo prospect (now designated as the Aubrey and Wilsonia
Fields) located in Tensas Parish, Louisiana, where seven successful wells were
drilled and completed as of September 30, 1996.
The Company's policy is to commit no more than 25% of its operating cash
flow to exploration activities and generally no more than $750,000 for any
single well. The Company has established an initial budget of $25 million for
exploration in 1997 and intends to participate in drilling a wide variety of
36
<PAGE> 37
prospects, including both low-risk and high-risk, high-potential projects in
order to maintain a balanced program with the potential for significant reserve
additions.
During 1997, the Company plans to participate in the drilling of up to 50
exploration prospects and to continue 3-D and 2-D seismic data acquisition and
analysis. Exploration activities will focus primarily on properties located in
the onshore Gulf Coast regions of Texas and Louisiana and in the Rocky
Mountains. As of December 31, 1996, the Company had finalized negotiations on
two exploratory projects in the Rocky Mountain region and is negotiating a
third. The two exploratory projects on which negotiations are completed include
(i) three Lodgepole prospects, in which the Company owns a 30% working interest,
located near Conoco's Eland Field in Stark County, North Dakota (one of which
was drilled in 1996 and was non-productive) and (ii) a Wind River Basin project,
in which the Company has a 95% working interest, on 7,500 gross acres in central
Wyoming that targets the Lance, Shannon, Mesa Verde, Frontier and Muddy sand
formations. The Lodgepole prospects are based on a 109-square mile 3-D seismic
shoot covering approximately 68,530 gross (16,653 net) acres. The Company is
currently negotiating to acquire a 50% working interest in a third exploration
project on a 12,000 gross-acre Tyler sand prospect in central Montana. The
Company also intends to further analyze the undeveloped acreage it acquired in
the Medallion Acquisition for possible exploration prospects and continue its
participation in exploration projects in Michigan, where a 3-D seismic program
is currently under way.
Sale of Certain Properties
In early 1996, the Company sold several non-strategic properties located in
south Texas, including its interest in the San Salvador, Bloomberg and Birdie
Fields, for a total sale price of $16.4 million. As of December 31, 1995, the
properties had reserves attributable to them by an independent reserve engineer
of 9.4 Bcf of natural gas and 63,000 bbls of oil. Prior to their sale, the
properties contributed 232 Mcf of natural gas and 2,900 bbls of oil to the
Company's production in 1996.
37
<PAGE> 38
PRINCIPAL WORKING INTEREST OIL AND GAS PROPERTIES
Approximately 85% of the Company's PV-10 of proved reserves and 92% of its
total proved oil and gas reserves, after giving effect to the Medallion
Acquisition, are attributable to properties in which it has a working interest.
The Company is the operator of 1,139 wells, representing 64% of the PV-10 of
proved reserves attributable to its working interests (54% of PV-10 for all
proved reserves). The following table sets forth data as of June 30, 1996 (after
giving effect to the Medallion Acquisition and the termination of the Tennessee
Gas Contract effective on January 1, 1997) regarding the number of gross
producing wells, the estimated quantities of proved oil and gas reserves and the
PV-10 attributable to the Company's principal properties in which it owns
working interests.
The following table does not include reserves or PV-10 values attributable
to the Company's VPP program. See "-- Volumetric Production Payment Program and
Underlying Principal Properties."
<TABLE>
<CAPTION>
ESTIMATED PROVED RESERVES
GROSS ----------------------------------------------------
PRODUCING OIL NATURAL GAS TOTAL % OF PV-10
PROPERTY/AREA WELLS (MBBLS) (MMCF) (MMCFE) TOTAL ($000S)
- -------------------------------------- ------- ----------- ------- ----- --------
<S> <C> <C> <C> <C> <C> <C>
Onshore Gulf Coast:
Bob West Field............. 50 -- 24,844 24,844 7% $ 36,108
Langham Creek Area......... 11 182 11,933 13,028 4 16,266
Laurel Ridge Field......... 2 232 3,629 5,019 1 11,342
Glasscock Ranch Field...... 11 84 3,117 3,622 1 2,557
Tensas Parish Area......... 3 105 1,781 2,409 1 3,224
Others..................... 256 1,701 12,309 22,512 7 18,325
----- ------ ------- ------- --- --------
Subtotal........... 333 2,304 57,613 71,434 21 87,822
Rocky Mountain:
Big Horn Basin
Manderson Field......... 17 2,134 10,560 23,364 7 18,748
Others.................. 207 1,475 4,896 13,748 4 11,008
San Juan Basin............. 49 -- 11,345 11,345 3 4,788
Wind River Basin........... 23 82 4,435 4,926 2 2,227
Sweet Grass Arch........... 208 567 1,176 4,577 1 4,486
Green River Basin.......... 82 34 3,680 3,882 1 2,047
Others..................... 1 15 6 96 -- 77
----- ------ ------- ------- --- --------
Subtotal........... 587 4,307 36,098 61,938 18 43,381
Michigan Niagaran Reef
Trend...................... 30 285 3,039 4,748 1 4,974
Medallion Acquisition:
Sawyer Canyon Field........ 345 69 54,646 55,062 16 54,659
ArkLaTex Area.............. 74 90 21,641 22,180 7 29,951
Anadarko Basin............. 216 177 19,699 20,762 6 20,272
Rocky Mountain............. 842 1,118 13,787 20,497 6 11,290
Gulf Coast and South
Texas................... 95 854 11,176 16,299 5 25,162
Offshore Gulf of Mexico.... 76 442 11,428 14,081 4 21,113
California................. 36 1,661 1,985 11,949 4 7,975
Others..................... 377 2,386 26,966 41,283 12 41,017
----- ------ ------- ------- --- --------
Subtotal........... 2,061 6,797 161,328 202,113 60 211,439
----- ------ ------- ------- --- --------
Total.............. 3,011 13,693 258,078 340,233 100% $347,616
===== ====== ======= ======= === ========
</TABLE>
Set forth below are descriptions of certain of the Company's significant
oil and gas producing properties and those targeted for significant drilling
activity in 1997.
38
<PAGE> 39
Onshore Gulf Coast Properties
Bob West Field. The Company has interests in approximately 863 gross (599
net) acres in this field located in Zapata and Starr Counties, Texas. The field
produces natural gas from a series of 20 different Upper Wilcox sands with
formation depths ranging from 9,500 to 13,500 feet that require stimulation by
hydraulic fracturing to effectively recover the reserves. Because the majority
of this field is situated under Lake Falcon on the Rio Grande River, most wells
must be drilled directionally under the lake from common lakeshore drill sites.
The Company owns interests in two principal areas in the Bob West Field. During
September 1996, the average combined rate of production attributable to the
Company's net revenue interest in these areas was approximately 12,000 Mcf of
natural gas per day. Prior to the termination of the Tennessee Gas Contract
effective January 1, 1997, substantially all of this natural gas production was
covered by the contract. See "-- Legal Proceedings -- Tennessee Gas Litigation,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources" and Note 7 to the Consolidated
Financial Statements.
With the termination of the Tennessee Gas Contract, the Company has the
equivalent of a 12.5% working interest in all production from the Guerra "A" and
Guerra "B" units. As of September 30, 1996, these units contained 32 producing
wells. The Company has the right to take all its production in kind, and during
September 1996, the average combined rate of production attributable to the
Company's non-operated net revenue interest was approximately 6,500 Mcf of
natural gas per day. One well is currently drilling and one has been permitted
on the Guerra "A" and Guerra "B" units.
The Company also owns a 100% working interest in and operates 511 acres
referred to as the Falcon/Bob West Field. During September 1996, the average
combined rate of production attributable to the Company's net revenue interest
was approximately 5,500 Mcf of natural gas per day. Substantially all of this
acreage was covered by the Tennessee Gas Contract and contains 18 producing
natural gas wells.
In September 1996, the Company began an extensive workover and recompletion
program on the acreage it operates. The Company is utilizing state-of-the-art
well log analysis, performance histories and bottom hole pressure analysis in an
effort to mitigate declines in gas production.
Langham Creek Area. This area is comprised of the Cypress, Cypress Deep and
Langham Creek Fields in western Harris County, Texas, where the Company has
non-operated interests in 7,349 gross (3,375 net) acres. Multiple horizons in
this area produce oil and gas from Eocene age sandstones in the Yegua formation
from 6,000 to 7,500 feet and in the Wilcox formation from 9,000 to 13,000 feet.
The Company owns working interests varying from 28% to 65% in 13 wells in
this area, representing an average net revenue interest of approximately 39%.
During September 1996, the nine producing wells in the Wilcox zone had an
average combined rate of production attributable to the Company's interest of
approximately 7,300 Mcf of natural gas and 82 bbls of oil per day. The
geological and geophysical evidence indicates the potential for as many as six
to nine additional drilling locations, with the upper Wilcox sands as the
primary target. The Company plans to continue active development in the area and
plans to drill as many as three additional wells in 1997.
Laurel Ridge Field. The Company is the operator of this field located in
Iberville Parish, Louisiana and has a 26% net revenue interest in 3,773 gross
(1,221 net) acres around two discovery wells. The #1 Claiborne Plantation was
completed in August 1995 in the Cibicides hazzardi (Frio) sand and the second
discovery, the #2 Claiborne Plantation, was completed in December 1995 in the
shallower Miogyp (Frio) formation. Based on the results of the first two
discovery wells and 2-D seismic surveys, the Company drilled two additional
step-out wells in July and October 1996 which were temporarily abandoned. The
Company has deferred future development of the subject Frio formation until the
completion of a 3-D seismic survey. A 3-D seismic program is scheduled to
commence in the first quarter of 1997 to identify additional locations and to
confirm the possible utilization of the wellbores of the two temporarily
abandoned wells for potential side-track completions. During September 1996, the
average
39
<PAGE> 40
production attributable to the Company's interest was 2,100 Mcf of natural gas
and 210 bbls of oil per day.
Glasscock Ranch Field. This field is located in Colorado County, Texas. The
Company and its partners leased approximately 2,800 acres and in 1994 drilled
and completed the #5 Glasscock well as a natural gas well in the upper portion
of the lower Wilcox sand section, a new reservoir for the field. The Company has
recently increased its working interest to approximately 85% and plans to
implement a development drilling program for 1997 which could include as many as
three additional wells.
Tensas Parish Area. The Company currently has leases or options covering
32,000 acres in this area and in mid-1996 initiated a major exploration and
development drilling program in its St. Jo (now referred to as the Aubrey and
Wilsonia Fields), Barfield and Chicago Mills prospects. The Company currently
owns a 100% working interest in these three prospects. Of the eight wells
drilled to date in the Aubrey and Wilsonia Fields, six were completed, one is in
the completion process and one was a dry hole. Five of the completed wells
targeted the lower Tuscaloosa at a depth of 8,300 feet and one well targeted the
Wilcox at a depth of 3,200 feet. The Company plans to drill as many as four
additional wells in these fields during the next six months. During September
1996, the average production attributable to the Company's interest in the
Aubrey and Wilsonia Fields was 1,600 Mcf of natural gas and 140 bbls of oil per
day. The Company expects this level of production to increase as a result of
further stimulation and operational enhancements commenced in October 1996.
The Company has 2,330 acres under lease in its Barfield prospect and has
completed a six square mile 3-D seismic survey on the prospect. Three recent
exploration wells were dry, but provided the Company with additional data on the
geology and geophysics of the prospect. A 12,500 foot well to test the James
Lime/Pettet Limestone reef is in the planning stage.
The Company has taken options on or leased approximately 26,700 acres in
its Chicago Mills Prospect. A 26-square mile 3-D seismic survey has been
completed on a portion of the optioned acreage and resulted in the leasing of
8,800 acres. The Company has staked five locations, one of which was abandoned,
to test seven different prospects delineated by the seismic data. The remainder
of the optioned acreage is scheduled for evaluation using 3-D seismic covering a
29-square mile area beginning in early 1997.
Rocky Mountain Properties
Big Horn Basin. This basin is located in north central Wyoming encompassing
parts of Washakie, Big Horn, Hot Springs, and Park counties. The Company
currently has lease holdings on 101,487 gross (86,264 net) acres. The Company
operates 106 wells and has additional interests in 124 non-operated wells in a
total of 18 fields. The major producing properties in the basin are the
Manderson Field that produces oil and gas at depths from 4,500 to 8,000 feet,
the Golden Eagle Field which produces oil and gas at depths from 3,200 to 10,000
feet, the 14-Mile Field that produces oil and gas at depths from 6,000 to 11,000
feet, the Grass Creek Field that produces oil and gas at depths from 2,400 to
7,000 feet and the Sellers Draw Field that produces natural gas at depths from
15,000 to 20,000 feet.
The Manderson Field is located on a northwest-southeast trending anticlinal
nose in the Big Horn Basin. The Company has expanded its holdings in the field
from approximately 7,500 acres obtained in the Rocky Mountain Acquisition to
more than 22,000 acres and owns a 100% working interest. The field has multiple
reservoirs that are producing or potentially productive: the Phosphoria
Dolomite, the Lakota sands, the Dakota sands, the Muddy sands, the Octh Louie
sands, and the Frontier sands.
The Manderson Field was discovered in 1951 and 16 wells targeting the
Phosphoria Dolomite were drilled primarily using 640-acre spacing from 1951 to
1954. Another well drilled in 1990 tested gas in the Phosphoria but was
recompleted to the Muddy sands as a natural gas producer due to the high
percentage of hydrogen sulphide present in the Phosphoria formation. To date,
the field has produced 8.2 Bcf of natural gas and more than 2.2 MMbbls of oil
from the Phosphoria, 32.4 Bcf of natural gas from the Muddy sands and lesser
amounts from the Frontier and Octh Louie sands.
40
<PAGE> 41
The Company is currently starting up an injection system and constructing
processing facilities to handle the sour natural gas produced from the
Phosphoria formation to allow for full field development. Since the drilling and
completion of its first well in April 1996, the Company has drilled and
completed 16 development wells, recompleted one previously existing well, is
currently completing seven wells and is drilling two wells in the Phosphoria
Dolomite, the deepest known productive reservoir in the Manderson Field. The
completed wells, in which the Company owns an 81% net revenue interest, have
tested at rates ranging from 200 to 1,900 bbls of oil per day and from 450 to
4,000 Mcf of natural gas per day.
Daily production in the Manderson Field has been constrained due to
limitations imposed by the State of Wyoming and the federal government on the
amount of sour gas that can be flared. In late December, the Company began
start-up of an injection well and associated compression facility. Completion of
the injection system should enable the Company to inject 8,000 Mcf of sour gas
per day and allow oil production to increase to approximately 5,000 bbls per
day. The sour gas will be injected into the Phosphoria reservoir for pressure
maintenance. Currently, six of the completed wells have been tied into the
injection system and are on production.
An amine treatment plant designed to treat the sour gas to marketable
specifications is scheduled for completion late in the first quarter of 1997.
Completion of the treatment facilities will allow the treated natural gas to be
marketed with the sour inert gas being reinjected into a disposal well. The
treatment facilities, together with the gas injection system, should provide for
sufficient gas-handling capacities for 16,000 Mcf of natural gas per day and
allow for the production of approximately 10,000 bbls of oil per day. There can
be no assurance that the Company will be able to produce oil and gas at rates
sufficient to fully utilize such capacities.
The Company drilled a total of 23 wells targeting the Phosphoria and two
other wells targeting shallower zones during 1996. It currently has three
drilling rigs active. Log data and tests from the new wells drilled to date have
suggested potential pays in the Lakota and the Dakota sands for oil and/or gas,
the Muddy sands for gas, the Octh Louie sands for oil, and the Frontier sands
for oil and/or gas. In 1997, the Company plans to drill an additional 27
Phosphoria wells and at least ten additional wells targeting the shallower
reservoirs. Drilling results to date, coupled with the acquisition of additional
seismic data indicate that the field may have significant prospective potential.
During September 1996, the average production attributable to the Company's
interest in the Manderson Field was 1,600 Mcf of natural gas and 790 bbls of oil
per day.
Sweet Grass Arch. The Company has an interest in 79,539 gross (57,904 net)
acres in this major producing area located in Toole County, Montana. The Company
currently operates 202 wells and has interests in six non-operated wells in the
area. The most important oil producing property in the area is the Homestake
Field, where the Company currently operates 67 wells. The Homestake Field
produces from the Sunburst sand at depths ranging from 1,400 to 1,700 feet.
Discovered in 1922, the field was actively developed during the 1936-1941 period
and again in the mid-1960s. During that latter period, a waterflood project was
initiated with little success due primarily to the lack of wellbore integrity.
During the late 1980s, two new wells were drilled in an attempt to revive the
field again with little success because of poor completion techniques. The
Company has begun an active development program designed to improve wellbore
integrity, utilize state-of-the-art completion techniques and redesign the
secondary recovery project. The Company initiated the program in September 1996
and has drilled and completed 16 wells. Eight of the completed wells have been
tied into facilities and together are currently producing in excess of 500 bbls
of oil per day and are still unloading after stimulation. Seven wells are
waiting for weather to allow completion of a pipeline connection and power line
installations prior to being put on production. Two additional wells are
currently being drilled to depths of 700 feet. The recent drilling activity is
believed to have substantially increased the productive area of the field. The
Company plans to drill an additional 15 wells in the Homestake Field in 1997.
41
<PAGE> 42
Medallion Acquisition Properties
Sawyer Canyon Field. Medallion's holdings in the Sawyer Canyon Field,
located in Sutton County, Texas, represented 16% of the Company's proved
reserves as of June 30, 1996 on a pro forma basis. Medallion purchased these
properties in April 1996 from Enron Oil & Gas Company. Medallion owns interests
in 345 gross (314 net) wells, of which it operates 322 gross (293 net) wells.
Medallion's average working interest in this field is 91%, and its leasehold
position consists of approximately 34,887 gross (34,053 net) acres. During
September 1996, the average combined rate of production attributable to its net
revenue interest was approximately 18,300 Mcf of natural gas per day.
The main producing formation in the Sawyer Canyon Field is the Canyon
sandstone at a depth of approximately 5,500 feet. Natural gas in the Canyon
formation is stratigraphically trapped in lenticular sandstone reservoirs. A
typical Sawyer Canyon Field well encounters multiple productive reservoirs
within the 800 to 1,400 foot thickness of the Canyon formation. These Canyon
reservoirs tend to be discontinuous and generally exhibit lower porosity and
permeability, characteristics which reduce the area that can be effectively
drained by a single well to units as small as 40 acres.
Medallion's 55.1 Bcfe of proved reserves attributable to the Sawyer Canyon
Field are 97% proved developed. The Company currently plans to drill up to seven
additional locations to exploit the remaining proved undeveloped reserves. The
Company also believes that additional proved reserves may ultimately be
attributed to many of the 30 or more 40-acre drilling locations remaining on the
property. The Company has also identified several recompletion projects in
existing wellbores into Canyon sand reservoirs not currently producing. In
addition to exploiting these Canyon sand development opportunities, the Company
currently intends to evaluate portions of the Sawyer Canyon Field for potential
in the shallower Wolfcamp and deeper Strawn formations which have been found to
be productive in the area.
ArkLaTex Area. Medallion's reserve holdings in the ArkLaTex Area,
representing approximately 7% of the Company's total proved reserves as of June
30, 1996 on a pro forma basis, are located primarily in Bossier, Claiborne,
Lincoln, and Union Parishes in north Louisiana. Medallion owns an interest in 74
gross (38 net) wells of which 42 gross (36 net) wells are operated by the
Company. Medallion's average working interest in its ArkLaTex Area operated
wells is approximately 86%. Average daily production from the ArkLaTex Area, net
to Medallion's interest, was approximately 8,100 Mcf of natural gas and 56 bbls
of oil during September 1996. Production in the ArkLaTex Area is primarily from
the Hosston, Cotton Valley and Haynesville formations of Cretaceous and Jurassic
age at depths of 5,500 to 10,000 feet. These formations are lower permeability
sandstones which were developed on 640-acre spacing and require EID and advanced
fracture stimulations to drain the reserves in place adequately. Medallion
drilled four wells and spudded four additional wells in the ArkLaTex Area in
1996.
Medallion's largest concentration of reserves in the ArkLaTex Area is in
the Elm Grove Field, Bossier Parish, Louisiana. At June 30, 1996, net proved
reserves were 19.1 Bcfe, of which 94% was proved developed. Production from the
Elm Grove Field is primarily natural gas from the Hosston and Cotton Valley
formations at depths of 7,000 to 9,600 feet. Medallion owns an interest in 42
gross (27 net) wells, of which 29 gross (27 net) wells are operated by
Medallion. Medallion's operated leasehold position consists of approximately
5,760 gross (5,649 net) acres. Average daily production from the Elm Grove
Field, net to Medallion's interest, was approximately 6,000 Mcf of natural gas
and 33 bbls of oil during September 1996.
Since Medallion acquired its first interest in the Elm Grove Field in 1994,
it has drilled 11 productive EID wells, recompleted several of the existing
wells to access behind pipe reserves and discovered a deeper productive zone not
previously produced in the field. Average gross natural gas production from the
field reached a rate of 13,200 Mcf per day at the beginning of 1996, up from an
average daily production level of 2,000 Mcf per day when Medallion assumed
operations in August 1994. Medallion has identified several behind-pipe zones
and three to five additional EID well locations.
Anadarko Basin Area. Medallion's Anadarko Basin properties are located in
northwest Oklahoma and the Texas panhandle. Medallion owns an interest in 216
gross (83 net) wells, of which it operates
42
<PAGE> 43
155 gross (60 net) wells. Average daily production from the area, net to
Medallion's interest, was approximately 10,300 Mcf of natural gas and 70 bbls of
oil during September 1996. Total net proved reserves, as of June 30, 1996, were
20.8 Bcfe with 98% categorized as proved developed.
The majority of the Medallion's properties in this area are located on the
Northern Shelf and predominantly produce natural gas from various formations of
Pennsylvanian and Pre-Pennsylvanian age at depths of 7,000 to 12,000 feet.
Medallion's Mills Ranch Field, operated by Chevron, is in the deeper part of the
basin with production from depths of 10,000 to 20,000 feet. Pre-Pennsylvanian
reservoirs include the Mississippi, Chester and Hunton formations and are
typically fractured carbonates. Pennsylvanian reservoirs include the Redfork,
Atoka and Morrow sandstones.
During the four-year period ended December 31, 1995, Medallion participated
in the drilling of 44 gross (37 net) EID wells in the Anadarko Basin Area.
Medallion drilled eight wells in this area in 1996. The Company plans to
continue to exploit areas of the Anadarko Basin that require EID wells for
adequate reserve drainage and intends to drill 16 locations in this area during
1997.
VOLUMETRIC PRODUCTION PAYMENT PROGRAM AND UNDERLYING PRINCIPAL PROPERTIES
The Company augments its working interest ownership of properties with a
volumetric production payment ("VPP") program, a method of acquiring oil and gas
reserves scheduled to be delivered in the future at a discount to the current
market price in exchange for an up-front cash payment. A volumetric production
payment is comparable to a term royalty interest in oil and gas properties and
entitles the Company to a priority right to a specified volume of oil and gas
reserves scheduled to be produced and delivered over a stated time period.
Although specific terms of the Company's volumetric production payments vary,
the Company is generally entitled to receive delivery of its scheduled oil and
gas volumes at agreed delivery points, free of drilling and lease operating
costs and, in certain cases, free of state severance taxes. The Company is not
the operator of any of the properties underlying its volumetric production
payments, and it does not bear any development or lease operating expenses.
After delivery of the oil and gas volumes, the Company arranges for further
downstream transportation and sells such volumes to available markets. The
Company believes that its VPP program diversifies its reserve base and achieves
attractive rates of return while minimizing the Company's exposure to certain
development, operating and reserve volume risks. Typically, the estimated proved
reserves of the properties underlying a volumetric production payment are
substantially greater than the specified reserve volumes required to be
delivered pursuant to the production payment.
Through June 30, 1996, the Company had invested $66.2 million under this
program, acquiring proved reserves of 38,841 MMcf of natural gas and 1,103 Mbbl
of oil, representing an average acquisition cost of $1.46 per Mcfe, without the
burden of development and lease operating expenses. As of June 30, 1996, the
Company had recovered $36.8 million from the sale of oil and gas received under
its VPP program. The VPP program accounted for approximately $60.6 million (15%)
of the Company's PV-10 of proved reserves, and 29,210 MMcfe (8%) of its total
proved oil and gas reserves as of June 30, 1996, after giving effect to the
Medallion Acquisition.
43
<PAGE> 44
The following table shows, as of June 30, 1996, the oil and gas deliveries
to the Company scheduled to be made pursuant to its VPP program over the period
from July 1, 1996 through December 31, 2006. Total future net cash flow to the
Company from the volumetric production payment deliveries scheduled below is
estimated to be $74.9 million, based on spot market prices in effect at June 30,
1996 ($2.38 per MMBtu and $18.83 per bbl, before adjustments for appropriate
basis differentials and Btu content).
<TABLE>
<CAPTION>
CUMULATIVE
NATURAL GAS OIL TOTAL TOTAL
PERIOD FROM TO (MMCF) (MBBLS) (MMCFE) (MMCFE)
- ----------------- -------------------------------- ----------- ------- ------- ----------
<S> <C> <C> <C> <C> <C>
July 1, 1996 September 30, 1996.............. 3,102 51 3,405 3,405
October 1, 1996 December 31, 1996............... 2,752 50 3,052 6,457
January 1, 1997 December 31, 1997............... 7,640 205 8,870 15,327
January 1, 1998 December 31, 1998............... 3,907 162 4,876 20,203
January 1, 1999 December 31, 1999............... 1,588 117 2,288 22,491
January 1, 2000 December 31, 2000............... 1,263 86 1,781 24,272
January 1, 2001 December 31, 2006............... 3,538 233 4,938 29,210
</TABLE>
The properties underlying the VPP program are principally located in two
major regions, the offshore Gulf Coast and the northern and southern Niagaran
Reef trend in Michigan.
Offshore Gulf Coast Properties
The Company's offshore Gulf Coast properties are located in six blocks off
the coast of Louisiana and four blocks off the coast of Alabama. The Company's
interests in the Louisiana blocks were all acquired through volumetric
production payment contracts with Hall-Houston Oil Company ("HHOC"), which is
the operator. The Louisiana blocks contain nine wells drilled during 1994, 1995,
and the first half of 1996 that are at depths ranging from 1,700 to 8,000 feet
in the shallow waters of the Gulf of Mexico. Production attributable to HHOC's
working interest during the month of September 1996 averaged 26,776 Mcf per day,
of which an average of 21,956 Mcf per day was delivered to the Company under the
VPP program. Proved reserves attributable to HHOC's interest, which support the
volumetric production payment, were estimated by an independent reserve engineer
to be 16,398 MMcf as of June 30, 1996. Pursuant to the HHOC volumetric
production payment, the Company received deliveries totaling 6,911 MMcf during
1995 and 5,104 MMcf during the six months ended June 30, 1996, was scheduled to
receive deliveries totaling 4,188 MMcf during the balance of 1996, and is
scheduled to receive deliveries totaling 4,788 MMcf in 1997, and 1,684 MMcf in
1998.
The Company's interests in the four offshore Alabama blocks were acquired
through two volumetric production payment agreements with The Offshore Group,
which operates five wells located on these properties. The Company received
deliveries of 260 MMcf in 1994, 552 MMcf in 1995, was scheduled to receive
deliveries totaling 1,287 MMcf during 1996 and is scheduled to receive
deliveries totaling 1,287 MMcf in 1997.
In addition, the Company is scheduled to receive volumes totaling 782 MMcfe
during the period from 1996 to 1998 from several smaller volumetric production
payments covering onshore Gulf Coast and Appalachian properties.
Niagaran Reef Trend Properties in Michigan
The Company's northern and southern Niagaran Reef trend properties, located
in Michigan, were acquired in December 1995. The VPP program reserves are
expected to be produced largely from an existing group of 89 wells located in 49
fields, primarily operated by a subsidiary of Hawkins Oil and Gas, Inc.
("Hawkins"). Additional reserves available to support the production payment may
be derived from a series of recompletions scheduled during 1996 and 1997 and
from certain reserves to be developed by Hawkins in an area of mutual interest
covering the Niagaran Reef trend pursuant to an exploration program with a third
party. The Niagaran Reef reservoirs are typically found at depths between 4,000
and 6,500 feet. Production rates from the property interests supporting the
production payment during
44
<PAGE> 45
September 1996 averaged 5,775 Mcf and 525 bbls per day. The Company estimated at
June 30, 1996 that 17,298 MMcf and 1,101 Mbbls were attributable to Hawkins'
interest in these properties to support the production payment, with
approximately 80% of the reserves attributable to 17 wells. Of the remaining
12,177 MMcf and 0.9 MMbbls to be delivered under the volumetric production
payment, the Company was scheduled to receive 1,117 MMcf and 100 Mbbls during
the last half of 1996, 2,476 MMcf and 205 Mbbls in 1997, with the balance to be
delivered between 1998 and 2006.
Recent Volumetric Production Payment Program Activities
Subsequent to June 30, 1996, KCS entered into four volumetric production
payments to acquire 11,886 MMcf of natural gas and 579 Mbbls of oil for $23.7
million, $8.9 million of which has not yet been paid and is expected to be
funded in the first half of 1997.
OIL AND GAS RESERVES
All information in this Prospectus relating to estimates of the Company's
proved reserves not associated with the VPP program or its working interest
reserves (approximately 1% of total proved reserves) in the Niagaran Reef trend
in Michigan is derived from reports prepared for the Company by Ryder Scott
Company (covering the Medallion Acquisition properties), H.J. Gruy and
Associates, Inc. (the Rocky Mountain properties) and R.A. Lenser and Associates,
Inc. (the onshore Gulf Coast properties), each in accordance with the rules and
regulations of the SEC. These independent reserve engineers' estimates were
based upon a review of production histories and other geologic, economic,
ownership and engineering data provided by the Company or third party operators.
Although reserve engineers' reports with respect to reserves underlying the
Company's VPP program are utilized by the Company to support its own analysis of
such reserves, the proved reserves, related future net revenues and PV-10 that
the Company reports with respect to volumetric production payments are taken
directly from the amounts contracted for pursuant to the agreements relating to
volumetric production payment (which amounts are less than the net interest
production reflected in the independent reserve engineers' reports).
The following table sets forth as of June 30, 1996, both historical and pro
forma (giving effect to the Medallion Acquisition) summary information with
respect to (i) the estimates made by the reserve engineers of the Company's
proved oil and gas reserves attributable to working interests and (ii) the
reserve amounts contracted for pursuant to the agreements relating to the
volumetric production payments. In addition, the table sets forth estimates of
future net revenues from these proved reserves and the present value thereof and
reflects the termination of the Tennessee Gas Contract effective January 1,
1997.
<TABLE>
<CAPTION>
JUNE 30, 1996
----------------------
HISTORICAL PRO FORMA
---------- ---------
<S> <C> <C>
PROVED RESERVES:
Oil (Mbbls)................................................. 7,798 14,595
Natural gas (MMcf).......................................... 120,542 281,873
Total (MMcfe).......................................... 167,330 369,443
Future net revenues ($000).................................. $288,024 $602,375
Present value of future net revenues before income taxes
($000).................................................... $196,826 $408,265
PROVED DEVELOPED RESERVES:
Oil (Mbbls)................................................. 4,377 10,856
Natural gas (MMcf).......................................... 105,709 244,120
Total (MMcfe).......................................... 131,971 309,256
Future net revenues ($000).................................. $234,718 $513,416
Present value of future net revenues before income taxes
($000).................................................... $168,384 $357,987
</TABLE>
45
<PAGE> 46
There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves and in projecting future rates of production and
future amounts and timing of development expenditures, including underground
accumulations of crude oil and gas that cannot be measured in an exact manner,
and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Estimates of proved undeveloped reserves are inherently less certain than
estimates of proved developed reserves. The quantities of oil and gas that are
ultimately recovered, production and operating costs, the amount and timing of
future development expenditures, geologic success and future oil and gas sales
prices may all differ from those assumed in these estimates. In addition, the
Company's reserves may be subject to downward or upward revision based upon
production history, purchases or sales of properties, results of future
development, prevailing oil and gas prices and other factors. Therefore, the
present value shown above should not be construed as the current market value of
the estimated oil and gas reserves attributable to the Company's properties.
In accordance with SEC guidelines, the estimates of future net revenues
from the Company's proved reserves and the present value thereof are made using
oil and gas sales prices in effect as of the dates of such estimates and are
held constant throughout the life of the properties except where such guidelines
permit alternate treatment, including, in the case of natural gas contracts, the
use of fixed and determinable contractual price escalations. The future net
revenues and present value thereof attributable to the Company's proved reserves
in the Bob West Field reflect the contract price to be paid by Tennessee Gas
through the termination of the Tennessee Gas Contract effective January 1, 1997.
See "-- Legal Proceedings -- Tennessee Gas Litigation." As of June 30, 1996,
spot market prices were $2.38 per MMBtu and $18.83 per bbl, before adjustments
for appropriate basis differentials and Btu content. The prices for natural gas
and, to a lesser extent, oil, are subject to substantial seasonal fluctuations,
and prices for each are subject to substantial fluctuations as a result of
numerous other factors. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations."
ACREAGE
The following table sets forth certain information with respect to
developed and undeveloped leased acreage of the Company, of Medallion and on a
pro forma combined basis as of September 30, 1996. The leases in which the
Company has an interest are for varying primary terms, and many require the
payment of delay rentals to continue the primary term. The leases may be
surrendered by the operator at any time by notice to the lessors, by the
cessation of production, fulfillment of commitments, or by failure to make
timely payments of delay rentals. Excluded from the table are the Company's
interests in the properties subject to volumetric production payments. See
"-- Volumetric Production Payment Program and Underlying Principal Properties."
<TABLE>
<CAPTION>
DEVELOPED ACRES UNDEVELOPED ACRES
------------------ ------------------
STATE GROSS NET GROSS NET
-------------------------------------------- ------- ------- ------- -------
<S> <C> <C> <C> <C>
Company:
Texas..................................... 49,405 17,904 32,418 18,602
Wyoming................................... 67,574 60,239 77,019 71,304
Montana................................... 64,522 42,002 21,017 16,977
Colorado.................................. 10,990 6,510 -- --
Louisiana................................. 3,209 2,695 36,534 32,097
Other..................................... 1,636 410 5,213 1,303
------- ------- ------- -------
Total............................. 197,336 129,760 172,201 140,283
------- ------- ------- -------
Medallion:
Texas..................................... 73,120 50,597 3,680 1,049
Oklahoma.................................. 44,237 22,768 10,926 7,844
Louisiana................................. 103,804 16,782 4,688 3,756
Other..................................... 99,199 27,139 4,895 4,314
------- ------- ------- -------
Total............................. 320,360 117,286 24,189 16,963
------- ------- ------- -------
Pro Forma Total............................. 517,696 247,046 196,390 157,246
======= ======= ======= =======
</TABLE>
46
<PAGE> 47
TITLE TO OIL AND GAS PROPERTIES
Substantially all of the Company's property interests not the subject of
its VPP program are held pursuant to leases from third parties. A title opinion
is typically obtained prior to acquiring these properties. The Company or the
relevant operator routinely obtained title opinions on substantially all of the
properties that the Company has drilled or participated in drilling. With
respect to acquisitions of proved properties, the Company generally obtains
updated title opinions covering properties constituting at least 80% of the
value of the acquisition, and there are usually older, existing opinions
covering the remaining properties. The Company believes that it has satisfactory
title to its properties in accordance with standards generally accepted in the
oil and gas industry. In addition, the Company's properties are subject to
customary royalty interests, overriding royalty interests, liens for current
taxes, and other burdens that the Company believes do not materially interfere
with the use of or affect the value of such properties.
The Company typically takes the same approach to approving title for
volumetric production payments as it does in drilling its own wells or in
property acquisitions. The operator will generally have a drilling title opinion
or a division order title opinion (on producing wells) for the properties being
conveyed. In most cases, the Company will require that the operator update any
existing title opinions to reflect the current working interest and net revenue
interest subjected to the volumetric production payment conveyed to the Company.
By updating the title, any existing mortgages, liens, lawsuits and potential
encumbrances will be disclosed. Only when the Company believes that it has
satisfactory title to the properties in accordance with generally accepted
industry standards will the Company proceed with a volumetric production
payment.
NATURAL GAS TRANSPORTATION AND MARKETING OPERATIONS
For the nine months ended September 30, 1996, the natural gas
transportation and marketing businesses accounted for approximately 75% of the
Company's revenues and recorded a $0.3 million operating loss.
Natural Gas Transportation
The major asset related to the Company's natural gas transportation
operations is a 150-mile carbon steel intrastate pipeline system and related
gathering facilities located north of Houston, Texas. In addition, the Company
owns more than 300 miles of natural gas gathering lines generally associated
with its wells, which connect producing fields with various natural gas
transmission lines and local distribution companies. Of the 17 gathering
systems, including the Texas system acquired in the Medallion Acquisition, five
are located in the Sweet Grass Arch basin in Montana, eleven are located in
Texas and one is located in Louisiana.
Natural Gas Marketing Operations
The Company's natural gas marketing business currently has offices in
Houston, Texas; Edison, New Jersey; and Pittsburgh, Pennsylvania, and engages in
the direct marketing of natural gas to industrial and commercial end-users.
During 1996, the Company served approximately 300 customers in 34 states and
Canada, bought natural gas from over 160 domestic and Canadian suppliers and
shipped natural gas on over 90 different pipelines.
As part of the Medallion Acquisition, the Company acquired Medallion's
natural gas marketing operations located in Tulsa, Oklahoma. These operations
market Medallion's production, aggregate natural gas volumes from producers and
provide services (including nomination, pipeline balancing, royalty payment
administration, and other accounting and administrative services) to these
producers. As of September 30, 1996, Medallion's natural gas marketing
operations purchased natural gas from over 600 wells located primarily in
Oklahoma and the Texas panhandle. These volumes are aggregated with volumes
purchased from others and resold to natural gas distribution companies,
industrial end-users and other natural gas marketing companies.
47
<PAGE> 48
Marketing of Oil and Gas Production
The Company markets substantially all of the oil and gas production from
Company-operated wells and its volumetric production payment volumes to
pipelines, local distribution companies and third-party natural gas marketers.
The Company believes that its marketing activities add value by giving the
Company opportunities to obtain competitive prices for products, rapidly connect
new wells to pipelines, minimize pipeline and purchaser balancing problems,
maintain continuous sales of production and secure prompt payment.
Substantially all of the Company's natural gas is sold either under
short-term contracts (one year or less) providing for variable or market
sensitive prices or under various long-term contracts providing for fixed prices
which dedicate the natural gas to a single purchaser for an extended period of
time.
Approximately 8% of the Company's total production for the nine months
ended September 30, 1996, after giving effect to the Medallion Acquisition, was
subject to the Tennessee Gas Contract, which was terminated effective January 1,
1997. Average sales prices under the Tennessee Gas Contract, excluding severance
tax reimbursements, were $8.38 per Mcf for the nine months ended September 30,
1996, $7.90 per Mcf for the year ended December 31, 1995, $7.49 per Mcf in 1994,
and $7.09 per Mcf in 1993.
The Company sells its oil production in each of its producing regions
pursuant to contracts based on postings by major purchasers. Historically, the
Company has been able to achieve a premium to these postings, based on oil
quality and transportation differentials.
The price of non-contract natural gas is influenced by supply and demand
factors for natural gas in the United States, Mexico and Canada, as well as
prices of competing fuels. Average oil prices are reflective of the world oil
market during the periods. Market prices for oil and gas, which are volatile in
nature, have a significant impact on the Company's revenue, net income and cash
flow.
In connection with the marketing of its oil and gas production, the Company
engages in oil and gas price risk management activities primarily through the
use of oil and gas futures and options contracts and "fixed for floating" price
swap agreements. The Company utilizes oil and gas futures contracts for the
purpose of hedging the risks associated with fluctuating crude oil and gas
prices and accounts for such contracts in accordance with FASB Statement No. 80,
"Accounting for Futures Contracts." Since these contracts qualify as hedges and
correlate to market price movements of oil and gas, any gains or losses
resulting from market changes will be offset by losses or gains on corresponding
physical transactions. The swap agreements on notional volumes require payments
to (or the receipt of payments from) counterparties to such agreements based on
the differential between a fixed and variable price for the oil or gas. The
Company maintains coverage of such notional volumes with adequate physical
volume deliveries at the hub points used to price such arrangements. The Company
records these transactions under settlement accounting guidelines and,
accordingly, includes gains or losses in oil and gas revenues in the period of
the swapped production. The Company intends to continue to consider various risk
management arrangements to stabilize cash flow and earnings and reduce the
Company's susceptibility to volatility in oil and gas prices.
The Company has three separate natural gas price swaps in place as a result
of the Medallion Acquisition. Effective January 1, 1995, Medallion effectively
fixed the sales price for a portion of its natural gas production at a NYMEX
price of $1.905 per MMBtu for a five-year term. In September 1995, Medallion
effectively fixed the sales price for an additional portion of its natural gas
production at a NYMEX price of $2.055 per MMBtu for ten years. In May 1996,
Medallion effectively fixed the sales price for an additional portion of its
natural gas production at a weighted average NYMEX price of $2.23 per MMBtu for
a one-year term. For the calendar years 1996, 1997 and 1998, these transactions
cover 11.7 million MMBtu, 8.1 million MMBtu and 4.83 million MMBtu of natural
gas, respectively, and result in annual weighted average prices per MMBtu of
$2.0325, $1.9942 and $1.9832, respectively. In May 1996, Medallion also fixed a
basis component of the net wellhead sales price for a portion of its natural gas
production at the NYMEX price less $0.096 per MMBtu for a one-year term.
48
<PAGE> 49
SIGNIFICANT CUSTOMER
One customer, Tennessee Gas, accounted for approximately 78%, 82% and 72%
of the oil and gas exploration and production revenue and 10%, 16% and 14% of
the Company's consolidated revenue for the years ended December 31, 1993, 1994,
and 1995, respectively, and 42% of the oil and gas exploration and production
revenue and 10% of the Company's consolidated revenue for the nine months ended
September 30, 1996. No other single customer accounted for more than 10% of the
Company's consolidated revenue during these periods. Effective January 1, 1997,
the Company's contract with Tennessee Gas was terminated. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- Tennessee Gas Litigation."
REGULATION
General. The Company's business is affected by numerous governmental laws
and regulations, including energy, environmental, conservation, tax and other
laws and regulations relating to the energy industry. For example, state and
federal agencies have issued rules and regulations that require permits for the
drilling of wells, regulate the spacing and drilling of wells, prevent the waste
of oil and gas reserves through proration, and regulate oilfield and pipeline
environmental and safety matters. Changes in any of these laws and regulations
could have a material adverse effect on the Company's business. In view of the
many uncertainties with respect to current and future laws and regulations,
including their applicability to the Company, the Company cannot predict the
overall effect of such laws and regulations on its future operations.
The Company believes that its operations comply in all material respects
with all applicable laws and regulations and that the existence and enforcement
of such laws and regulations have no more restrictive effect on the Company's
method of operations than on other similar companies in the energy industry.
The following discussion contains summaries of certain laws and regulations
and is qualified in its entirety by the foregoing.
Regulation of the Sale and Transportation of Oil and Gas. Various aspects
of the Company's oil and gas operations are regulated by agencies of the federal
government. The FERC regulates the transportation of natural gas in interstate
commerce pursuant to the Natural Gas Act of 1938 (the "NGA") and the Natural Gas
Policy Act of 1978 (the "NGPA"). In the past, the federal government had
regulated the prices at which the Company's produced oil and gas could be sold.
Currently, "first sales" of natural gas by producers and marketers, and all
sales of crude oil, condensate and natural gas liquids, can be made at
uncontrolled market prices, but Congress could reenact price controls at any
time.
Deregulation of wellhead and other sales in the natural gas industry began
with the enactment of the NGPA in 1978. In 1989, Congress enacted the Natural
Gas Wellhead Decontrol Act which removed all NGA and NGPA price and nonprice
controls affecting wellhead sales of natural gas effective January 1, 1993. In
late 1992, the FERC issued its Order No. 547 which granted automatic and
flexible blanket certificate authority to all persons engaging in "sales for
resale" in interstate commerce which would otherwise be regulated as
jurisdictional sales under the NGA. Due to FERC's elimination in July 1994 of
certain regulations deemed to be unnecessary due to enactment of the Decontrol
Act, a portion of the Company's current natural gas sales to resellers that do
not qualify as "first sales" and involve natural gas which is not produced by
the Company are made pursuant to the blanket authority granted by Order No. 547.
Although the Company believes it unlikely that FERC will materially revise or
withdraw the blanket authority issued by Order No. 547, certain resales by the
Company could in the future be subject to greater federal oversight, including
the possibility that the FERC could prospectively impose more restrictive
conditions on such sales. In that event, the Company does not believe it would
be affected differently than other natural gas industry participants engaging in
interstate resales.
Commencing in April 1992, the FERC issued its Order No. 636 and related
clarifying orders ("Order No. 636"), which, among other things, purported to
restructure the interstate natural gas industry and to require interstate
pipelines to provide transportation services separate, or "unbundled," from the
49
<PAGE> 50
pipelines' sales of natural gas. Order No. 636 also required pipelines to
provide "open-access" transportation on a nondiscriminatory basis for all
natural gas shippers. Order No. 636 was implemented on a pipeline-by-pipeline
basis, principally through negotiated settlements in individual pipeline service
restructuring proceedings. In many instances, the interstate pipelines
themselves are no longer wholesalers or merchants of natural gas, but instead
provide only natural gas storage and transportation services. Order No. 636 and
certain related proceedings were the subject of an appeal to the United States
Court of Appeals for the District of Columbia Circuit. That court recently
issued its decision in the appeal of Order No. 636 and largely upheld the
fundamental tenets of the order. However, the court's decision is still subject
to further action, including potential applications for a writ of certiorari to
the United States Supreme Court. In addition, several appeals in individual
pipeline proceedings and related dockets remain pending. It is therefore not
possible for the Company to predict what effect, if any, the ultimate outcome of
these regulatory and judicial review proceedings will have on FERC's open-access
regulations or the Company's operations.
Although Order No. 636 does not directly regulate the Company's production
activities, the FERC has stated that it intends Order No. 636 to foster
increased competition within all phases of the natural gas industry. It is
unclear what impact, if any, increased competition within the natural gas
industry under Order No. 636 will have on the Company's activities. Although
Order No. 636, assuming it is upheld in its entirety, could provide the Company
with better access to markets and the ability to utilize new types of
transportation services, it could also subject the Company to more restrictive
pipeline imbalance tolerances and greater penalties for violation of those
tolerances. The Company believes that Order No. 636 has not had any significant
impact on the Company as a producer or on the Company's natural gas marketing
efforts.
The FERC has announced its intention to reexamine or revise certain of its
transportation-related policies, including the appropriate manner for setting
rates for new interstate pipeline construction, the manner in which interstate
pipeline shippers may release interstate pipeline capacity under Order No. 636
for resale in secondary markets, and the use of market-based rates for
interstate natural gas transmission services. In January 1996, the FERC issued a
statement of policy and request for comments concerning alternatives to its
traditional cost-of-service ratemaking methodology and set forth the criteria
that the FERC will use to evaluate proposals to charge market-based rates for
the transportation of natural gas. The FERC also requested comments on whether
it should allow pipelines the flexibility to negotiate the terms and conditions
of transportation service with prospective shippers. In another rulemaking, the
FERC is considering how to alter its regulations to promote the fair and
effective release and recontracting of pipeline capacity from one shipper to
another, and to what extent such transactions should be regulated where the
market is demonstrably competitive. While any resulting FERC action on the above
matters would affect the Company only indirectly, these inquiries are intended
to further enhance competition in natural gas markets.
The FERC has also issued various orders and policy statements which are
intended to foster competitive markets for natural gas by giving natural gas
purchasers access to multiple supply sources at market-driven prices. The FERC's
current rules and policy statements may also have the effect of enhancing
competition in natural gas markets by, among other things, facilitating
construction of natural gas supply laterals and encouraging non-producer natural
gas marketers to engage in certain purchase and sale transactions. The Company
cannot accurately predict whether the FERC's actions will achieve the goal of
increasing competition in markets in which the Company's natural gas is sold.
The FERC has also recently issued numerous orders confirming the sale and
abandonment of natural gas gathering facilities previously owned by interstate
pipelines and acknowledging that if the FERC does not have jurisdiction over
services provided thereon, then such facilities and services may be subject to
regulation by state authorities in accordance with state law. A number of states
have either enacted new laws or are considering inadequacy of existing laws
affecting gathering rates and/or services. Thus, natural gas gathering may
receive greater regulatory scrutiny by state agencies in the future. The
Company's gathering operations could be adversely affected should they be
subject in the future to increased state regulation of rates or services,
although the Company does not believe that it would be
50
<PAGE> 51
affected by such regulation any differently than other natural gas producers or
gatherers. In addition, FERC's approval of transfers of previously-regulated
gathering systems to independent or pipeline-affiliated gathering companies that
are not subject to FERC regulation may affect competition for gathering or
natural gas marketing services in areas served by those systems and thus may
affect both the costs and the nature of gathering services that will be
available to interested producers or shippers in the future. The effects, if
any, of FERC's gathering policies on the Company's operations are uncertain.
The Company's natural gas transportation and gathering operations are
generally subject to safety and operational regulations relating to the design,
installation, testing, construction, operation, replacement and management of
facilities and to state regulation of the rates of such service. To a more
limited degree, a portion of the Company's transportation services may be
subject to FERC oversight in accordance with the provisions of the NGPA.
Pipeline safety issues have recently become the subject of increasing focus in
various political and administrative arenas at both the state and federal
levels. At the federal level, in October 1996, the President signed the
Accountable Pipeline Safety and Partnership Act of 1996, which, among other
things, gives the public an opportunity to comment on pipeline risk management
programs, promotes communication regarding safety issues to residents along
pipeline right-of-ways, and encourages the examination of remote control valves
along pipelines. The Company believes its operations, to the extent they may be
subject to current natural gas pipeline safety requirements, comply in all
material respects with such requirements. The Company cannot predict what
effect, if any, the adoption of additional pipeline safety legislation might
have on its operations, but the natural gas industry could be required to incur
additional capital expenditures and increased costs depending upon future
legislative and regulatory changes.
Sales of crude oil, condensate and natural gas liquids by the Company are
not regulated and are made at market prices. The price the Company receives from
the sale of these products is affected by the cost of transporting the products
to market. Effective as of January 1, 1995, the FERC implemented regulations
establishing an indexing system for transportation rates for oil pipelines,
which would generally index such rates to inflation, subject to certain
conditions and limitations. These regulations are subject to pending petitions
for judicial review. The Company is not able to predict with certainty what
effect, if any, these regulations will have on it, but other factors being
equal, the regulations may tend to increase transportation costs or reduce
wellhead prices under certain conditions.
The Company also operates federal oil and gas leases, which are subject to
the regulation of the United States Minerals Management Service ("MMS"). MMS
recently issued a notice of proposed rulemaking in which it proposed to amend
its regulations governing the calculation of royalties and the valuation of
natural gas produced from federal leases. The principle feature in the
amendments, as proposed, would establish an alternative market-index based
method to calculate royalties on certain natural gas production sold to
affiliates or pursuant to non-arm's-length sales contracts. The MMS proposed
this rulemaking to facilitate royalty valuation in light of changes in the gas
marketing environment. The Company cannot predict at this stage what action the
MMS will take on these matters, nor can it predict at this stage of the
rulemaking proceeding how the Company might be affected by amendments to the
regulations.
Additional MMS proposals and proceedings that might affect the oil and gas
industry are pending before Congress, the FERC and the courts. The Company
cannot predict when or whether any such proposals may become effective. In the
past, the natural gas industry historically has been very heavily regulated.
There is no assurance that the current regulatory approach pursued by the FERC
will continue indefinitely into the future. Notwithstanding the foregoing, it is
not anticipated that compliance with existing federal, state and local laws,
rules and regulations will have a material or significantly adverse effect upon
the capital expenditures, earnings or competitive position of the Company.
Taxation. The operations of the Company, as is the case in the energy
industry generally, are significantly affected by federal tax laws, including
the Tax Reform Act of 1986. In addition, federal as well as state tax laws have
many provisions applicable to corporations in general which could affect the
potential tax liability of the Company.
51
<PAGE> 52
Operating Hazards and Environmental Matters. The oil and gas business
involves a variety of operating risks, including the risk of fire, explosions,
blow-outs, pipe failure, casing collapse, abnormally pressured formations and
environmental hazards such as oil spills, natural gas leaks, ruptures and
discharge of toxic gases, the occurrence of any of which could result in
substantial losses to the Company due to injury or loss of life, severe damage
to or destruction of property, natural resources and equipment, pollution or
other environmental damage, clean-up responsibilities, regulatory investigation
and penalties and suspension of operations. Such hazards may hinder or delay
drilling, development and on-line production operations.
Extensive federal, state and local laws and regulations govern oil and gas
operations regulating the discharge of materials into the environment or
otherwise relating to the protection of the environment. These laws and
regulations may require the acquisition of a permit before drilling commences,
restrict or prohibit the types, quantities and concentration of substances that
can be released into the environment or wastes that can be disposed of in
connection with drilling and production activities, prohibit drilling activities
on certain lands lying within wetlands or other protected areas and impose
substantial liabilities for pollution or releases of hazardous substances
resulting from drilling and production operations. Moreover, state and federal
environmental laws and regulations may become more stringent.
The Company owns, leases, or operates properties that have been used for
the exploration and production of oil and gas, and owns and operates a natural
gas pipeline and natural gas gathering systems. Hydrocarbons, mercury,
polychlorinated biphenyls ("PCBs") or other wastes may have been disposed of or
released on or under the properties owned, leased, or operated by the Company or
on or under other locations where such wastes have been or are taken for
disposal, although the Company has no knowledge of any such occurrences. The
Company's properties and any wastes that may have been disposed thereon may be
subject to federal or state environmental laws that could require the Company to
remove the wastes or remediate any contamination identified on the Company's
properties.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the original conduct, on certain classes of persons who are
considered to be responsible for the release of a "hazardous substance" into the
environment. These persons include the owner or operator of the disposal site or
sites where the release occurred and companies that disposed or arranged for the
disposal of the hazardous substances. Under CERCLA, such persons may be subject
to joint and several liability for the costs of cleaning up the hazardous
substances that have been released into the environment, for damages to natural
resources and for the costs of certain health studies, and it is not uncommon
for neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the release of hazardous
substances.
In addition, the U.S. Oil Pollution Act ("OPA") requires owners and
operators of facilities that could be the source of an oil spill into "waters of
the United States" (a term defined to include rivers, creeks, wetlands, and
coastal waters) to adopt and implement plans and procedures to prevent any spill
of oil into any waters of the United States. OPA also requires affected facility
owners and operators to demonstrate that they have at least $35 million in
financial resources to pay for the costs of cleaning up an oil spill and
compensating any parties damaged by an oil spill. Substantial civil and criminal
fines and penalties can be imposed for violations of OPA and other environmental
statutes.
In addition, the disposal of wastes containing naturally occurring
radioactive material which are commonly generated during oil and gas production
are 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.
52
<PAGE> 53
LEGAL PROCEEDINGS
Tennessee Gas Litigation
In April 1996, the Texas Supreme Court withdrew its previous opinion and
issued its final opinion with respect to the take-or-pay pricing and quantity
provisions of the Tennessee Gas Contract litigation and affirmed the Company's
position on all issues, including those involving both the volume and price
provisions of the contract. In August 1996, the Texas Supreme Court denied
Tennessee Gas' petition for a rehearing and on September 30, 1996, the Company
finally concluded these aspects of the litigation that had been ongoing since
1990 and received approximately $70 million from Tennessee Gas, representing the
Tennessee Gas Receivable at that date.
On December 23, 1996, the Company and Tennessee Gas entered into a
settlement covering all claims and litigation between them and agreed to
terminate the Tennessee Gas Contract effective January 1, 1997, approximately
two years prior to its expiration date. In the settlement, the parties agreed to
the dismissal of all of their respective claims concerning disputes with respect
to the obligations of the parties under the Tennessee Gas Contract. Included in
the settlement is the disposition of the lawsuit related to the November 1996
verdict of a jury in a trial in the District Court of Zapata County, Texas, in
which the jury awarded Tennessee Gas $143.2 million including approximately $114
million for punitive damages. The December 1996 settlement did not affect the
April 1996 decision of the Texas Supreme Court or the Company's prior recovery
of the Tennessee Gas Receivable. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and Note 7 to the Consolidated
Financial Statements.
Other Legal Proceedings
The Company is also a party to three lawsuits involving the holders of
royalty interests on the acreage that was covered by the Tennessee Gas Contract.
The Company is a co-plaintiff in the first of these lawsuits that was filed in
Dallas County, Texas, and is a defendant in the other subsequently filed suits
in Zapata County, Texas. The basis of these declaratory judgment actions is the
royalty holders' claim that their royalty payments should be based on the price
paid by Tennessee Gas for the natural gas purchased by it under the Tennessee
Gas Contract. The Company has been paying royalties for this natural gas based
upon the spot market price. Because the leases have market-value royalty
provisions, the Company believes it is in full compliance under the leases with
its royalty holders, and its position has been confirmed in the Dallas suit
where the trial judge has granted the co-plaintiffs' motions for summary
judgment on this issue. In addition, the trial judge has granted summary
judgment against the royalty owners with respect to their various counterclaims
against the co-plaintiffs as concerns the jointly-owned Guerra "A" and Guerra
"B" units. However, the royalty owners also separately counterclaimed against
the Company with respect to the Jesus Yzaguirre unit, alleging that the largest
lease contained therein had terminated in December 1975 and that certain of the
royalty owners were entitled to royalties based upon the Tennessee Gas Contract
price because of their execution of certain division orders in 1992 that
allegedly varied the market-value royalty provision of their lease. The trial
judge has not yet ruled on the parties' respective motions for summary judgment
concerning these issues, although he has granted the Company's motion for
summary judgment that the royalty holders' leases require that royalties be
based upon the market value of the natural gas at the lease when produced and
sold, not the price paid for the natural gas under the Tennessee Gas Contract.
While the Company believes its defenses are meritorious and that it should
prevail in the pending litigation, there can be no assurance as to the ultimate
outcome of these matters, which the royalty owners have indicated will be
appealed in due course to the Fifth District Court of Appeals in Dallas, Texas.
The Company and Medallion are also parties to various other lawsuits and
governmental proceedings, all arising in the ordinary course of business.
Although the outcome of these lawsuits cannot be predicted with certainty, the
Company and Medallion do not expect such matters to have a material adverse
effect, either singly or in the aggregate, on the financial position of the
Company.
53
<PAGE> 54
MANAGEMENT
EXECUTIVE OFFICERS, DIRECTORS AND CERTAIN KEY EMPLOYEES
The following table sets forth the name, age and present position with the
Company of each of the Company's executive officers, directors and certain other
key employees.
<TABLE>
<CAPTION>
NAME AGE POSITION WITH THE COMPANY
---- --- -------------------------
<S> <C> <C>
James W. Christmas................... 48 President, Chief Executive Officer and Director
C.R. Devine.......................... 50 Vice President, Oil and Gas Operations; President, KCS
Resources, Inc.
Henry A. Jurand...................... 47 Vice President, Chief Financial Officer and Secretary
Harry Lee Stout...................... 49 President, KCS Energy Marketing, Inc.; President, KCS
Pipeline Systems, Inc.; President, KCS Michigan
Resources, Inc.; President, KCS Energy Services, Inc.
William E. Warnock, Jr............... 43 President, KCS Medallion Resources, Inc., President,
GED Energy Services, Inc., and Vice Chairman, Medallion
Gas Services, Inc.
G. Stanton Geary..................... 62 Director
Stewart B. Kean...................... 62 Director and Chairman of the Board
James E. Murphy, Jr.................. 40 Director
Robert G. Raynolds................... 44 Director
Joel D. Siegel....................... 55 Director
Christopher A. Viggiano.............. 43 Director
</TABLE>
James W. Christmas has served as President and Chief Executive Officer and
as a director of the Company since 1988. Prior to joining the Company, Mr.
Christmas spent ten years with NUI Corporation, serving in a variety of officer
capacities and as President of several of its subsidiaries. While Mr. Christmas
was Vice President of Planning of NUI Corporation, he was in charge of the
spin-off of its non-regulated businesses that resulted in the formation of KCS
Energy, Inc. Mr. Christmas began his career with Arthur Andersen & Co.
C. R. Devine was named Vice President, Oil and Gas Operations of the
Company in December 1992 and President of KCS Resources, Inc., a subsidiary of
the Company engaged in oil and gas exploration and production, in December 1993.
He has served as principal operating officer of the Company's oil and gas
operations since 1988. He has been employed by the Company and its predecessor
companies since 1974.
Henry A. Jurand was appointed Chief Financial Officer on January 1, 1996.
He has served as Vice President of the Company since September 1990, as
Treasurer from March 1991 to December 1995, and as Secretary since February
1992. From 1988 to 1990, he was a Senior Vice President of Private Capital
Partners, Inc., in New York City. From 1977 to 1988, he was employed by
Baltimore Gas and Electric Company, holding management positions including Vice
President and Chief Financial Officer of Constellation Holdings, Inc., a
subsidiary, and President, Constellation Investments, Inc.
Harry Lee Stout has served as President of KCS Energy Marketing, Inc. and
KCS Pipeline Systems, Inc., the subsidiaries of the Company engaged in natural
gas marketing and transportation, since joining the Company in August 1991. In
October 1995, he was named President of KCS Michigan Resources, Inc. and in
September 1996, he was named President, KCS Energy Services, Inc. From 1990 to
1991, he was Vice President of Minerex Corporation in Houston, Texas. From 1978
to 1990, he was employed by Enron Corp. of Houston, Texas, holding various
management positions including Senior Vice President of Houston Pipe Line
Company and Executive Vice President, Enron Gas Marketing Company, both of which
are subsidiaries of Enron Corp.
54
<PAGE> 55
William E. Warnock, Jr. was named President, KCS Medallion Resources, Inc.
(formerly InterCoast Oil and Gas Company) President, GED Energy Services, Inc.,
and Vice Chairman, Medallion Gas Services, Inc. effective with the consummation
of the Medallion Acquisition. Mr. Warnock joined InterCoast in 1992 as its
President and Chief Operating Officer. Prior to joining InterCoast, he
co-founded Medallion Petroleum, Inc. in 1985 and served as its President.
G. Stanton Geary has served as a director of the Company since 1988. He is
proprietor of Gemini Associates, Pomfret, Connecticut, a venture capital
consulting firm, and business manager of the Rectory School, Pomfret,
Connecticut.
Stewart B. Kean has served as Chairman of the Board of Directors of the
Company since 1988. He was President of Utility Propane Company, a former
subsidiary of the Company, from 1965 to 1989. He is past President of the
National LP Gas Association and past President of the World LP Gas Forum. He
currently serves as a member of the Council of the World LP Gas Forum. Mr. Kean
is Robert G. Raynolds' uncle.
James E. Murphy, Jr. has served as a director of the Company since 1988.
Mr. Murphy heads his own political and governmental relations consulting firm
offering strategic planning and management consulting services to Republican
candidates nationwide, with extensive experience at the presidential, state and
congressional levels. Based in Gaithersburg, Maryland, he also advises
corporations and industry groups on strategic planning, governmental relations
and grassroots lobbying projects.
Robert G. Raynolds has served as a director of the Company since August
1995. He has been an independent consulting geologist for several major and
independent oil and gas companies from 1992 until the present and was a
geologist with Amoco Production Company from 1983 until 1992. Mr. Raynolds is
Stewart B. Kean's nephew.
Joel D. Siegel has served as a director of the Company since 1988. He is an
attorney-at-law and has been President of the law firm, Orloff, Lowenbach,
Stifelman & Siegel, P.A. of Roseland, New Jersey, since 1975. Orloff, Lowenbach,
Stifelman & Siegel, P.A. serves as outside legal counsel to the Company. Mr.
Siegel served as President and Chief Executive Officer of Constellation Bancorp,
Elizabeth, New Jersey, and Constellation Bank, Elizabeth, New Jersey, for the
period April 26, 1991 to December 6, 1991.
Christopher A. Viggiano has served as a director of the Company since 1988.
Mr. Viggiano has been President, Chairman of the Board and majority owner of
O'Bryan Glass Corp., Queens, New York, since December 1, 1991, and served as
Vice President and a member of the board of directors of O'Bryan Glass Corp.
from 1985 to December 1, 1991. He is a Certified Public Accountant.
55
<PAGE> 56
SECURITY OWNERSHIP BY CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
As of December 31, 1996, there were 11,587,422 shares of the Company's
Common Stock outstanding. These shares were held by 1,184 holders of record. The
following table sets forth information as to the number and percentage of shares
owned beneficially as of December 31, 1996 by each executive officer and
director of the Company, by all executive officers and directors as a group and
by each person known by the Company to be a beneficial owner of more than 5% of
the Company's Common Stock. For the purpose of the following table, a beneficial
owner of a security includes any person who, directly or indirectly, has or
shares voting power and/or investment power with respect to such security.
<TABLE>
<CAPTION>
SHARES OWNED PERCENT
BENEFICIALLY(1) OF CLASS
--------------- --------
<S> <C> <C>
James W. Christmas.......................................... 511,175(2)(3) 4.3%
C. R. Devine................................................ 91,804(2) *
Henry A. Jurand............................................. 43,032(2) *
Harry Lee Stout............................................. 36,238(2) *
William E. Warnock, Jr...................................... -- --
G. Stanton Geary............................................ 7,062(2) *
Stewart B. Kean............................................. 1,379,650(2)(4) 11.9%
James E. Murphy, Jr......................................... 14,177(2) *
Robert G. Raynolds.......................................... 1,963(2) *
Joel D. Siegel.............................................. 91,429(2)(5) *
Christopher A. Viggiano..................................... 27,829(2) *
Executive officers and directors as a group (11 persons).... 2,204,359(2) 18.5%
Metropolitan Life Insurance Company(6)...................... 1,302,500 11.2%
One Madison Avenue
New York, New York 10010
</TABLE>
- ---------------
* Less than 1%
(1) Unless otherwise indicated, beneficial owner has sole voting and investment
power.
(2) Includes shares that (i) may be purchased as a result of options granted
that are exercisable within 60 days of 260,000, 31,950, 25,850 and 22,500
for Messrs. Christmas, Devine, Jurand and Stout, respectively, 3,000 each
for Messrs. Geary, S.B. Kean, Murphy, Siegel and Viggiano and 1,000 for Mr.
Raynolds and (ii) are allocated to the beneficial owner's account under
401(k) plans.
(3) Includes 18,000 shares held in trusts established for the benefit of Mr.
Christmas' children, the beneficial ownership of which is disclaimed by Mr.
Christmas.
(4) Includes the following shares as to which Mr. Kean shares voting and
investment power: 413,812 shares held by Stewart B. Kean, John Kean and May
Raynolds as the three co-trustees under certain family trusts; 58,392 shares
held by Stewart B. Kean and John Kean as the two co-trustees under certain
family trusts; 40,620 shares held by Stewart B. Kean and John Kean, Jr. as
the two co-trustees under certain family trusts.
(5) Includes 8,000 shares held in trusts established for the benefit of Mr.
Siegel's children, the beneficial ownership of which is disclaimed by Mr.
Siegel.
(6) Includes 1,290,800 shares (or 11.1%) owned by an affiliate of Metropolitan
Life Insurance Company, State Street Research and Management Company, One
Financial Center, 30th Floor, Boston, Massachusetts 02111.
In December 1994, the Board of Directors adopted a policy requiring minimum
levels of ownership of the Company's Common Stock by its directors and by
executive officers of the Company and its subsidiaries. Within a four-year
period, directors are required to become beneficial owners of Common Stock with
a market value equivalent to four times their annual retainer. During such
period, the president
56
<PAGE> 57
and chief executive officer must become the owner of Common Stock with a market
value of four times his annual base salary. For vice presidents of the Company
and presidents of subsidiaries, the multiple of annual base salary is two and
one-half times and for vice presidents of subsidiaries it is one-half.
DESCRIPTION OF CAPITAL STOCK
The following summary of the Company's capital stock is qualified in its
entirety by reference to the Company's Certificate of Incorporation and Bylaws,
each of which is incorporated by reference into this Prospectus. See
"Incorporation of Certain Documents by Reference."
COMMON STOCK
The Company is authorized to issue 50,000,000 shares of Common Stock, $.01
par value per share. Following the Offerings, 14,587,422 shares of Common Stock
will be outstanding. In addition, the Company has granted options to purchase up
to 529,575 shares of Common Stock at an average exercise price of $10.91 per
share and has granted warrants to purchase up to 435,000 shares of Common Stock
at $45.00 per share in connection with the Medallion Acquisition. See
"Capitalization." Holders of Common Stock are entitled to one vote per share on
all matters on which the holders of Common Stock are entitled to vote. Because
holders of Common Stock do not have cumulative voting rights, holders of a
majority of the shares voting for the election of directors can elect all of the
members of the Board of Directors. A majority vote is also sufficient for other
actions that require the vote or concurrence of stockholders. The Common Stock
is not redeemable and has no conversion or preemptive rights. All of the
outstanding shares of Common Stock are, and all of the shares sold in this
offering will be, when issued and paid for, fully paid and non-assessable. In
the event of the liquidation or dissolution of the Company, subject to the
rights of the holders of any outstanding shares of the Company's Preferred
Stock, the holders of Common Stock are entitled to share pro rata in any balance
of the corporate assets available for distribution to them. The Company may pay
dividends if, when and as declared by the Board of Directors from funds legally
available therefor. Under the terms of the Indenture and Bank Credit Facilities,
however, the payment of dividends is limited to 50% of the Company's
consolidated net income commencing October 1, 1995. See "Dividend Policy."
PREFERRED STOCK
The Company is authorized to issue up to 5,000,000 shares of Preferred
Stock, $.01 par value per share. No shares of Preferred Stock are currently
outstanding. The Company's Board of Directors is authorized to issue the
Preferred Stock in series and, with respect to each series, to determine the
number of shares in any such series, and fix the designations, preferences,
qualifications, limitations, restrictions and special or relative rights of
shares of any series of Preferred Stock. The Board of Directors could, without
stockholder approval, issue Preferred Stock with voting rights and other rights
that could adversely affect the voting power of holders of Common Stock and
could be used to prevent a third party from acquiring control of the Company.
The Company has no present plans to issue any shares of Preferred Stock.
SPECIAL PROVISIONS OF THE CERTIFICATE OF INCORPORATION AND DELAWARE LAW
Limitation of Director Liability. Section 102(b)(7) of the Delaware General
Corporation Law ("Section 102(b)") authorizes corporations to limit or to
eliminate the personal liability of directors to corporations and their
stockholders for monetary damages for breach of directors' fiduciary duty of
care. Although Section 102(b) does not change directors' duty of care, it
enables corporations to limit available relief to equitable remedies such as
injunction or rescission. The Certificate of Incorporation limits the liability
of directors to the Company or its stockholders to the full extent permitted by
Section 102(b). Specifically, directors of the Company will not be personally
liable for monetary damages for breach of a director's fiduciary duty as a
director, except for liability: (i) for any breach of the director's duty of
loyalty to the Company or its stockholders, (ii) for acts or omissions not in
good faith or
57
<PAGE> 58
that involve intentional misconduct or a knowing violation of law, (iii) for
unlawful payments of dividends or unlawful stock repurchases or redemptions as
provided in Section 174 of the Delaware General Corporation Law, or (iv) for any
transaction from which the director derived an improper personal benefit.
Indemnification. To the maximum extent permitted by law, the Bylaws provide
for mandatory indemnification of directors and officers of the Company against
all expense, liability and loss to which they may become subject, or which they
may incur as a result of being or having been a director or officer of the
Company. In addition, the Company must advance or reimburse directors and
officers for expenses incurred by them in connection with indemnification
claims.
Delaware Anti-Takeover Law. Section 203 of the Delaware General Corporation
Law ("Section 203") generally provides that a person who, together with
affiliates and associates owns, or within three years did own, at least 15% but
less than 85% of the outstanding voting stock of a corporation subject to the
statute (an "Interested Stockholder") may not engage in certain business
combinations with the corporation for a period of three years after the date on
which the person became an Interested Stockholder unless (i) prior to such date,
the corporation's board of directors approved either the business combination or
the transaction in which the stockholder became an Interested Stockholder or
(ii) subsequent to such date, the business combination is approved by the
corporation's board of directors and authorized at a stockholders' meeting by a
vote of at least two-thirds of the corporation's outstanding voting stock not
owned by the Interested Stockholder. Section 203 defines the term "business
combination" to encompass a wide variety of transactions with or caused by an
Interested Stockholder, including mergers, asset sales, and other transactions
in which the Interested Stockholder receives or could receive a benefit on other
than a pro rata basis with other stockholders.
The provisions of Section 203, combined with the staggered election of
directors and the Board's authority to issue Preferred Stock without further
stockholder action, could delay or frustrate the removal of incumbent directors
or a change in control of the Company. The provisions also could discourage,
impede or prevent a merger, tender offer or proxy contest, even if such event
would be favorable to the interests of stockholders. The Company's stockholders,
by adopting an amendment to the Certificate of Incorporation, may elect not to
be governed by Section 203 which election would be effective 12 months after
such adoption. Neither the Certificate of Incorporation nor the Bylaws exclude
the Company from the restrictions imposed by Section 203.
REGISTRATION RIGHTS
The warrants to acquire 435,000 shares of Common Stock from the Company at
a price of $45.00 per share issued to MidAmerican Capital Company ("MidAmerican
Capital") in connection with the Medallion Acquisition carry certain rights with
respect to registration under the Securities Act of the shares of Common Stock
underlying such warrants. In general, MidAmerican Capital has one "demand"
registration under which the Company will be obligated to file, and use its best
efforts to cause to be declared effective, a registration statement with respect
to the resale by MidAmerican of shares of Common Stock acquired pursuant to the
warrants. In addition, MidAmerican Capital has rights to two "piggyback"
registrations in the event the Company proposes to register with the SEC an
underwritten public sale of any shares of Common Stock. These rights expire at
such time as MidAmerican Capital is able to sell its shares of Common Stock
without restriction under the Securities Act and are subject to certain
conditions and limitations, including the right of the underwriters of an
offering to limit the number of shares Medallion may include in a registration
pursuant to its piggyback rights. The Company is obligated to bear all expenses
in connection with the registration, except underwriting discount and
commissions with respect to the Common Stock being registered.
TRANSFER AGENT
The Company's transfer agent and registrar for the Common Stock is
Registrar and Transfer Company, Cranford, New Jersey.
58
<PAGE> 59
UNDERWRITING
Subject to the terms and conditions set forth in the U.S. Underwriting
Agreement among the Company and Salomon Brothers Inc, Donaldson, Lufkin &
Jenrette Securities Corporation, Prudential Securities Incorporated, Morgan
Keegan & Company, Inc. and Southcoast Capital Corporation, as representatives of
the several underwriters (the "U.S. Representatives"), the Company has agreed to
sell to the entities named below (the "U.S. Underwriters"), and each of the U.S.
Underwriters has severally agreed to purchase from the Company, the aggregate
number of shares of Common Stock set forth opposite its name below.
<TABLE>
<CAPTION>
NUMBER
U.S. UNDERWRITERS OF SHARES
----------------- ---------
<S> <C>
Salomon Brothers Inc ....................................... 576,000
Donaldson, Lufkin & Jenrette Securities Corporation ........ 480,000
Prudential Securities Incorporated.......................... 480,000
Morgan Keegan & Company, Inc. .............................. 192,000
Southcoast Capital Corporation.............................. 192,000
PaineWebber Incorporated.................................... 80,000
Smith Barney Inc............................................ 80,000
Dominick & Dominick, Incorporated........................... 64,000
Johnson Rice & Company L.L.C................................ 64,000
Nesbitt Burns Securities Inc................................ 64,000
Rauscher Pierce Refsnes, Inc................................ 64,000
Sanders Morris Mundy Inc.................................... 64,000
---------
Total............................................. 2,400,000
=========
</TABLE>
The U.S. Underwriting Agreement provides that the several U.S. Underwriters
will be obligated to purchase all the shares of Common Stock being offered
(other than the shares covered by the over-allotment option described below), if
any are purchased.
The U.S. Representatives have advised the Company that they propose
initially to offer the Common Stock directly to the public at the public
offering price set forth on the cover page of this Prospectus and to certain
dealers at such price less a concession not in excess of $1.08 per share. The
U.S. Underwriters may allow, and such dealers may reallow, a concession not in
excess of $0.10 per share on sales to certain other dealers. After the initial
offering, the price to public and concessions to dealers may be changed.
The Company has entered into an International Underwriting Agreement with
the International Underwriters named therein, for whom Salomon Brothers
International Limited, Donaldson, Lufkin & Jenrette Securities Corporation,
Prudential-Bache Securities (U.K.) Inc., Morgan Keegan & Company, Inc. and
Southcoast Capital Corporation are acting as representatives (the "International
Representatives"), providing for the concurrent offer and sale of 600,000 shares
of Common Stock outside of the United States and Canada.
The initial public offering price and underwriting discount per share for
the U.S. Offering and the International Offering will be identical. The closing
of the U.S. Offering is conditioned upon the closing of the International
Offering, and the closing of the International Offering is conditioned upon the
closing of the U.S. Offering.
Each U.S. Underwriter has severally agreed that, as part of the
distribution of the U.S. Offering, (i) it is not purchasing any shares of Common
Stock for the account of anyone other than a United States or Canadian Person
and (ii) it has not offered or sold, and will not offer or sell, directly or
indirectly, any shares of Common Stock or distribute this Prospectus to any
person outside the United States or Canada or to anyone other than a United
States or Canadian Person. Each International Underwriter has severally agreed
that, as part of the distribution of the International Offering, (i) it is not
purchasing any shares of
59
<PAGE> 60
Common Stock for the account of any United States or Canadian Person, and
(ii) it has not offered or sold, and will not offer or sell, directly or
indirectly, any shares of Common Stock or distribute any Prospectus related to
the International Offering to any person within the United States or Canada or
to any United States or Canadian Person. The foregoing limitations do not apply
to stabilization transactions or to certain other transactions specified in the
Agreement Between U.S. Underwriters and International Underwriters. "United
States or Canadian Person" means any person who is a national citizen or
resident of the United States or Canada, any corporation, partnership or other
entity created or organized in or under the laws of the United States or Canada,
or any political subdivision thereof, any estate or trust the income of which is
subject to United States or Canadian federal income taxation, regardless of the
source of its income (other than a foreign branch of any United States or
Canadian Person), and includes any United States or Canadian branch or a person
other than a United States or Canadian Person.
Each U.S. Underwriter that will offer or sell shares of Common Stock in
Canada as part of the distribution has severally agreed that such offers and
sales will be made only pursuant to an exemption from the prospectus
requirements in each jurisdiction in Canada in which such offers and sales are
made.
Pursuant to the Agreement Between U.S. Underwriters and International
Underwriters, sales may be made between the U.S. Underwriters and the
International Underwriters of such number of shares of Common Stock as may be
mutually agreed. The price of any shares of Common Stock so sold shall be the
initial public offering price, less an amount not greater than the concession to
securities dealers. To the extent that there are sales between U.S. Underwriters
and the International Underwriters pursuant to the Agreement Between U.S.
Underwriters and International Underwriters, the number of shares initially
available for sale by the U.S. Underwriters or by the International Underwriters
may be more or less than the amount appearing on the cover page of this
Prospectus.
The Company has granted to the U.S. Underwriters and the International
Underwriters options to purchase up to an additional aggregate of 360,000 and
90,000 shares of Common Stock, respectively, at the price to public less the
underwriting discount set forth on the cover page of this Prospectus, solely to
cover over-allotments, if any, incurred in the sale of shares of Common Stock
being offered hereby. Either or both options may be exercised at any time up to
30 days after the date of this Prospectus. To the extent that the U.S.
Underwriters and the International Underwriters exercise such options, each of
the U.S. Underwriters or International Underwriters, as the case may be, will be
obligated, subject to certain conditions, to purchase a number of option shares
proportionate to such U.S. Underwriter's or International Underwriter's initial
commitment.
For a period of 90 days after the date of this Prospectus, the Company and
each director and executive officer of the Company have agreed not to offer,
sell, contract to sell or otherwise dispose of any shares of Common Stock, any
other capital stock of the Company or any security convertible into or
exercisable or exchangeable for Common Stock or any such other capital stock
without the prior written consent of Salomon Brothers Inc, except that (i) the
Company may issue securities pursuant to the Company's stock option or other
benefit or incentive plans maintained for its officers, directors or employees,
and (ii) the Company may issue up to 435,000 shares of Common Stock upon
exercise of warrants issued in the Medallion Acquisition.
No action has been taken or will be taken in any jurisdiction by the
Company or the U.S. Underwriters that would permit a public offering of the
shares offered hereby in any jurisdiction where action for that purpose is
required, other than the United States. Persons who come into possession of this
Prospectus are required by the Company and the U.S. Underwriters to inform
themselves about and to observe any restrictions as to the Offering of the
Shares offered hereby and the distribution of this Prospectus.
The Company has agreed to indemnify the U.S. Underwriters against certain
civil liabilities, including certain liabilities under the Securities Act, or
contribute to payments the U.S. Underwriters may be required to make in respect
thereof.
60
<PAGE> 61
CERTAIN LEGAL MATTERS
The validity of the issuance of the shares of Common Stock offered hereby
will be passed upon for the Company by Mayor, Day, Caldwell & Keeton, L.L.P.,
Houston, Texas. Certain legal matters relating to the sale of such Common Stock
will be passed upon for the Underwriters by Vinson & Elkins L.L.P., Houston,
Texas.
ACCOUNTANTS
The audited Consolidated Financial Statements and schedules of the Company
included or incorporated by reference in this Prospectus and elsewhere in the
Registration Statement have been audited by Arthur Andersen LLP, independent
public accountants, as indicated in their reports with respect thereto, and are
included herein in reliance upon said firm as experts in giving said reports.
The audited Combined Financial Statements of the InterCoast Entities
included in this Prospectus and elsewhere in the Registration Statement have
been audited by Arthur Andersen LLP, independent public accountants, as
indicated in their report with respect thereto, and are included herein in
reliance upon said firm as experts in giving said report.
The audited Statement of Revenues and Direct Operating Expenses of the
Sawyer Canyon Properties included in this Prospectus and elsewhere in the
Registration Statement have been audited by Arthur Andersen LLP, independent
public accountants, as indicated in their report with respect thereto, and are
included herein in reliance upon said firm as experts in giving said report.
RESERVE ENGINEERS
Information set forth in this Prospectus relating to the Company's
estimated proved oil and gas reserves not attributable to its VPP program or its
working interest reserves in the Niagaran Reef trend in Michigan (approximately
1% of total proved reserves) at June 30, 1996, the related calculations of
future net production revenues and the net present value thereof have been
derived from independent reserve engineering reports prepared for the Company by
Ryder Scott Company (the Medallion Acquisition), H.J. Gruy and Associates, Inc.
(the Rocky Mountain Acquisition) and R.A. Lenser and Associates, Inc. (the
onshore Gulf Coast properties), and all such information has been included in
reliance on the authority of such firms as experts regarding the matters
contained in their reports.
Although reserve engineers' reports with respect to reserves underlying the
Company's VPP program are utilized by the Company to support its own analysis of
such reserves, the proved reserves, related future net revenues and PV-10 that
the Company reports with respect to volumetric production payments are not
derived from independent reserve engineers' report, but rather are taken
directly from the amounts contracted for, pursuant to the agreements relating to
each volumetric production payment (which amounts are less than the net interest
production reflected in the reserve reports). A report prepared for the Company
by Ryder Scott Company (covering the VPP program properties owned by the Company
in the offshore Gulf Coast region) includes all the reserves of each field from
which the Company's VPP interest is taken.
AVAILABLE INFORMATION
The Company has filed with the SEC a registration statement on Form S-3
(the "Registration Statement"), which term encompasses all amendments, exhibits,
annexes and schedules thereto under the Securities Act, with respect to the
Common Stock offered hereby. This Prospectus which constitutes a part of the
Registration Statement, does not contain all the information set forth in the
Registration Statement, to which reference is hereby made. Statements made in
this Prospectus as to the contents of any contract, agreement or other document
referred to are not necessarily complete. With respect to each such contract,
agreement or other document filed as an exhibit to the Registration Statement
and
61
<PAGE> 62
the exhibits thereto, reference is hereby made to the exhibit for a more
complete description of the matter involved, and each statement made herein
shall be deemed qualified in its entirety by such reference.
The Company is subject to the informational requirements of the Exchange
Act, and in accordance therewith files reports, proxy statements and other
information with the SEC. Such reports, proxy statements and other information
filed by the Company may be inspected and copied at the public reference
facilities maintained by the SEC, 450 Fifth Street, N.W., Judiciary Plaza,
Washington, D.C. 20549; and at the following regional offices of the SEC: 7
World Trade Center, Suite 1300, New York, New York 10048; and CitiCorp Center,
500 West Madison Street, Chicago, Illinois 60661. Copies of such material can
also be obtained from the Public Reference Section of the SEC at 450 Fifth
Street, N.W., Judiciary Plaza, Washington, D.C. 20549, at prescribed rates. The
SEC maintains an Internet web site that contains reports, proxy and information
statements and other information regarding registrants that file electronically
with the SEC (http:\\www.sec.gov). The Common Stock is traded on the New York
Stock Exchange. The Company's reports, proxy statements and other information
concerning the Company can be inspected and copied at the offices of the New
York Stock Exchange, 20 Broad Street, New York, New York 10005.
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
The Company's (i) Annual Report on Form 10-K for the year ended December
31, 1995, (ii) Quarterly Report on Form 10-Q for the three months ended March
31, 1996, (iii) Quarterly Report on Form 10-Q for the three months ended June
30, 1996, (iv) Quarterly Report on Form 10-Q for the three months ended
September 30, 1996, (v) Current Report on Form 8-K dated January 25, 1996 (filed
January 29, 1996), (vi) Current Report on Form 8-K dated April 18, 1996 (filed
on April 19, 1996), (vii) Current Report on Form 8-K dated August 16, 1996
(filed August 21, 1996) (viii) Current Report on Form 8-K dated October 17, 1996
(filed on November 5, 1996), (ix) Amendment No. 1 to Current Report on Form 8-K
dated October 17, 1996 (filed on November 15, 1996) (x) Current Report on Form
8-K dated November 25, 1996 (filed on November 25, 1996), (xi) Current Report on
Form 8-K dated December 24, 1996 (filed on December 26, 1996) and (xii)
Amendment No. 2 to Current Report on Form 8-K dated October 17, 1996 (filed
January 9, 1997) are incorporated into this Prospectus by reference.
Each document filed by the Company pursuant to Section 13(a), 13(c), 14 or
15(d) of the Exchange Act, subsequent to the date of this Prospectus and prior
to the termination of the offering of Common Stock made hereby shall be deemed
to be incorporated herein by reference and to be a part hereof from the date of
filing of such document. Any statement contained herein or in a document all or
a portion of which is incorporated or deemed to be incorporated by reference
herein shall be deemed to be modified or superseded for purposes of this
Prospectus to the extent that a statement contained herein or in any
subsequently filed document which also is or is deemed to be incorporated by
reference herein modifies or supersedes such statement. Any statement so
modified or superseded shall not be deemed, except as so modified or superseded,
to constitute a part of this Prospectus.
The Company will provide without charge to each person to whom a copy of
this Prospectus is delivered, on the request of any such person, a copy of any
or all of the foregoing documents incorporated herein by reference (other than
exhibits to such documents, unless such exhibits are specifically incorporated
by reference into such documents). Requests should be directed to the Company at
379 Thornall Street, Edison, New Jersey 08837, Attention: Corporate Secretary
(telephone: (908) 632-1770).
62
<PAGE> 63
GLOSSARY
The following are abbreviations and definitions of terms used throughout
this Prospectus.
Acquisition Cost. An amount per Mcfe equal to the total purchase price paid
divided by the estimated proved reserves acquired.
bbl. Barrel of 42 U.S. gallons of crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet.
Bcfe. Billion feet of natural gas equivalent.
Btu. British thermal unit, which is the quantity of heat required to raise
the temperature of one pound of water from 58.5 to 59.5 degrees Fahrenheit.
Completion. Installation of permanent equipment for the production of oil
or gas.
Condensate. Hydrocarbon mixture that becomes liquid and separates from
natural gas when the natural gas is produced. Similar to crude oil.
Development location. A location on which a development well can be
drilled.
Development well. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive in an
attempt to recover proved undeveloped reserves.
EBITDA. EBITDA represents income before depletion, depreciation,
amortization, interest expense, interest and other income and income taxes.
EBITDA is a financial measure commonly used in the Company's industry and should
not be considered in isolation or as a substitute for net income, cash flow
provided by operating activities or other income or cash flow data prepared in
accordance with generally accepted accounting principles or as a measure of a
company's profitability or liquidity.
Extensional Infill Drilling ("EID"). Drilling of a well to enhance the
economic recovery of oil and gas in producing areas to a level greater than that
previously achieved by the owners of the prevailing leasehold by increasing the
density of wells that penetrate known reservoirs. Typically, development of
these prospects requires rights to drill on acreage that is held by production.
Exploratory well. A well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field which contains other
productive oil or gas reservoirs.
Finding Cost. An amount per Mcfe equal to the sum of all costs incurred
relating to oil and gas property acquisition, exploration and development
activities divided by the sum of all additions and revisions to estimated proved
reserves, including reserve purchases.
Mcf equivalent ("Mcfe"). Mcf of natural gas equivalent, determined using
the ratio of one bbl of crude oil, condensate or natural gas liquids to six Mcf
of natural gas.
Gross acres or gross wells. An acre or well in which a working interest is
owned.
Mbbl. One thousand barrels of crude oil or other liquid hydrocarbons.
MMbbl. One million barrels of crude oil or other liquid hydrocarbons.
MBtu. One thousand Btus.
MMBtu. One million Btus.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet of natural gas equivalent.
MMcf. One million cubic feet.
MMcfe. One million cubic feet of natural gas equivalent.
63
<PAGE> 64
Net acres or net wells. The sum of the fractional working interests net to
the Company owned in gross acres or gross wells.
Net production. Production after royalties and production due others.
Overriding royalty interest. An interest in an oil and gas property
entitling the owner to a share of oil or gas production, free of costs of
production.
Pre-tax present value of estimated future net revenues ("PV-10"). Estimated
future net revenues before income taxes with no price or cost escalation or
deescalation, in accordance with guidelines promulgated by the SEC and
discounted using an annual discount rate of 10%.
Productive well. A well that is producing oil or gas or that is capable of
production.
Proved developed reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Proved reserves. 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.
Proved undeveloped reserves. 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.
Recompletion. The completion for production of an existing wellbore in
another formation from that in which the well has previously been completed.
Reserve life. Calculation derived by dividing year-end reserves by total
production in that year.
Reserve replacement. Calculation derived by dividing gross additions to
reserves in a year by total production in that year.
Section 29 tax credit. The Section 29 tax credit is an income tax credit
against regular federal income tax liability with respect to sales of natural
gas produced from tight gas sand formations, subject to a number of limitations.
Fuels qualifying for the Section 29 tax credit must be produced from a well
drilled or a facility placed in service after November 5, 1990 and before
January 1, 1993, and be sold before January 1, 2003.
Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas regardless of whether such acreage contains proved reserves.
Working interest. The operating interest which gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
the production.
Workover. Operations on a producing well to restore or increase production.
64
<PAGE> 65
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<S> <C>
KCS Energy, Inc. and Subsidiaries
Report of Independent Public Accountants............................................ F-2
Statements of Consolidated Income for the years ended December 31, 1993, 1994 and
1995 and for the nine months ended September 30, 1995 and 1996 (unaudited)....... F-3
Consolidated Balance Sheets at December 31, 1994 and 1995 and September 30, 1996
(unaudited)...................................................................... F-4
Statements of Consolidated Stockholders' Equity for the years ended December 31,
1993, 1994 and 1995 and for the nine months ended September 30, 1996
(unaudited)...................................................................... F-5
Statements of Consolidated Cash Flows for the years ended December 31, 1993, 1994
and 1995 and for the nine months ended September 30, 1995 and 1996 (unaudited)... F-6
Notes to Consolidated Financial Statements.......................................... F-7
InterCoast Entities (Medallion)
Report of Independent Public Accountants............................................ F-26
Combined Statements of Income for the years ended December 31, 1993, 1994 and 1995
and for the nine months ended September 30, 1995 and 1996 (unaudited)............ F-27
Combined Balance Sheets at December 31, 1994 and 1995 and September 30, 1996
(unaudited)...................................................................... F-28
Combined Statements of Stockholders' Equity for the years ended December 31, 1993,
1994 and 1995 and for the nine months ended September 30, 1996 (unaudited)....... F-29
Combined Statements of Cash Flows for the years ended December 31, 1993, 1994 and
1995 and for the nine months ended September 30, 1995 and 1996 (unaudited)....... F-30
Notes to Combined Financial Statements.............................................. F-31
Sawyer Canyon Properties
Report of Independent Public Accountants............................................ F-42
Statements of Revenues and Direct Operating Expenses for the years ended December
31, 1994 and 1995 and for the three months ended March 31, 1996 (unaudited)...... F-43
Notes to Statements of Revenues and Direct Operating Expenses....................... F-44
</TABLE>
F-1
<PAGE> 66
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To KCS Energy, Inc.:
We have audited the accompanying consolidated balance sheets of KCS Energy,
Inc. (a Delaware Corporation) and subsidiaries as of December 31, 1994 and 1995,
and the related statements of consolidated income, stockholders' equity and cash
flows for each of the three years in the period ended December 31, 1995. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. 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 financial position of KCS Energy, Inc. and
subsidiaries as of December 31, 1994 and 1995, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1995 in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
New York, New York
February 29, 1996
F-2
<PAGE> 67
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
FOR THE NINE MONTHS
ENDED,
FOR THE YEARS ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------------ -----------------------
1993 1994 1995 1995 1996
---------- ---------- ---------- ---------- ----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenue........................ $ 304,289 $ 341,713 $ 449,965 $ 332,274 $ 316,604
Operating costs and expenses
Cost of gas sales............ 253,435 265,076 356,186 264,097 231,063
Other operating and
administrative expenses... 15,018 18,285 18,669 12,950 19,427
Depreciation, depletion and
amortization.............. 8,036 19,740 39,209 29,299 33,933
---------- ---------- ---------- ---------- ----------
Operating costs and
expenses................ 276,489 303,101 414,064 306,346 284,423
---------- ---------- ---------- ---------- ----------
Operating income.......... 27,800 38,612 35,901 25,928 32,181
Interest and other income,
net.......................... 704 1,039 3,713 2,311 4,850
Interest expense............... (1,983) (2,938) (7,732) (4,912) (13,858)
---------- ---------- ---------- ---------- ----------
Income before income taxes..... 26,521 36,713 31,882 23,327 23,173
Federal and state income
taxes........................ 7,910 12,556 10,576 7,645 8,367
---------- ---------- ---------- ---------- ----------
Net income................ $ 18,611 $ 24,157 $ 21,306 $ 15,682 $ 14,806
========== ========== ========== ========== ==========
Earnings per share of common
stock and common stock
equivalents.................. $ 1.60 $ 2.05 $ 1.81 $ 1.33 $ 1.25
========== ========== ========== ========== ==========
Average shares of common stock
and common stock equivalents
outstanding.................. 11,658,370 11,804,989 11,760,701 11,766,011 11,886,434
========== ========== ========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-3
<PAGE> 68
KCS ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------
1994 1995
-------- -------- SEPTEMBER 30,
1996
------------
(UNAUDITED)
<S> <C> <C> <C>
ASSETS
Current assets
Cash and cash equivalents........................................ $ 988 $ 5,846 $ 53,597
Trade accounts receivable, less allowance for doubtful
accounts -- 1994, $305; 1995, $415 and September 30, 1996,
$858.......................................................... 46,380 58,052 39,146
Receivable from Tennessee Gas.................................... 13,569 56,437 --
Fuel inventories................................................. 2,509 782 884
Other current assets............................................. 4,148 3,374 5,055
------- ------- -------
Current assets................................................ 67,594 124,491 98,682
Property, plant and equipment
Oil and gas properties, full cost method, less accumulated
DD&A -- 1994, $49,077; 1995, $86,936 and September 30, 1996,
$119,775...................................................... 125,621 204,958 206,308
Natural gas transportation systems, at cost less accumulated
depreciation -- 1994, $3,480; 1995, $4,285 and September 30,
1996, $5,156.................................................. 17,315 22,345 22,296
Other property, plant and equipment, at cost less accumulated
depreciation -- 1994, $1,681; 1995, $1,472 and September 30,
1996, $1,866.................................................. 1,468 2,013 2,979
------- ------- -------
Property, plant and equipment, net................................. 144,404 229,316 231,583
Investments and other assets....................................... 2,425 6,802 10,887
------- ------- -------
$214,423 $360,609 $ 341,152
======= ======= =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Current maturities of long-term debt............................. $ 1,035 $ -- $ --
Accounts payable................................................. 44,172 59,475 34,680
Accrued liabilities.............................................. 6,172 4,926 7,032
------- ------- -------
Current liabilities.............................................. 51,379 64,401 41,712
Deferred credits and other liabilities
Deferred federal and state income taxes.......................... 17,069 26,172 30,367
Other............................................................ 3,337 2,931 2,931
------- ------- -------
Deferred credits and other liabilities............................. 20,406 29,103 33,298
Long-term debt..................................................... 61,970 165,529 149,830
Commitments and contingencies
Preferred stock, authorized 5,000,000 shares -- unissued........... -- -- --
Stockholders' equity
Common stock, par value $0.01 per share, authorized 50,000,000
shares issued 12,344,278 and 12,379,885, at December 31, 1994
and 1995, respectively, and 12,488,120 shares issued at
September 30, 1996............................................ 123 124 125
Additional paid-in capital....................................... 23,895 24,910 25,997
Retained earnings................................................ 59,885 79,814 93,578
Less treasury stock, 890,248 and 892,748 shares, at December 31,
1994 and 1995, respectively, and 900,748 at September 30,
1996.......................................................... (3,235) (3,272) (3,388)
------- ------- -------
Total stockholders' equity.................................... 80,668 101,576 116,312
------- ------- -------
$214,423 $360,609 $ 341,152
======= ======= =======
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-4
<PAGE> 69
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY
(DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
ADDITIONAL
COMMON PAID-IN RETAINED TREASURY STOCKHOLDERS'
STOCK CAPITAL EARNINGS STOCK EQUITY
------ ---------- -------- -------- -------------
<S> <C> <C> <C> <C> <C>
Balance at December 31, 1992.......... $116 $ 12,618 $18,825 $(1,326 ) $ 30,233
Stock issuances
-- option and benefit plans......... 4 1,019 -- -- 1,023
-- acquisitions..................... 3 6,176 -- -- 6,179
Tax benefit on stock option
exercises........................... -- 3,473 -- -- 3,473
Net income............................ -- -- 18,611 -- 18,611
Dividends ($0.06 per share)........... -- -- (675 ) -- (675)
---- ------- ------- ------- --------
Balance at December 31, 1993.......... 123 23,286 36,761 (1,326 ) 58,844
Stock issuances -- option and benefit
plans............................... -- 380 -- -- 380
Tax benefit on stock option
exercises........................... -- 229 -- -- 229
Net income............................ -- -- 24,157 -- 24,157
Dividends ($0.09 per share)........... -- -- (1,033 ) -- (1,033)
Purchase of treasury stock............ -- -- -- (1,909 ) (1,909)
---- ------- ------- ------- --------
Balance at December 31, 1994.......... 123 23,895 59,885 (3,235 ) 80,668
Stock issuances -- option and benefit
plans............................... 1 188 -- -- 189
Tax benefit on stock option
exercises........................... -- 201 -- -- 201
Stock warrants issued................. -- 626 -- -- 626
Net income............................ -- -- 21,306 -- 21,306
Dividends ($0.12 per share)........... -- -- (1,377 ) -- (1,377)
Purchase of treasury stock............ -- -- -- (37 ) (37)
---- ------- ------- ------- --------
Balance at December 31, 1995.......... 124 24,910 79,814 (3,272 ) 101,576
Stock issuances -- option and benefit
plans............................... 1 520 -- -- 521
Tax benefit on stock option
exercises........................... -- 567 -- -- 567
Net income............................ -- -- 14,806 -- 14,806
Dividends ($0.09 per share)........... -- -- (1,042 ) -- (1,042)
Purchase of treasury stock............ -- -- -- (116 ) (116)
---- ------- ------- ------- --------
Balance at September 30, 1996
(unaudited)......................... $125 $ 25,997 $93,578 $(3,388 ) $ 116,312
==== ======= ======= ======= ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-5
<PAGE> 70
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
FOR THE NINE MONTHS
FOR THE YEARS ENDED DECEMBER 31, ENDED SEPTEMBER 30,
----------------------------------- ---------------------
1993 1994 1995 1995 1996
-------- -------- --------- ------- ---------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Cash flows from operating activities:
Net income............................ $ 18,611 $ 24,157 $ 21,306 $15,682 $ 14,806
Non-cash charges (credits)
Depreciation, depletion and
amortization..................... 8,036 19,740 39,209 29,299 33,933
Deferred income taxes.............. 1,440 10,896 9,756 7,441 4,195
Other non-cash charges and credits,
net.............................. (559) (65) 820 1,315 1,248
-------- -------- --------- -------- ---------
27,528 54,728 71,091 53,737 54,182
Net changes is assets and liabilities:
Trade accounts receivable.......... (36,153) 19,107 (11,672) (714) 18,906
Receivable from Tennessee Gas...... -- (13,569) (42,868) (32,613) 56,437
Fuel inventories................... (417) (1,126) 1,727 1,303 (102)
Other current assets............... 138 (1,299) 490 (1,178) (1,681)
Accounts payable and accrued
liabilities...................... 29,023 (10,724) 14,163 6,735 (22,689)
Federal and state income taxes..... 1,615 (119) 178 (1,623) (1,419)
Other, net......................... (311) 3,118 (2,999) 3,014 1,493
-------- -------- --------- -------- ---------
Net cash provided by operating
activities............................ 21,423 50,116 30,110 28,661 105,127
Cash flows from investing activities:
Investment in oil and gas
properties......................... (36,420) (73,682) (121,265) (52,953) (50,552)
Proceeds from the sale of oil and gas
properties......................... -- -- 4,069 5,524 16,384
Investment in natural gas
transportation systems............. (1,512) (700) (5,969) (3,681) (843)
Investment in other property, plant
and equipment...................... (344) (571) (1,465) (821) (1,340)
-------- -------- --------- -------- ---------
Net cash used in investing activities... (38,276) (74,953) (124,630) (51,931) (36,351)
Cash flows from financing activities:
Proceeds from long-term debt.......... 18,000 49,431 141,298 51,369 165,145
Repayments of long-term debt.......... (3,956) (26,247) (38,774) (23,574) (180,900)
Issuance of common stock.............. 1,023 380 189 222 521
Issuance of stock warrants............ -- -- 626 -- --
Tax benefit on stock option
exercises.......................... 3,473 229 201 124 567
Purchase of treasury stock............ -- (1,909) (37) (37) (116)
Dividends paid........................ (554) (919) (1,377) (1,033) (1,042)
Deferred financing costs and other,
net................................ (56) (509) (2,748) (602) (5,200)
-------- -------- --------- -------- ---------
Net cash provided by (used in) financing
activities............................ 17,930 20,456 99,378 26,469 (21,025)
-------- -------- --------- -------- ---------
Increase (decrease) in cash and cash
equivalents........................... 1,077 (4,381) 4,858 3,199 47,751
Cash and cash equivalents at beginning
of year............................... 4,292 5,369 988 988 5,846
-------- -------- --------- -------- ---------
Cash and cash equivalents at end of
year.................................. $ 5,369 $ 988 $ 5,846 $ 4,187 $ 53,597
======== ======== ========= ======== =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-6
<PAGE> 71
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
KCS Energy, Inc. is principally engaged in the acquisition, exploration,
development and production of natural gas and crude oil. The Company also
operates natural gas transportation and energy marketing and services
businesses.
Recapitalization (Quasi-reorganization)
At September 30, 1988, prior to the start of the Company's first full year
of operations as a separate legal entity with independent management, an amount
equal to the cumulative retained earnings deficit of the KCS subsidiaries
($25,109,000) was eliminated against additional paid-in capital in connection
with a quasi-reorganization.
Basis of Presentation
The consolidated financial statements include the accounts of KCS Energy,
Inc. and its wholly owned subsidiaries ("KCS" or "Company"). All significant
intercompany accounts and transactions have been eliminated in consolidation.
Certain previously reported amounts have been reclassified to conform to current
year presentations.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates. The most
significant estimates and assumptions impacting the Company's consolidated
financial statements relate to the Tennessee Gas contract. See Note 7. The
condensed interim financial statements included herein have been prepared by KCS
Energy, Inc., without audit, pursuant to the rules and regulations of the
Securities and Exchange Commission ("SEC") and reflect all adjustments which are
of a normal recurring nature and which, in the opinion of management, are
necessary for a fair statement of the results for interim periods. Certain
information and footnote disclosures have been condensed or omitted pursuant to
such rules and regulations. The results of operations for the interim periods
presented are not necessarily indicative of the results to be expected for the
full year.
Cash Equivalents
The Company considers all highly liquid investments with a maturity of
three months or less when purchased to be cash equivalents.
Futures Contracts
The Company utilizes oil and natural gas futures contracts for the purpose
of hedging the risks associated with fluctuating crude oil and natural gas
prices and accounts for such contracts in accordance with FASB Statement No. 80,
"Accounting for Futures Contracts." These contracts permit settlement by
delivery of commodities and, therefore, are not financial instruments, as
defined by FASB Statement Nos. 107 and 119. At December 31, 1994, the Company's
hedging activities consisted of 760 long contracts at an average price of $1.93
per Mcf and 305 short contracts at an average price of $1.95 per Mcf maturing
through 1995 and 1996, covering 10,650 MMcf of natural gas. At December 31,
1995, the Company's hedging activities consisted of 700 long contracts at an
average price of $1.82 per Mcf and 587 short contracts at an average price of
$1.95 per Mcf maturing through 1996, covering 12,870 MMcf of natural gas. Since
these contracts qualify as hedges and correlate to market price movements of
natural gas, any gains or losses resulting from market changes will be offset by
losses or gains on
F-7
<PAGE> 72
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
corresponding physical transactions. Deferred gains, net of deferred losses,
were $1.4 million at December 31, 1994. Deferred losses, net of deferred gains,
were $0.1 million at December 31, 1995.
Imbalances
The Company follows the entitlements method of accounting for production
imbalances, where revenues are recognized based on its interest in oil and gas
production from a well. Imbalances arise when a purchaser takes delivery of more
or less from a well than the Company's actual interest in the production from
that well. The difference between cash received and revenue recorded is a
receivable or payable. Such imbalances are reduced either by subsequent
balancing of over and under deliveries or by cash settlement, as required by
applicable contracts. Such imbalances were not material at December 31, 1994 or
1995.
Property, Plant and Equipment
The Company follows the full cost method of accounting, under which all
productive and nonproductive costs associated with its exploration, development
and production activities are capitalized in a country-wide cost center. Such
costs include lease acquisitions, geological and geophysical services, drilling,
completion, equipment and certain general and administrative costs directly
associated with acquisition, exploration and development activities. General and
administrative costs related to production and general overhead are expensed as
incurred. The Company provides for depreciation, depletion and amortization of
evaluated costs using the future gross revenue method based on recoverable
reserves valued at current prices. Under accounting procedures prescribed by the
Securities and Exchange Commission capitalized costs may not exceed the present
value of future net revenues from production of proved oil and gas reserves. To
the extent that the capitalized costs exceed the estimated present value of
future net revenues at the end of any fiscal quarter, such excess costs are
written down with a corresponding charge to income.
Depreciation of other property, plant and equipment is provided on a
straight-line basis over the useful lives of the assets, except for certain
natural gas gathering pipelines which are depreciated based on the estimated
lives of the gas wells served. Repairs of all property, plant and equipment and
replacements and renewals of minor items of property are charged to expense, as
incurred.
Income Taxes
The Company accounts for income taxes in accordance with FASB Statement No.
109, "Accounting for Income Taxes." Deferred income taxes reflect the future tax
consequences of differences between the tax bases of assets and liabilities and
their financial reporting amounts at each year end.
For income tax purposes, the Company deducts the difference between market
value and exercise price arising from the exercise of stock options. The tax
effect of this deduction which, for financial reporting purposes, is accounted
for as an increase to additional paid-in capital, amounted to $3,473,000,
$229,000 and $201,000 in 1993, 1994 and 1995, respectively.
Earnings Per Share
Earnings per share have been computed by dividing net earnings by the
weighted average number of common shares outstanding during the periods,
adjusted for the dilutive effects of stock options and warrants.
F-8
<PAGE> 73
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Supplemental Cash Flow Disclosures
The Company acquired certain producing properties during 1993. The related
non-cash investing and financing activities are summarized as follows:
<TABLE>
<CAPTION>
DOLLARS IN
THOUSANDS
----------
<S> <C>
Investment in oil and gas properties..................................... $ (10,179)
Subordinated note payable assumed........................................ 4,000
Issuance of common stock................................................. 6,179
</TABLE>
2. RETIREMENT BENEFIT PLANS
The Company has a trusteed, non-contributory Retirement Plan ("Plan"). The
Plan was amended to freeze the accrual of future benefits as of October 31,
1991. Prior to October 1991, the Plan covered substantially all full-time
employees of KCS and its participating subsidiaries. The Company's funding
policy for the Plan is to make annual contributions that meet the minimum
funding requirements of the Employee Retirement Income Security Act of 1974. The
required contribution was $49,924 in 1993. No contributions were required in
1994 and 1995.
Net periodic pension costs consisted of the following components:
<TABLE>
<CAPTION>
1993 1994 1995
----- ----- ----
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Service cost -- benefits earned during the period......... $ -- $ -- $ --
Interest cost on projected benefit obligation............. 75 66 69
Actual return on plan assets.............................. (360) 78 (4)
Net amortization and deferral............................. 340 (153) (64)
----- ----- ----
Net periodic pension cost (income)........................ $ 55 $ (9) $ 1
===== ===== ====
</TABLE>
The following table sets forth the funded status and amounts recognized in
the consolidated balance sheets at December 31, 1994 and 1995 for the Plan:
<TABLE>
<CAPTION>
1994 1995
------ ------
(DOLLARS IN
THOUSANDS)
<S> <C> <C>
Actuarial present value of benefit obligations:
Vested benefits.............................................. $ 980 $ 969
Non-vested benefits.......................................... 18 --
Accumulated benefit obligation............................... 998 969
Projected benefit obligation................................... 998 969
Market value of plan assets.................................... 1,272 1,157
Excess of plan assets over projected benefit obligation........ 274 188
Unrecognized net loss.......................................... 143 199
Unrecognized net asset at January 1............................ (100) (82)
------ ------
Pension prepayment in the balance sheet........................ $ 317 $ 305
====== ======
</TABLE>
Assumptions used for the 1994 and 1995 actuarial calculations were 7% for
the discount rate and expected long-term return on assets. As a result of the
October 31, 1991 freeze of future benefits, no service costs accrued during the
periods. During 1995, the Company made lump-sum cash payments to
F-9
<PAGE> 74
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
terminated participants which represented a settlement of projected benefit
obligations. Plan assets at December 31, 1995 are invested in both cash
equivalents and KCS Energy, Inc. common stock.
The Board of Directors took action to terminate the Plan effective
September 30, 1995. The Company has filed all required standard termination
applications with both the Internal Revenue Service and the Pension Benefit
Guaranty Corporation. A complete settlement of the Plan's projected benefit
obligations is expected to occur during 1996.
The Company sponsors a Savings and Investment Plan ("Savings Plan") under
Section 401(k) of the Internal Revenue Code. Eligible employees may contribute
up to 16% of their base salary to the Savings Plan subject to certain IRS
limitations. The Company may make matching contributions, which have been set by
the Board of Directors at 50% of the employee's contribution (up to 6% of annual
base compensation) since the inception of the Savings Plan in June 1988. The
Savings Plan also contains a profit-sharing component whereby the Board of
Directors may declare annual discretionary profit-sharing contributions.
Profit-sharing contributions are allocated to each eligible employee. Employee
and profit-sharing contributions 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 fair market value. Company matching contributions are invested in shares of
KCS common stock. Eligible employees vest in both the Company matching and
discretionary profit-sharing contributions over a four-year period based upon
their years of service with the Company. Company contributions to the Savings
Plan were $282,232 in 1993, $293,622 in 1994 and $253,666 in 1995.
SUBSEQUENT INFORMATION (UNAUDITED)
In July 1996, the Company completed the termination of its non-contributory
Retirement Plan and satisfied all obligations thereunder.
3. STOCK OPTION AND INCENTIVE PLANS
The Company has two employee stock option and incentive plans, the 1988
Stock Plan and the 1992 Stock Plan (the "Employee Incentive Plans"). Under the
Employee Incentive Plans, stock options, stock appreciation rights and
restricted stock may be granted to employees of KCS. The 1992 Stock Plan also
provides that bonus stock may be granted to employees.
The 1994 Directors' Stock Plan provides that each non-employee director be
granted stock options for 1,000 shares annually. This plan also provides that in
lieu of cash, each non-employee director be issued KCS stock with a fair market
value equal to 50% of their annual retainer.
Each plan provides that the option price of shares issued be equal to the
market price on the date of grant. All options expire 10 years after the date of
grant. At December 31, 1995, options for 405,500 shares were exercisable.
F-10
<PAGE> 75
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Transactions during the last three years involving stock options under the
above plans are summarized as follows:
<TABLE>
<CAPTION>
NUMBER OF OPTION PRICE
SHARES PER SHARE
--------- -------------
<S> <C> <C>
Options outstanding, December 31, 1992.................. 792,200 $1.21-$ 6.25
1993 -- Granted......................................... 106,700 $22.88
-- Exercised....................................... (419,200) $1.21-$ 6.25
1994 -- Granted......................................... 106,000 $14.50-$26.88
-- Exercised....................................... (32,200) $1.33-$ 6.25
1995 -- Granted......................................... 105,000 $13.00-$16.31
-- Exercised....................................... (22,600) $1.33-$ 1.98
-- Forfeited....................................... (3,100) $22.88-$26.88
------- ------------
Options outstanding, December 31, 1995.................. 632,800 $1.50-$26.88
======= ============
</TABLE>
Restricted shares awarded under the Employee Incentive Plans have a fixed
restriction period during which ownership of the shares cannot be transferred
and the shares are subject to forfeiture if employment terminates. Restricted
stock has the same dividend and voting rights as other common stock and is
considered to be currently issued and outstanding. The cost of the awards,
determined as the fair market value of the shares at the date of grant, is
expensed ratably over the period the restrictions lapse. This cost was
immaterial during the three years ended December 31, 1995. Restricted stock
totaling 11,200 shares was outstanding under the Employee Incentive Plans at
December 31, 1995.
Bonus stock awards under the 1992 Stock Plan convert to shares of
restricted stock if certain three-year performance goals are met. The restricted
stock then vests over a two-year period. The cost of the awards is expensed
ratably based on the current market price of the Company's common stock and the
extent to which the performance goals are being met. This cost amounted to
$200,000 in 1993 and was immaterial in 1994 and 1995. Bonus stock grants
totaling 48,800 shares were outstanding at December 31, 1995.
At December 31, 1995, 49,402 shares were available for future grants
(including bonus stock awards) under the Employee Incentive Plans.
Under the 1988 KCS Energy, Inc. Employee Stock Purchase Program (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 per share
determined by the closing price on the date of purchase. The minimum purchase is
25 shares. The maximum annual purchase is the number of shares costing no more
than 10% of the eligible employee's annual base salary, and for directors, 3,000
shares. The number of shares issued in connection with the Program was 26,845,
7,438 and 6,897 during 1993, 1994 and 1995, respectively. At December 31, 1995,
there were 443,695 shares available for issuance under the Program.
F-11
<PAGE> 76
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
4. LONG-TERM DEBT
Long-term debt consists of the following:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------- SEPTEMBER 30,
Dollars in thousands 1994 1995 1996
------- -------- --------
<S> <C> <C> <C>
(UNAUDITED)
Credit Facility.......................................... $ -- $ -- $ 100
Master Note Facility..................................... 46,400 76,255 --
Receivables Facility..................................... -- 26,900 --
VPP Facility............................................. -- 38,000 --
Note Financing........................................... -- 24,374 --
Revolving credit agreement............................... 15,431 -- --
Subordinated Note Payable................................ 910 -- --
Senior Notes............................................. -- -- 149,434
Other.................................................... -- -- 296
Installment note payable to bank due in equal monthly
installments, with interest at 10.5%................... 264 -- --
------- --------
63,005 165,529 149,830
Less current maturities.................................. 1,035 -- --
------- -------- --------
Long-term debt........................................... $61,970 $165,529 $149,830
======= ======== ========
</TABLE>
SENIOR NOTES
On January 25, 1996, subsequent to the year ended December 31, 1995, KCS
Energy, Inc. (the "Parent") completed a private offering of $150 million senior
notes at an interest rate of 11% due January 15, 2003 (the "Senior Notes"). The
Senior Notes are noncallable for four years and are unsecured obligations of the
Parent. Prior to January 15, 1999, the Parent may use proceeds from a public
equity offering to redeem up to $35 million of the Senior Notes. The
subsidiaries of the Parent have guaranteed the Senior Notes on a senior
unsecured basis. The net proceeds of approximately $145 million were used to
reduce the amounts outstanding under certain of the agreements discussed below.
The Senior Notes contain certain restrictive covenants which, among other
things, limit the Company's ability to incur additional indebtedness, require
the repurchase of the Senior Notes upon a change of control and restrict the
aggregate cash dividends paid to 50% of the Company's cumulative net income
during the period beginning October 1, 1995. Additionally, the Master Note
Facility, Receivables Facility and VPP Facility agreements summarized below were
amended to permit the borrowers under the agreements to guarantee the Senior
Notes and to remove restrictions on subsidiary dividends to the Parent.
On May 8, 1996, the Company commenced an offer (the "Exchange Offer") of up
to $150 million senior notes (the "Exchange Notes") in exchange for the
outstanding Senior Notes, pursuant to a registration statement declared
effective by the Securities and Exchange Commission on May 7. The Exchange Notes
are identical in all material respects to the form and terms of the Senior Notes
except for certain transfer restrictions and registration rights applicable to
the Senior Notes. The Exchange Notes evidenced the same debt, and were issued
under and entitled to the benefits of the same Indenture, as the Senior Notes.
At June 30, 1996, the Company maintained three separate bank credit
facilities to support its operations. The Master Note Facility was utilized
primarily to support the expansion of the Company's exploration and production
and natural gas transportation businesses. The Company's natural gas marketing
subsidiary had two credit facilities, the Receivable Facility and VPP Facility,
which were used
F-12
<PAGE> 77
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
primarily for working capital purposes and to support the acquisition of oil and
gas properties through volumetric production payments.
SUBSEQUENT INFORMATION (UNAUDITED)
In July 1996, the Receivable Facility was paid in full and terminated. On
September 25, 1996, the Company consolidated the Master Note Facility and the
VPP Facility to create one Revolving Credit Facility (the "Credit Facility"),
which will mature on September 30, 2000. The Credit Facility is secured by the
same collateral that was pledged to secure the Master Note and VPP facilities.
The borrowing base under the Credit Facility is a function of the lender's
determination of the value of the Company's oil and gas reserves, and is
currently limited to $75 million under the terms of the Indenture. As of
December 31, 1996, $0.1 million was outstanding under the Credit Facility. The
Credit Facility bears interest at a spread over the prime rate or LIBOR,
determined each quarter based on the Company's consolidated debt-to-EBITDA
ratio. As of January 29, 1997, following the Medallion Acquisition, $74.5
million was outstanding under the Credit Facility.
In October 1996, the Company exercised its option to purchase the Warrant
issued in connection with the Note financing.
Simultaneous with the Medallion Acquisition, the Company entered into a new
revolving credit agreement ("Revolving Credit Agreement") with a group of banks.
Of the Revolving Credit Agreement's $135 million initial borrowing base, $30
million is structured as a term loan with a maturity of March 31, 1997; the
remaining $105 million revolving loan matures on September 30, 2000. The
Company's obligations under the Revolving Credit Agreement are secured by
substantially all of the oil and gas assets of Medallion and a pledge of
Medallion's common stock. The Revolving Credit Agreement permits the Company to
borrow at interest rates based upon the banks' prime rate or LIBOR. The
applicable spread over the prime rate or LIBOR is determined each quarter based
on the Company's consolidated debt-to-EBITDA ratio. As of January 29, 1997,
following the Medallion Acquisition, $90.2 million was outstanding under the
Revolving Credit Agreement.
MASTER NOTE FACILITY
The Master Note Facility ("Facility"), which matures on October 1, 1998, is
used primarily for the expansion of the Company's exploration and production and
natural gas transportation businesses. As such, borrowings under the Facility
are limited to certain KCS subsidiaries ("Borrowers") which are engaged in those
activities. The borrowing base, or actual availability under the Facility,
increased from $64 million at December 31, 1994 to $100 million at December 31,
1995. As of December 31, 1995, $76.3 million was outstanding under the facility
and $11.1 million was reserved pursuant to the existing letters of credit. The
borrowing base is reviewed at least semiannually and may be adjusted based on
the lenders' valuation of the Borrowers' oil and gas reserves, pipeline assets
and other factors. Substantially all of the Borrower's oil and gas reserves
(excluding those acquired through volumetric production payments) and pipeline
assets have been pledged to secure the Facility.
The Facility permits the Borrowers to choose interest rate options based on
the bank's prime rate or LIBOR and from maturities ranging up to three months. A
commitment fee of one-half of one percent is paid on the unused portion of the
borrowing base. The weighted average effective interest rate was 6.13% in 1994
and 7.98% in 1995. As of December 31, 1995, the weighted average effective
interest rate on the borrowings was 8.66%.
Immediately following the sale of the Senior Notes, the Facility was
amended to decrease the borrowing base to $20 million and the amount outstanding
under the Facility was reduced to $2 million and $11.1 million was reserved
pursuant to existing letters of credit.
F-13
<PAGE> 78
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
REVOLVING CREDIT FACILITIES
Revolving Credit Agreement
During 1994, the Company's natural gas marketing subsidiary had a revolving
credit agreement ("Agreement") that was used primarily for working capital
purposes and the purchase of oil and gas reserves through volumetric production
payments and was secured by that subsidiary's trade accounts receivable and
other assets.
The Agreement was replaced with two new revolving credit facilities, the
Receivables Facility and the VPP Facility. At December 31, 1994, $15.4 million
was reflected as outstanding under the Agreement. On January 12, 1995, the
Company paid in full all outstanding balances and terminated the Agreement. The
weighted average effective interest rate was 7.97% in 1994 and 8.87% in 1995.
Receivables Facility
The Receivables Facility matures in June 1997 and is secured by the natural
gas marketing subsidiary's accounts receivables and other assets (excluding
those pledged under the VPP Facility) and a pledge of the natural gas marketing
subsidiary's stock. In August 1995, the maximum credit limit under the
Receivables Facility was increased from the initial $25 million to $35 million.
Under the terms of the Receivables Facility, the subsidiary may borrow the
lesser of the credit limit or the borrowing base supported by Eligible
Receivables, as defined by the lender. The borrowing base is reviewed on a
monthly basis. As of December 31, 1995, the borrowing base and outstanding
balance was $26.9 million.
The Company may choose to borrow funds based on either the lender's "Base
Rate" or the 30-day LIBOR. A commitment fee of one-half of one percent is paid
on the average daily unused portion of the credit limit. The weighted average
effective interest rate was 7.64% in 1995. On December 31, 1995, the weighted
average effective interest rate on outstanding borrowings was 7.60%.
Proceeds from the sale of the Senior Notes were used to decrease the amount
outstanding under the Receivables Facility to $23.4 million. The borrowing base
of the Receivables Facility was unaffected by the sale of the Senior Notes.
VPP Facility
The VPP Facility matures in January 1999 and is secured by all of the oil
and gas reserves purchased through volumetric production payments. The initial
maximum credit commitment under this facility of $25 million was increased in
December 1995 to $50 million and the borrowing base was increased to $38
million. The borrowing base is reviewed at least semiannually and may be subject
to change based upon the lenders' evaluation of the oil and gas reserves and
other factors. The outstanding balance under the VPP Facility was $38 million on
December 31, 1995.
Under the VPP Facility, the Company can request advances based upon either
the prime rate, certificates of deposit rate or LIBOR with maturities ranging up
to three months. A commitment fee of one-half of one percent is paid on the
average daily unused portion of the borrowing base. The weighted average
effective interest rate was 8.17% in 1995. As of December 31, 1995, the weighted
average effective interest rate on outstanding borrowings was 8.11%.
Proceeds from the sale of the Senior Notes were used to decrease the amount
outstanding under the VPP Facility to $1.0 million. The VPP Facility's borrowing
base was unaffected by the sale of the Senior Notes.
F-14
<PAGE> 79
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE FINANCING
On November 17, 1995, the Parent entered into a $25 million Note Financing
Agreement ("Note Financing"), secured by all of the assets of the Parent other
than the capital stock of its marketing subsidiary. The proceeds from the Note
Financing were used to fund the Company's oil and gas property acquisitions and
for general corporate purposes.
The Note Financing, which was paid in full with the proceeds of the Senior
Notes, accrued interest at the rate of 12% per annum.
The Parent also issued to the purchaser under the Note Financing (with an
option to buy back at 150% of the exercise price within 12 months and 175%
between 12 and 24 months) a warrant to purchase 114,683 shares of the Parent's
common stock exercisable at a price of $11.65 per share, subject to adjustment
to prevent dilution. In October 1996, the Company exercised its option to
purchase the warrant issued in connection with the Note financing.
OTHER INFORMATION
KCS Energy, Inc. has guaranteed the obligations of its subsidiaries under
the above agreements. The agreements contain certain restrictive covenants
which, among other things, require the Company to maintain minimum levels of
working capital, cash flow and tangible net worth, as defined in the agreements.
In addition, the Company is restricted from incurring secured indebtedness under
designated credit facilities in an amount which is the greater of $75 million or
15% of adjusted consolidated net tangible assets (as defined in the Indenture).
This restriction does not apply to purchase money indebtedness. The Company's
ability to pay cash dividends is limited by the Indenture and existing credit
facilities.
The Company had a subordinated short-term note payable, which was issued in
conjunction with a 1993 acquisition of producing properties. The balance was
paid in full during fiscal year 1995. This note, payable in monthly
installments, accrued interest at prime plus one percent.
Long-term debt is carried at an amount approximating fair value because its
interest rates are based on current market rates.
Long-term debt due during the fiscal years ending December 31, 1996 to
2000, is as follows: $-0- in 1996, $51,900,000 in 1997, $76,255,000 in 1998,
$38,000,000 in 1999 and $-0- in 2000. Reflecting the issuance of the Senior
Notes on January 25, 1996 and the repayment of amounts outstanding on the Master
Note Facility, the Receivables Facility and the VPP Facility, long-term debt due
during the fiscal years ending December 31, 1996 to 2000, is as follows: $-0- in
1996, $23.4 million in 1997, $2 million in 1998, $1 million in 1999 and $-0-
million in 2000. Interest payments were $1,819,000 in 1993, $2,088,000 in 1994
and $6,757,000 in 1995. Interest payments were $4,406,000 and $10,793,000 for
the nine months ended September 30, 1995 and September 30, 1996, respectively.
5. LEASES
Future minimum lease payments under non-cancelable operating leases are as
follows: $558,000 in 1996, $548,000 in 1997, $537,000 in 1998, $421,000 in 1999
and $337,000 in 2000.
Lease payments charged to operating expenses amounted to $579,000, $598,000
and $466,000 during 1993, 1994 and 1995, respectively.
F-15
<PAGE> 80
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
6. INCOME TAXES
Federal and state income tax expense includes the following components:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER
31,
-------------------------------
1993 1994 1995
------- ------- -------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Currently payable........................................... $ 6,316 $ 1,039 $ 1,216
Deferred provision, net..................................... 1,428 10,692 8,296
Amortization of investment tax credits...................... (73) -- --
------- ------- -------
Federal income tax expense.................................. 7,671 11,731 9,512
State income taxes (deferred provision $12 in 1993, $204 in
1994 and $1,460 in 1995).................................. 239 825 1,064
------- ------- -------
$ 7,910 $12,556 $10,576
======= ======= =======
Sources of deferred federal and state income taxes:
Intangible drilling costs................................. $ 3,708 $10,278 $12,619
Revenue recognition deferred.............................. -- 2,343 1,854
Depreciation, depletion and amortization.................. (814) (1,883) (5,579)
Tax credit carry forwards and other, net.................. (1,454) 158 862
------- ------- -------
$ 1,440 $10,896 $ 9,756
======= ======= =======
Reconciliation of federal income tax expense at statutory
rate to provision for income taxes:
Income before income taxes................................ $26,521 $36,713 $31,882
Tax provision at 35% statutory rate....................... 9,282 12,850 11,159
State income tax, net of federal income tax benefit....... 151 537 692
Statutory depletion....................................... (620) (696) (676)
Section 29 credits........................................ (537) (388) (425)
Other, net................................................ (366) 253 (174)
------- ------- -------
$ 7,910 $12,556 $10,576
======= ======= =======
</TABLE>
The primary differences giving rise to the Company's deferred tax assets
and liabilities are as follows:
<TABLE>
<CAPTION>
DECEMBER 31, 1995
----------------------
ASSETS LIABILITIES
------ -----------
(DOLLARS IN THOUSANDS)
<S> <C> <C>
Income tax effects of:
Accelerated DD&A and other property related items..................... -- $ 24,261
Alternative minimum tax credit carry forwards......................... $3,175 --
Deferred revenue...................................................... -- 4,197
Other, net............................................................ -- 889
------ -------
$3,175 $ 29,347
====== =======
</TABLE>
Income tax payments were $1,729,500 in 1993 and $1,302,000 in 1994. No
income tax payments were made in 1995. The Company received federal incone tax
refunds of $233,000 and $58,000 in 1993 and 1994, respectively, related to
fiscal year 1992 and 1993 overpayments. No income tax payments
F-16
<PAGE> 81
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
were made during the nine months ended September 30, 1995. Income tax payments
were $4,545,000 during the nine months ended September 30, 1996.
The alternative minimum tax credit carryforwards of $3,175,000, which can
be carried forward indefinitely, are available to reduce the Company's future
federal income tax liabilities.
7. CONTINGENCIES
Tennessee Gas Litigation -- Recent Events (unaudited)
Most of the Company's natural gas sold from the Bob West Field in south
Texas was covered by an above-market, take-or-pay contract (the "Tennessee Gas
Contract") with Tennessee Gas Pipeline Company ("Tennessee Gas"), which had been
the subject of several lawsuits. On December 23, 1996, the Company and Tennessee
Gas entered into a settlement covering all claims and litigation between them
related to the Tennessee Gas Contract. As part of the settlement, the Tennessee
Gas Contract was terminated effective January 1, 1997, approximately two years
prior to its expiration date. The parties also agreed to the dismissal of the
contract dispute that resulted in a November 1996 jury award to Tennessee Gas of
$143.2 million (including $114 million in punitive damages). The early
termination of the Tennessee Gas Contract with its above-market pricing
provisions resulted in downward revisions in the amounts of $59.5 million for
estimated future net revenues before income taxes (based upon a natural gas
price of $2.10 per Mcf, the assumed realized spot market price on June 30, 1996)
and $51.4 million for PV-10, as compared to prior reserve reports prepared as of
June 30, 1996. Except for the revisions to future net revenues, the Company's
financial statements will not be directly affected as a result of the settlement
and early termination of the contract.
The December 1996 settlement did not affect the Company's successful
conclusion of litigation earlier in the year relating to the validity and
pricing provisions of the Tennessee Gas Contract and its recovery of past
underpayments (including interest and net of severance taxes and other payables
related to the contract) that had accrued under the contract. On September 30,
1996, Tennessee Gas paid the Company approximately $70 million, representing the
amount of the Tennessee Gas Receivable at that date.
On April 18, 1996 the Texas Supreme Court granted the petitioners' request
for a rehearing, withdrew its August 1, 1995 opinion and issued a new opinion on
the previously disclosed litigation relating to the Tennessee Gas Contract. In
its April 18, 1996 opinion, the Texas Supreme Court affirmed the Company's
position on all issues, stating that the price payable by Tennessee Gas
escalates monthly in accordance with Section 102(b)(2) of the Natural Gas Policy
Act of 1978 ("NGPA") ($8.53 per MMBtu in September 1996 plus reimbursement of
severance taxes); that KCS has the right to pool the leases; that Tennessee Gas
has no legal or contractual right to question or determine whether certain
leases are no longer committed to the Tennessee Gas Contract; and the Tennessee
Gas Contract is not an output contract governed by Section 2.306 of the Texas
Uniform Commercial Code. Tennessee Gas filed a motion requesting another
rehearing on June 3, 1996 and on August 16, 1996 the Texas Supreme Court denied
Tennessee Gas' motion. On September 30, 1996 the Company recovered approximately
$70 million that Tennessee Gas previously withheld under a series of interim
agreements, which was the balance of the purchase price for production taken by
Tennessee Gas from September 17, 1994 through April 30, 1996, plus interest as
provided for in the Tennessee Gas Contract. The terms of the Tennessee Gas
Contract, in accordance with judicial rulings in the case, governed performance
by each of the parties through the termination of the contract effective January
1, 1997.
F-17
<PAGE> 82
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Tennessee Gas Litigation -- Background
In August 1990, in the District Court of Bexar County, Texas ("District
Court"), Tennessee Gas filed suit against the Company and its co-sellers
claiming among other things that the price of natural gas under the Tennessee
Gas Contract should be determined under Section 101 of the NGPA rather than
Section 102(b)(2), that certain leases were no longer subject to the contract,
that for purposes of the contract the acreage subject to the contract could not
be pooled with other properties and that the contract was governed by Section
2.306 of the Texas Uniform Commercial Code ("Section 2.306"). In July 1992, the
District Court ruled in favor of the Company on all of these issues and awarded
damages for past underpayments and legal fees. The District Court's judgment was
partially affirmed by the Court of Appeals, which held that the price of natural
gas under the contract was to be determined in accordance with Section
102(b)(2), that all leases were subject to the contract, and that pooling of the
property with a pro rata acreage allocation of production to the contract was in
accordance with the contract. However, the Court of Appeals reversed the
District Court's summary judgment holding that the Tennessee Gas Contract was
not an output contract subject to Section 2.306. Under the Court of Appeals
decision, new wells could be drilled and production increased, but any
production increase had to have complied with certain good faith and
reasonableness standards mandated by Section 2.306. The Court of Appeals also
set aside the District Court's awards to the Company of legal fees and past
underpayments pending the outcome of the trial on the Section 2.306 issue.
On August 1, 1995, the Texas Supreme Court affirmed the ruling of the Court
of Appeals, including its decision that Section 2.306 was applicable to the
Tennessee Gas Contract. The Texas Supreme Court remanded to the District Court
for plenary trial the question of whether, as required by Section 2.306, natural
gas volumes taken by Tennessee Gas under the contract were produced and
delivered in good faith and were not unreasonably disproportionate to a normal
or otherwise comparable prior output or the expectation of the parties. The
Company filed a request on September 15, 1995 for a rehearing in the Texas
Supreme Court of the Section 2.306 issue.
In connection with a District Court judgment, since September 1994
Tennessee Gas has posted supersedeas bonds totaling $206 million and executed
interim agreements with the Company and its co-sellers under which it pays $3.00
per MMBtu, currently, for natural gas delivered, and has agreed to take monthly
no less than 85% of the delivery capacity, if available, of the wells covered by
the Tennessee Gas Contract for the term of the interim agreement, or until
mandate issues. The excess of $3.00 per MMBtu over the market price for natural
gas delivered since August 1, 1995 (but not for the earlier deliveries) is
refundable to Tennessee Gas to the extent required by a final judgment against
the Company. The acceptance of the $3.00 per MMBtu does not constitute any
waiver by the Company to its claim for the full contract price for all natural
gas taken by Tennessee Gas. The last interim agreement, remained in effect until
April 30, 1996.
Prior to September 17, 1994, Tennessee Gas had been paying a price for
natural gas production from the dedicated leases based on Section 102(b)(2) of
the NGPA, plus reimbursement for severance taxes, subject to the right to
recover any excess price if ultimately successful in the litigation. As of
December 31, 1995, the Company had recorded cumulative revenue of approximately
$155 million for natural gas sold under the Tennessee Gas Contract based on the
prices as defined in the contract, of which approximately $112 million
(approximately $61 million of which has been received by the Company) is at
issue in the litigation. The Company continues to accrue an accounts receivable
amount due from Tennessee Gas that reflects the difference between the amount
paid for natural gas under the interim agreements between the parties and the
price that would have been paid pursuant to the terms of the Tennessee Gas
Contract. At December 31, 1995, such receivable (which includes accrued interest
as provided for in the contract and is net of deferred severance taxes and other
payables) was $56.4 million.
F-18
<PAGE> 83
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
SUBSEQUENT INFORMATION (UNAUDITED)
Royalty Suits -- Background
The Company is a party to three lawsuits involving the holders of royalty
interests on the acreage that was covered by the Tennessee Gas Contract. The
Company is a co-plaintiff in the first of these lawsuits that was filed in
Dallas County, Texas, and is a defendant in the other subsequently filed suits
in Zapata County, Texas. The basis of these declaratory judgment actions is the
royalty holders' claim that their royalty payments should be based on the price
paid by Tennessee Gas for the natural gas purchased by it under the Tennessee
Gas Contract. The Company has been paying royalties for this natural gas based
upon the spot market price. Because the leases have market-value royalty
provisions, the Company believes it is in full compliance under the leases with
its royalty holders. The amount at issue in these cases cannot be determined at
this time as it is a function of the quantity of natural gas for which Tennessee
Gas ultimately is obligated to pay at the contract price at the resolution of
the Tennessee Gas litigation described above. As of December 31, 1995, the
amount of natural gas taken by Tennessee Gas attributable to these royalty
interests was approximately 3.1 Bcf, for which royalties have been paid by the
Company at the average spot price of approximately $1.71 per Mcf, net of
severance tax, compared to the average contract price of approximately $7.50 per
Mcf, net of severance tax. Consequently, if the Company prevails in its
litigation with Tennessee Gas, but loses in its litigation with these royalty
interest owners, the Company faces a maximum liability in this litigation of
approximately $17.9 million.
Royalty Suits -- Recent Events (unaudited)
The Company's position has recently been confirmed in the Dallas suit where
the trial judge has granted the co-plaintiffs' motions for summary judgment on
this issue. In addition, the trial judge has granted summary judgment against
the royalty owners with respect to their various counterclaims against the
co-plaintiffs as concerns the jointly-owned Guerra "A" and Guerra "B" units.
However, the royalty owners also separately counterclaimed against the Company
with respect to the Jesus Yzaguirre unit, asserting that the largest lease
contained therein had terminated in December, 1975 and that certain of the
royalty owners were entitled to the Tennessee Gas Contract price because of
their execution of certain division orders in 1992 that allegedly varied the
market-value royalty provision of their lease. The trial judge has not yet ruled
on the parties' motions for summary judgment concerning these issues, although
he has granted the Company's motion for summary judgment that the royalty
holders' leases require that royalties be based upon the market value of the
natural gas at the lease when produced and sold, not the price paid for the
natural gas under the Tennessee Gas Contract.
Other Legal Proceedings
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 cannot be predicted with certainty, management does
not expect such matters to have a material adverse effect, either singly or in
the aggregate, on the financial position of the Company.
F-19
<PAGE> 84
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
8. QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
FISCAL QUARTERS
-----------------------------------------------
FIRST SECOND THIRD FOURTH
-------- -------- -------- --------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
1994
Revenue..................................... $ 85,173 $ 84,491 $ 80,743 $ 91,306
Operating Income............................ 9,380 11,135 6,076 12,021
Net Income.................................. 6,170 6,915 3,977 7,095
Earnings Per Common Share................... $ 0.52 $ 0.58 $ 0.34 $ 0.60
1995
Revenue..................................... $ 96,039 $126,556 $109,679 $117,691
Operating Income............................ 10,184 9,306 6,438 9,973
Net Income.................................. 6,219 5,377 4,086 5,624
Earnings Per Common Share................... $ 0.53 $ 0.46 $ 0.35 $ 0.48
1996
Revenue..................................... $146,557 $ 96,487 $ 73,560 --
Operating Income............................ 12,373 10,751 9,057 --
Net Income.................................. 5,855 4,987 3,964 --
Earnings Per Common Share................... $ 0.50 $ 0.42 $ 0.33 --
</TABLE>
F-20
<PAGE> 85
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. FINANCIAL INFORMATION BY BUSINESS SEGMENT
The following financial information has been provided for the business
segments of the Company:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
----------------------------------
1993 1994 1995
-------- -------- --------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Revenue
Oil and Gas Exploration and Production................ $ 40,455 $ 66,215 $ 86,629
Natural Gas Transportation and Marketing.............. 264,710 279,155 365,354
Intercompany.......................................... (876) (3,657) (2,018)
------- -------- --------
$304,289 $341,713 $449,965
======= ======== ========
Operating Income
Oil and Gas Exploration and Production................ $ 26,655 $ 37,943 $ 39,645
Natural Gas Transportation and Marketing.............. 3,578 2,889 (1,349)
------- -------- --------
30,233 40,832 38,296
Corporate Expenses.................................... (2,433) (2,220) (2,395)
Interest and Other Income, net........................ 704 1,039 3,713
Interest Expense...................................... (1,983) (2,938) (7,732)
------- -------- --------
Income Before Income Taxes............................ $ 26,521 $ 36,713 $ 31,882
======= ======== ========
Identifiable Assets
Oil and Gas Exploration and Production................ $ 94,266 $151,571 $274,474
Natural Gas Transportation and Marketing.............. 68,406 60,573 78,331
Corporate and Other................................... 3,318 2,279 7,804
------- -------- --------
$165,990 $214,423 $360,609
======= ======== ========
Depreciation, Depletion and Amortization
Oil and Gas Exploration and Production................ $ 7,004 $ 18,538 $ 37,988
Natural Gas Transportation and Marketing.............. 998 1,178 1,157
Other................................................. 34 24 64
------- -------- --------
$ 8,036 $ 19,740 $ 39,209
======= ======== ========
Capital Expenditures
Oil and Gas Exploration and Production................ $ 46,667 $ 73,870 $122,554
Natural Gas Transportation and Marketing.............. 1,773 942 6,085
Other................................................. 15 141 60
------- -------- --------
$ 48,455 $ 74,953 $128,699
======= ======== ========
</TABLE>
10. OIL AND GAS PRODUCING OPERATIONS
The following data is presented pursuant to FASB Statement No. 69 with
respect to oil and gas acquisition, exploration, development and producing
activities, which is based on estimates of year-end oil and gas reserve
quantities and forecasts of future development costs and production schedules.
These estimates and forecasts are inherently imprecise and subject to
substantial revision as a result of changes in estimates of remaining volumes,
prices, costs, and production rates.
F-21
<PAGE> 86
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Except where otherwise provided by contractual agreement, future cash
inflows are estimated using year-end prices. Oil and gas prices at December 31,
1995 are not necessarily reflective of the prices the Company expects to receive
in the future.
Volumetric production payment volumes represent oil and gas reserves
purchased from third parties which entitle the Company to a specified volume of
oil and gas to be delivered over a stated time period. The related volumes
stated herein reflect scheduled amounts of oil and gas to be delivered to the
Company at agreed delivery points, and are stated at year-end prices. The
Company does not bear any development or lease operating expenses associated
with the volumetric production payments.
PRODUCTION REVENUES AND COSTS
Information with respect to production revenues and costs related to oil
and gas producing activities is as follows:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
-------------------------------------
1993 1994 1995
--------- --------- ---------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Revenue.............................................. $ 39,918 $ 65,773 $ 85,424
Production (lifting) costs........................... 5,011 7,063 6,623
Technical support and other.......................... 1,785 2,671 2,373
Depreciation, depletion and amortization............. 6,944 18,538 37,859
------- ------- -------
Total expenses............................. 13,740 28,272 46,855
------- ------- -------
Pretax income from producing activities.............. 26,178 37,501 38,569
Income taxes......................................... 8,005 12,041 12,549
------- ------- -------
Results of oil and gas producing activities
(excluding corporate overhead and interest)........ $ 18,173 $ 25,460 $ 26,020
======= ======= =======
Capitalized costs incurred:
Property acquisition............................... $ 18,563 $ 27,772 $ 77,515
Exploration........................................ 3,787 12,599 16,891
Development........................................ 24,249 33,311 26,859
------- ------- -------
Total capitalized costs incurred................ $ 46,599 $ 73,682 $ 121,265
======= ======= =======
Capitalized costs at year-end:
Proved properties.................................. $ 98,369 $ 169,624 $ 284,597
Unproved properties................................ 2,647 5,074 7,297
------- ------- -------
101,016 174,698 291,894
Accumulated depreciation, depletion and
amortization....................................... (30,539) (49,077) (86,936)
------- ------- -------
Net investment in oil and gas producing properties... $ 70,477 $ 125,621 $ 204,958
======= ======= =======
</TABLE>
DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)
The following information relating to discounted future net cash flows has
been prepared on the basis of the Company's estimated net proved oil and gas
reserves in accordance with FASB Statement No. 69. A significant portion of the
discounted future net cash flows presented below is attributable to the Bob West
Field where gas is committed under the Tennessee Gas Contract, which was
terminated effective January 1, 1997 (see Note 7).
F-22
<PAGE> 87
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------
1994 1995
-------- ---------
(DOLLARS IN
THOUSANDS)
<S> <C> <C>
Future cash inflows................................................... $371,323 $ 521,914
Future costs:
Production.......................................................... (44,795) (94,880)
Development......................................................... (18,995) (21,985)
Discount -- 10% annually............................................ (65,828) (113,964)
------- --------
Present value of future net revenues................................ 241,705 291,085
Future income taxes, discounted at 10%.............................. (62,045) (59,322)
------- --------
Standardized measure of discounted future net cash flows.............. $179,660 $ 231,763
======= ========
</TABLE>
CHANGES IN DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVE QUANTITIES
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
----------------------------------
1993 1994 1995
-------- -------- --------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Balance, beginning of year.............................. $106,993 $160,884 $179,660
Increases (decreases)
Sales, net of production costs........................ (34,907) (58,710) (78,801)
Net change in prices, net of production costs......... (7,648) (11,180) 9,593
Discoveries and extensions, net of future production
and development costs.............................. 75,365 26,930 22,417
Changes in estimated future development costs......... (1,862) (9,622) (862)
Change due to acquisition of reserves in place........ 23,665 26,038 108,798
Development costs incurred during the period.......... 3,371 13,924 9,672
Revisions of quantity estimates....................... (15,791) 1,532 (19,256)
Accretion of discount................................. 14,600 21,017 24,033
Net change in income taxes............................ (10,279) (12,060) 2,021
Sales of reserves in place............................ -- -- (1,931)
Changes in production rates (timing) and other........ 7,377 20,907 (23,581)
-------- -------- --------
Net increase.......................................... 53,891 18,776 52,103
-------- -------- --------
Balance, end of year.................................... $160,884 $179,660 $231,763
======== ======== ========
</TABLE>
RESERVE INFORMATION (UNAUDITED)
The following information with respect to the Company's estimated net
proved oil and gas reserves are estimates based on reports prepared by
independent reserve engineers (principally R.A. Lenser and Associates, Inc. and
H.J. Gruy and Associates, Inc.). Proved developed reserves represent only those
reserves expected to be recovered through existing wells using equipment
currently in place. Proved undeveloped reserves represent proved reserves
expected to be recovered from new wells or from existing wells after material
recompletion expenditures. All of the Company's reserves are located within the
United States.
F-23
<PAGE> 88
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
1993 1994 1995
----------------- ----------------- -----------------
GAS OIL GAS OIL GAS OIL
MMCF MBBL MMCF MBBL MMCF MBBL
------ ------ ------- ----- ------- -----
<S> <C> <C> <C> <C> <C> <C>
Proved developed and undeveloped
reserves
Balance, beginning of year....... 52,029 1,333 69,740 2,578 89,184 2,319
Production....................... (6,977) (179) (11,304) (211) (19,129) (196)
Discoveries, extensions, etc..... 14,066 972 10,924 33 10,399 202
Acquisition of reserves in
place.......................... 10,043 1,684 18,206 148 71,560 5,449
Sales of reserves in place....... -- -- -- -- (3,751) (3)
Revisions of estimates........... 579 (1,232) 1,618 (229) (7,300) (254)
------ ------ ------- ----- ------- -----
Balance, end of year............. 69,740 2,578 89,184 2,319 140,963 7,517
====== ====== ======= ===== ======= =====
Proved developed reserves
Balance, beginning of year..... 39,140 1,095 61,016 1,579 74,215 1,336
------ ------ ------- ----- ------- -----
Balance, end of year........... 61,016 1,579 74,215 1,336 121,987 3,808
====== ====== ======= ===== ======= =====
</TABLE>
Proved gas reserves at December 31, 1995 include 31.7 Bcf (including 28.7
Bcf proved, developed) attributable to the Bob West Field, where gas is
committed under the Tennessee Gas Contract. The Tennessee Gas Contract was
terminated effective January 1, 1997 (see Note 7).
11. RECENT ACQUISITIONS
On November 8, 1995, the Company acquired substantially all of the oil and
gas assets of Natural Gas Processing Company (the "Rocky Mountain Acquisition")
for $33 million, subject to adjustments for a July 1, 1995 effective date. The
purchase was financed principally through the Master Note Facility. The Company
also acquired a significant inventory of oil and gas equipment and supplies,
vehicles and buildings as well as natural gas gathering systems consisting of
approximately 200 miles of pipeline.
On December 7, 1995, the Company acquired reserves in the northern and
southern Niagaran Reef trend in Michigan for $31 million, including a volumetric
production payment covering certain reserves, escalating working interests in
related properties and participation rights and an overriding royalty interest
in an exploration program (collectively, the "Michigan Acquisition"). The
volumetric production payment provides for the delivery to the Company of
certain oil and gas reserves totaling 20.3 Bcfe through January 31, 2006 without
any burden of operating costs. The Michigan Acquisition was financed through the
VPP Facility and the Note Financing.
These acquisitions were accounted for using the purchase method. The
results of operations for the acquired entities are included in the Company's
consolidated results of operations from the dates of acquisition.
F-24
<PAGE> 89
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following is the unaudited pro forma revenue, net income and earnings
per share giving effect to the Rocky Mountain and Michigan Acquisitions for the
years ended December 31, 1995 and 1994, as if such transactions had occurred at
the beginning of such years. The unaudited pro forma financial data do not
purport to be indicative of the financial position or results of operations that
would actually have occurred if the transactions had occurred as presented or
that may be obtained in the future.
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
---------------------
1994 1995
-------- --------
(DOLLARS IN
THOUSANDS,
EXCEPT PER SHARE
DATA)
<S> <C> <C>
Revenue...................................................... $356,748 $465,000
Net income................................................... $ 24,512 $ 21,661
Earnings per common share.................................... $ 2.08 $ 1.84
</TABLE>
12. SUBSEQUENT EVENT (UNAUDITED)
Medallion Acquisition
As of December 31, 1996, the Company completed the arrangements for the
acquisition of all of the outstanding stock of the Medallion entities, indirect
wholly-owned subsidiaries of MidAmerican Energy Holdings Company
("MidAmerican"), for a purchase price of approximately $214.4 million,
consisting of a cash payment of $209.4 million (reduced at the January 2, 1997
closing by $15.3 million principally to reflect free cash flow from the
Medallion entities' operations subsequent to July 1, 1996 effective date) and
warrants to purchase 435,000 shares of Common Stock.
Medallion's principal assets are 202.1 Bcfe proved oil and gas reserves
estimated as of June 30, 1996 by an independent reserve engineer, Ryder Scott
Company, consisting of 161.3 Bcf of natural gas (80% of total proved reserves)
and 6.8 MMbbls of oil and condensate. These reserves are located primarily in
the Mid-Continent region encompassing west Texas, the Texas panhandle, northwest
Oklahoma and north Louisiana. Proved developed reserves account for 88% of
Medallion's total proved reserves and the average reserve life at year-end 1995
was 8.0 years. The Medallion Acquisition will more than double the Company's
reserve base and add substantial management and technical expertise,
particularly in the new Mid-Continent core operating area.
F-25
<PAGE> 90
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and Boards of Directors of InterCoast
Oil and Gas Company, InterCoast Gas Services
Company and GED Energy Services, Inc.:
We have audited the accompanying combined balance sheets of the InterCoast
Entities (see Note 1) as of December 31, 1994 and 1995, and the related combined
statements of income, changes in stockholders' equity and cash flows for each of
the three years in the period ended December 31, 1995. These combined financial
statements are the responsibility of the InterCoast Entities' management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. 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 financial position of the InterCoast Entities as
of December 31, 1994 and 1995, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 1995, in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Tulsa, Oklahoma
October 30, 1996
F-26
<PAGE> 91
THE INTERCOAST ENTITIES
COMBINED STATEMENTS OF INCOME
(IN THOUSANDS)
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------- --------------------
1993 1994 1995 1995 1996
------- ------- ------- ------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenue
Gas and oil revenues.............. $37,359 $44,466 $48,109 $34,624 $ 51,229
Natural gas sales revenues........ 16,715 13,700 25,351 6,561 108,635
Gathering system revenues......... -- -- -- -- 644
------- ------- ------- ------- --------
54,074 58,166 73,460 41,185 160,508
------- ------- ------- ------- --------
Operating costs and expenses
Gas and oil operating expenses.... 9,616 15,016 14,552 10,920 12,367
Cost of gas sold.................. 16,216 13,142 24,361 6,139 106,546
Gathering system expenses......... -- -- -- -- 109
Other operating and administrative
expenses....................... 2,268 2,713 2,658 1,679 3,407
Depreciation, depletion and
amortization................... 13,672 18,782 21,705 15,953 20,360
------- ------- ------- ------- --------
41,772 49,653 63,276 34,691 142,789
------- ------- ------- ------- --------
Interest expense.................... -- -- -- -- 992
Income before income taxes.......... 12,302 8,513 10,184 6,494 16,727
Provision for income taxes.......... 5,383 3,202 3,638 2,319 5,973
------- ------- ------- ------- --------
Net income..................... $ 6,919 $ 5,311 $ 6,546 $ 4,175 $ 10,754
======= ======= ======= ======= ========
</TABLE>
The accompanying notes to combined financial statements are an integral part of
these statements.
F-27
<PAGE> 92
THE INTERCOAST ENTITIES
COMBINED BALANCE SHEETS
(IN THOUSANDS EXCEPT SHARE AND PER SHARE AMOUNTS)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------- SEPTEMBER 30,
1994 1995 1996
-------- -------- -------------
(UNAUDITED)
<S> <C> <C> <C>
Current assets
Cash and cash equivalents.............................. $ 5,124 $ 8,323 $ 3,542
Trade accounts receivable.............................. 6,586 24,101 29,740
Other.................................................. 2,311 1,383 2,332
-------- -------- --------
Total current assets........................... 14,021 33,807 35,614
Gas and oil properties, net.............................. 141,070 158,597 199,427
Gas gathering system..................................... -- -- 2,950
Other property, net...................................... 754 872 1,174
Intangible and other assets, net......................... 1,840 3,511 5,066
-------- -------- --------
Total assets................................... $157,685 $196,787 $ 244,231
======== ======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable....................................... $ 3,104 $ 18,702 $ 21,461
Other current liabilities.............................. 993 3,625 4,187
-------- -------- --------
Total current liabilities...................... 4,097 22,327 25,648
-------- -------- --------
Accumulated deferred income taxes, net................... 13,541 25,088 31,866
-------- -------- --------
Long-term debt due to MidAmerican Capital................ -- -- 52,402
Stockholders' equity, per accompanying statements
Common stock, InterCoast Oil and Gas Company ($1 par
value, 1,000 shares authorized, issued and
outstanding)........................................ 1 1 1
Common stock, InterCoast Gas Services Company ($1 par
value, 1,000 shares authorized, issued and
outstanding)........................................ 1 1 1
Common stock, GED Energy Services, Inc. ($1 par value,
0, 1,000 and 1,000 shares authorized, issued and
outstanding at December 31, 1994 and 1995 and
September 30, 1996)................................. -- 1 1
Additional paid-in capital............................. 123,802 126,580 100,769
Retained earnings...................................... 16,243 22,789 33,543
-------- -------- --------
Total stockholders' equity..................... 140,047 149,372 134,315
-------- -------- --------
Total liabilities and stockholders' equity..... $157,685 $196,787 $ 244,231
======== ======== ========
</TABLE>
The accompanying notes to combined financial statements are an integral part of
these statements.
F-28
<PAGE> 93
THE INTERCOAST ENTITIES
COMBINED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMMON STOCK
--------------------------------------------------
INTERCOAST OIL ADDITIONAL COMBINED
AND INTERCOAST GAS GED ENERGY PAID-IN RETAINED STOCKHOLDERS'
GAS COMPANY SERVICES COMPANY SERVICES, INC. CAPITAL EARNINGS EQUITY
-------------- ---------------- -------------- ---------- --------- -------------
<S> <C> <C> <C> <C> <C> <C>
Balance at December 31,
1992...................... $ 1 $ 1 $ -- $ 57,683 $ 4,013 $ 61,698
Net income.................. -- -- -- -- 6,919 6,919
Contributions from parent... -- -- -- 49,467 -- 49,467
-- -- --
-------- ------- --------
Balance at December 31,
1993...................... 1 1 -- 107,150 10,932 118,084
Net income.................. -- -- -- -- 5,311 5,311
Contributions from parent... -- -- -- 16,652 -- 16,652
-- -- --
-------- ------- --------
Balance at December 31,
1994...................... 1 1 -- 123,802 16,243 140,047
Formation of GED Energy
Services, Inc. ........... -- -- 1 -- -- 1
Net income.................. -- -- -- -- 6,546 6,546
Contributions from parent... -- -- -- 2,778 -- 2,778
-- -- --
-------- ------- --------
Balance at December 31,
1995...................... 1 1 1 126,580 22,789 149,372
Net income (unaudited)...... -- -- -- -- 10,754 10,754
Dividend to parent
(unaudited)............... -- -- -- (25,811) -- (25,811)
-- -- --
-------- ------- --------
Balance at September 30,
1996 (unaudited).......... $ 1 $ 1 $ 1 $ 100,769 $ 33,543 $ 134,315
==== ==== ==== ========= ======== =========
</TABLE>
The accompanying notes to combined financial statements are an integral part of
these statements.
F-29
<PAGE> 94
THE INTERCOAST ENTITIES
COMBINED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
---------------------------------- ---------------------
1993 1994 1995 1995 1996
-------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Cash flows from operating activities
Net income............................. $ 6,919 $ 5,311 $ 6,546 $ 4,175 $ 10,754
Adjustments to reconcile net income to
net cash from operating activities:
Deferred income taxes, net.......... 4,020 2,502 11,547 3,608 6,778
Provision for depreciation,
depletion and amortization........ 13,672 18,782 21,705 15,953 20,360
Change in working capital items:
Accounts receivable............... (2,791) 3,309 (17,515) (2,981) (5,639)
Other current assets.............. 296 (1,032) 928 (297) (949)
Accounts payable.................. 2,869 (2,782) 15,598 2,758 2,759
Other current liabilities......... 1,773 (1,840) 2,632 (291) 562
-------- -------- -------- -------- --------
Net cash from operating
activities................... 26,758 24,250 41,441 22,925 34,625
-------- -------- -------- -------- --------
Cash flows from investing activities
Investments in:
Gas and oil properties.............. (74,984) (42,849) (40,845) (30,059) (61,979)
Other............................... (460) (26) (2,004) (149) (4,173)
Proceeds from sale of gas and oil
properties........................ 1,495 3,465 1,829 1,829 155
-------- -------- -------- -------- --------
Net cash from investing
activities................... (73,949) (39,410) (41,020) (28,379) (65,997)
-------- -------- -------- -------- --------
Cash flows from financing activities
Borrowings from MidAmerican Capital.... -- -- -- -- 52,402
-------- -------- -------- -------- --------
Contributions from (dividends to)
parent.............................. 49,467 16,652 2,778 5,949 (25,811)
-------- -------- -------- -------- --------
Net cash from financing activities....... 49,467 16,652 2,778 5,949 26,591
-------- -------- -------- -------- --------
Net increase (decrease) in cash and cash
equivalents............................ 2,276 1,492 3,199 495 (4,781)
Cash and cash equivalents at beginning of
period................................. 1,356 3,632 5,124 5,124 8,323
-------- -------- -------- -------- --------
Cash and cash equivalents at end of
period................................. $ 3,632 $ 5,124 $ 8,323 $ 5,619 $ 3,542
======== ======== ======== ======== ========
Supplemental cash flow information
Cash paid (received) during the period
for:
Income taxes........................... $ 1,363 $ 700 $ (7,909) $ (1,233) $ (641)
======== ======== ======== ======== ========
</TABLE>
The accompanying notes to combined financial statements are an integral part of
these statements.
F-30
<PAGE> 95
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS
1. ACCOUNTING POLICIES
Corporate Structure
InterCoast Oil and Gas Company (InterCoast Oil and Gas, formerly Medallion
Production Company), a Delaware corporation, and InterCoast Gas Services
Company, a Delaware corporation, (InterCoast Gas Services -- Delaware) are
wholly-owned subsidiaries of InterCoast Energy Company (InterCoast Energy).
InterCoast Gas Services Company, an Oklahoma corporation, (InterCoast Gas
Services -- Oklahoma) and GED Energy Services, Inc., a Delaware corporation,
(GED) are wholly-owned subsidiaries of InterCoast Gas Services -- Delaware.
InterCoast Energy is a wholly-owned subsidiary of MidAmerican Capital Company
(MidAmerican Capital), which is wholly-owned by MidAmerican Energy Company
(MidAmerican Energy).
InterCoast Oil and Gas is primarily engaged in the acquisition,
development, exploration and production of natural gas and oil. InterCoast Gas
Services -- Oklahoma and GED are primarily engaged in the marketing of natural
gas.
Basis of Presentation
The accompanying financial statements reflect the combined operations of
InterCoast Oil and Gas, InterCoast Gas Services -- Oklahoma and GED
(collectively, the InterCoast Entities). The financial statements are presented
on a combined historical cost basis because the InterCoast Entities are under
common control and because InterCoast Energy and its wholly-owned subsidiary,
InterCoast Gas Services -- Delaware, have signed letters of intent to sell the
stock of the InterCoast Entities to KCS Energy, Inc. (see Note 10).
InterCoast Gas Services -- Delaware formed GED and acquired the assets of
GED Gas Services, L.L.C. effective November 1, 1995. The accompanying combined
financial statements include the results of GED for the period since the date of
such acquisition.
Intercompany and affiliated company accounts and transactions have been
eliminated in the combination. Since there is no parent-subsidiary relationship
between the InterCoast Entities, there is no basis for eliminating the equity
accounts of any of the entities.
The preparation of the financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reported period. Actual
results may differ from those estimates.
Oil and Gas Properties
The InterCoast Entities account for their gas and oil properties using the
full cost method of accounting which provides for the capitalization of all
acquisition, exploration and development costs incurred for the purpose of
finding natural gas and oil reserves. The unamortized cost of gas and oil
properties, including estimated future development and abandonment costs, is
amortized using the unit-of-production method based on the ratio of volumes
produced to proved reserves.
Unevaluated properties and associated costs not currently being amortized
and included in oil and gas properties were $1.5 million, $1.6 million and $2.1
million at December 31, 1993, 1994 and 1995, respectively and $3.3 million at
September 30, 1996. Such costs relate to projects which were at such dates
undergoing exploration or development activities or in which the InterCoast
Entities intend to commence such activities in the future. The InterCoast
Entities will begin to amortize these costs when proved reserves are established
or impairment is determined.
F-31
<PAGE> 96
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
The InterCoast Entities' unamortized costs of gas and oil properties are
limited to the sum of the future net revenues attributable to proved oil and gas
reserves discounted at ten percent plus the cost of any unproved properties. If
the InterCoast Entities' unamortized costs in oil and gas properties exceed this
ceiling amount, a provision for additional depreciation, depletion and
amortization is required. At December 31, 1993, 1994 and 1995 and September 30,
1996, the InterCoast Entities' unamortized costs of oil and gas properties did
not exceed such ceiling amount.
Proceeds from the sale of oil and gas properties are applied to reduce the
costs in the full cost pool unless the sale involves a significant quantity of
reserves in relation to the cost center, in which case a gain or loss would be
recognized.
The InterCoast Entities conduct certain of their drilling activities
(Programs), on a joint venture basis, together with working interest
participants. The agreements under which these investors participate provide the
InterCoast Entities with certain reversionary interests in the properties in the
Programs and current reimbursement of proportionate amounts of overhead and
seismic costs. Overhead reimbursements are included in the Combined Statements
of Income as a reduction of general and administrative expenses. The amounts of
such reimbursements were $872,000, $1,520,000 and $2,047,000 for the years ended
December 31, 1993, 1994 and 1995, respectively, and were $2,022,000 and
$2,653,000 for the nine months ended September 30, 1995 and 1996, respectively.
Production Imbalances
Joint interest owners may take more or less than their ownership interest
of natural gas volumes from jointly owned reservoirs. The InterCoast Entities
follow the sales method of accounting for imbalances, whereby they recognize
revenues based on the actual volumes of natural gas sold to purchasers. The
InterCoast Entities record a liability if sales of natural gas volumes in excess
of their entitlements from a jointly owned reservoir exceed their interest in
the remaining estimated natural gas reserves of such reservoir. Volumetric
production is monitored to minimize imbalances, and such imbalances were not
significant at December 31, 1993, 1994 and 1995 and September 30, 1996.
Amortization of Goodwill
Goodwill was recognized with the acquisition of operating rights, certain
other assets and personnel of Medallion Petroleum, Inc. in 1992 by InterCoast
Oil and Gas and with the acquisition of certain assets and personnel of GED Gas
Services, L.L.C. in 1995 by GED. Goodwill is amortized over the expected period
of benefit of forty years using the straight line method. The unamortized
balance of goodwill included on the Combined Balance Sheets as Intangible and
Other Assets at December 31, 1994 and 1995 and September 30, 1996 is $1,829,000,
$3,486,000 and $3,417,000, respectively.
Long-Lived Assets
In March 1995, the Financial Accounting Standards Board (FASB) issued SFAS
No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of." This statement, which the InterCoast Entities adopted
on January 1, 1996, requires the InterCoast Entities to review long-lived assets
for impairment whenever circumstances indicate that the carrying amount of an
asset may not be recoverable. Adoption of SFAS No. 121 had no impact on the
InterCoast Entities' results of operations or financial position at the time of
adoption.
Stock-Based Compensation Plans
In October 1995, the FASB issued SFAS No. 123 "Accounting for Stock-Based
Compensation" regarding accounting for stock-based compensation plans. This
statement, which is effective for
F-32
<PAGE> 97
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
reporting periods beginning January 1, 1996, allows for alternative methods of
adoption. The InterCoast Entities do not expect the accounting provisions or the
alternative disclosure provisions of SFAS No. 123 to have a material impact on
the InterCoast Entities' compensation costs.
Accounting for Commodity Price Risk Management
The InterCoast Entities engage in price risk management activities to
minimize the impact of market fluctuations on assets, liabilities, production or
other contractual commitments. Changes in the market value of these transactions
are deferred until the gain or loss on the underlying item is recognized. See
Note 6 for further discussion of the InterCoast Entities' price risk management
activities.
Combined Statements of Cash Flows
For purposes of the Combined Balance Sheets and Combined Statements of Cash
Flows, the InterCoast Entities consider all highly liquid debt instruments
purchased with a remaining maturity of three months or less to be cash
equivalents. There were no material non-cash investing or financing activities
in the years ended December 31, 1993, 1994 or 1995 or in the nine months ended
September 30, 1995 and 1996.
2. OIL AND GAS PROPERTIES, NET
<TABLE>
<CAPTION>
DECEMBER 31, SEPTEMBER
--------------------- 30,
1994 1995 1996
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Oil and gas properties........................... $186,131 $225,147 $286,116
Accumulated depreciation, depletion and
amortization................................... (45,061) (66,550) (86,689)
-------- -------- --------
Oil and gas properties, net...................... $141,070 $158,597 $199,427
======== ======== ========
</TABLE>
The provision for depreciation, depletion and amortization of the
InterCoast Entities' oil and gas properties was recorded at the rate of $0.80,
$0.86 and $0.90, per equivalent thousand cubic feet of natural gas production
for the years ended December 31, 1993, 1994 and 1995, respectively, and at the
rate of $0.83 and $0.88 for the nine months ended September 30, 1995 and 1996,
respectively.
3. INCOME TAXES
The InterCoast Entities are included in the consolidated federal and, where
appropriate, state income tax returns of MidAmerican Energy. The consolidated
income tax currently payable (or receivable) has been allocated among the
InterCoast Entities and other members of the affiliated income tax reporting
group (Group) based on the respective contributions to the consolidated taxable
income and tax credits of the Group. The InterCoast Entities have received (or
made) payments for the income tax reductions (or increases) contributed to the
Group.
The components of the provision for income taxes are shown below:
<TABLE>
<CAPTION>
1993 1994 1995
------ ------ -------
(IN THOUSANDS)
<S> <C> <C> <C>
Current -- Federal................................... $1,136 $ 560 $(7,143)
-- State.................................... 227 140 (766)
Deferred -- Federal................................... 3,135 1,772 10,382
-- State.................................... 885 730 1,165
------ ------ ------
Total....................................... $5,383 $3,202 $ 3,638
====== ====== ======
</TABLE>
F-33
<PAGE> 98
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
A reconciliation of the statutory federal income tax rate to the overall
effective income tax rate follows:
<TABLE>
<CAPTION>
1993 1994 1995
---- ---- ----
<S> <C> <C> <C>
Statutory federal income tax rate......................... 35.0% 35.0% 35.0%
State income taxes, net of federal income tax benefit..... 2.0 2.5 2.1
State tax true-ups........................................ 1.7 -- --
Other items, net.......................................... 5.1 0.1 (1.4)
---- ---- ----
Overall effective income tax rate......................... 43.8% 37.6% 35.7%
==== ==== ====
</TABLE>
The components of the net deferred tax liability are as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------
1994 1995
------- --------
(IN THOUSANDS)
<S> <C> <C>
Accelerated depreciation/depletion methods.................... $(4,271) $(13,940)
Intangible drilling costs..................................... 17,062 38,278
Other......................................................... 750 750
------- --------
Accumulated deferred income taxes............................. $13,541 $ 25,088
======= ========
</TABLE>
4. RELATED PARTY TRANSACTIONS
The InterCoast Entities receive general and administrative services from
InterCoast Energy, MidAmerican Capital and MidAmerican Energy. The costs of such
services received, including overhead costs, are assigned (and billed) to the
InterCoast Entities. Wages and salaries of the corporate staff and personnel of
InterCoast Energy, MidAmerican Capital and MidAmerican Energy are assigned based
upon an estimate of the time spent by staff and personnel benefitting the
InterCoast Entities. The estimate is reviewed and updated annually. Such wages
and salaries are billed to the InterCoast Entities, along with associated
payroll taxes and the costs of benefits. In addition, certain directly assigned
expenses paid by MidAmerican Capital are billed to the InterCoast Entities.
The InterCoast Entities are parties to guarantee agreements between
InterCoast Energy and its primary lender.
MidAmerican Capital and InterCoast Energy have entered into letters of
credit and financial guarantees on behalf of the InterCoast Entities to support
certain well costs and the natural gas purchases. Letters of credit and
financial guarantees are conditional commitments issued by MidAmerican Capital
InterCoast Energy to guarantee performance to a third party.
The InterCoast Entities have letters of credit totaling $1,914,000 and
$1,103,000 and financial guarantees amounting to $2,750,000 and $0 which were
not reflected on the Combined Balance Sheets as of December 31, 1995 and 1994,
respectively.
The fair value of the letters of credit was $14,000 and $8,000 at December
31, 1995 and 1994, respectively, estimated based on fees currently charged for
similar agreements. The fair value of the financial guarantees is not
determinable based on the specific characteristics of the guarantees.
5. EMPLOYEE BENEFITS
The InterCoast Entities' employees participate in MidAmerican Energy's
noncontributory defined benefit retirement income plan. Benefits under the plan
are based on participants' compensation, years of service and age at retirement.
Funding is based on the actuarially determined costs of the plan and the
requirements of the Internal Revenue Code and the Employee Retirement Income
Security Act.
F-34
<PAGE> 99
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
As of December 31, 1993, 1994 and 1995, the InterCoast Entities have not
been required to contribute to the plan. Pension costs are allocated to the
InterCoast Entities based on participants' compensation. The amount the
InterCoast Entities expensed during 1995, 1994 and 1993 was $12,000, $44,000 and
$0, respectively. The InterCoast Entities' pension accrual included in the
Combined Balance Sheets as Other Current Liabilities was $56,000 at December 31,
1994 and 1995.
6. FINANCIAL INSTRUMENTS WITH OFF-BALANCE SHEET RISK
Price Risk Management
The InterCoast Entities have entered into swaps, futures and options to
manage risks associated with fluctuations in the price of natural gas production
and marketing activities.
Commodity Price Swaps. Commodity price swap agreements require the
InterCoast Entities to make payments to (or entitle it to receive payments from)
the counterparties based upon the differential between a specified fixed and
variable price. The InterCoast Entities account for these transactions on a
settlement basis and, accordingly, gains or losses are included in oil and gas
revenues in the period in which the underlying natural gas is produced. These
agreements do not impose cash margin requirements on the InterCoast Entities or
provide for collateral to the InterCoast Entities. At December 31, 1995,
InterCoast Oil and Gas was party to commodity price swap agreements covering
approximately 8.0 million MMBtu, 6.3 million MMBtu and 23.2 million MMBtu of
natural gas for the years 1996 and 1997 and for the period 1998 through 2005,
respectively.
Futures and Options Contracts. Natural gas futures require the InterCoast
Entities to buy or sell natural gas at a fixed price. Natural gas options held
to hedge price risk only provide the right, not the requirement, to buy or sell
natural gas at a fixed price. The InterCoast Entities use futures to manage
margins on offsetting fixed-price purchase or sale commitments for physical
quantities of natural gas. The InterCoast Entities use options to limit overall
price risk exposure. Futures contracts mandate initial margin requirements. The
InterCoast Entities maintain such margin accounts and funds in cash any daily
settlement requirements relating to futures contracts.
At December 31, 1995, the InterCoast Entities had futures contracts to
purchase natural gas for approximately 10.1 million MMBtu and to sell natural
gas for approximately 4.9 million MMBtu. The associated unrecognized gain on
futures contracts was $486,000.
Basis Swaps. Basis swap agreements require the InterCoast Entities to make
payments to (or entitle it to receive payments from) the counterparties based
upon the differential between the variable costs associated with the delivery of
natural gas production to specific delivery points and a contractually specified
fixed cost. At December 31, 1995, InterCoast Oil and Gas had basis swap
arrangements relating to a total of approximately 2.1 million MMbtu during 1996.
Credit Risk
Credit risk relates to the risk of loss that the InterCoast Entities would
incur as a result of the nonperformance by counterparties pursuant to the terms
of their contractual obligations. The InterCoast Entities' overall exposure to
credit risk may be affected positively or negatively in that the counterparties
may be similarly affected by changes in economic, regulatory or other
conditions. The InterCoast Entities maintain credit policies with regard to
counterparties that management believes minimize overall credit risk. With
regard to commodity price and basis swaps, these policies include an evaluation
of potential counterparties' financial condition (including credit rating),
collateral agreements under certain circumstances and the use of standardized
agreements. With regard to futures and options contracts, the InterCoast
Entities utilize New York Mercantile Exchange (NYMEX) contracts. Such contracts
are guaranteed by the NYMEX and, accordingly, have nominal credit risk. As a
result, the InterCoast Entities'
F-35
<PAGE> 100
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
risk is limited to the initial purchase price of the options and to changes in
the market value of the futures contracts. Accordingly, the InterCoast Entities
do not anticipate any material impact on their financial position or results of
operations as a result of nonperformance by counterparties to the financial
instruments related to natural gas production and marketing activities.
7. CONCENTRATION OF CREDIT RISK
Although credit risk is inherent to the foregoing types of financial
instruments and the InterCoast Entities are exposed to losses in the event of
nonperformance by the counterparties, the InterCoast Entities believe that the
aggregate credit risk associated with present swap and hedge arrangements is not
significant due to the nature of the contracts and the counterparties thereto.
The InterCoast Entities' gas and oil production purchasers consist
primarily of independent marketers and major natural gas pipeline companies. The
InterCoast Entities perform credit evaluations of their customers' financial
condition and obtain credit support if the InterCoast Entities believe it is
warranted. The InterCoast Entities have not experienced any significant losses
from uncollectible accounts.
8. COMMITMENTS AND CONTINGENCIES
The InterCoast Entities are lessees in several agreements to lease office
space at various locations. The lease agreements expire in 1999 through 2001,
with various options for renewal. The following is a schedule by year of
estimated future rent expense on such leases as of December 31, 1995:
<TABLE>
<CAPTION>
YEAR ENDING
DECEMBER 31,
------------
<S> <C>
1996................................................................... $ 218,000
1997................................................................... 205,000
1998................................................................... 204,000
1999................................................................... 205,000
2000................................................................... 204,000
Thereafter............................................................. 205,000
----------
Total........................................................ $1,241,000
==========
</TABLE>
On June 19, 1996, an action was brought by Nab Nat. Resources, L.L.C.
against several defendants, including InterCoast Oil and Gas, in the Second
Judicial District Court, Claiborne Parish, State of Louisiana, seeking a
declaration of the court that certain leases and a unit agreement had lapsed by
reason of a cessation of production of oil or gas in paying quantities that
allegedly occurred in the mid 1980s. The plaintiff also seeks, among other
things, an accounting of the production of oil, natural gas and other minerals
from the properties since the alleged lapse of the leases, damages of not less
than $5,000,000 for restoration and clean up of the lands covered by the leases
and certain other damages for trespass and mental anguish. InterCoast Oil and
Gas is in the preliminary stages of investigating the facts on which the lawsuit
appear to be based. Based on InterCoast Oil and Gas' preliminary investigations,
the claim of damages for restoration and clean up of certain lands appears to
relate to properties which the InterCoast Oil and Gas does not own. InterCoast
Oil and Gas currently intends to continue its investigation of the lawsuit and
to defend the action vigorously.
9. SIGNIFICANT ACQUISITION
In April 1996, InterCoast Oil and Gas acquired the interests of Enron Oil &
Gas Company in certain gas and oil properties (the Sawyer Canyon Properties),
associated natural gas gathering lines and other well equipment located in
Texas. The net purchase price at closing was approximately $53.2 million.
F-36
<PAGE> 101
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
InterCoast Oil and Gas concurrently conveyed certain interests in particular
wells to InterCoast Global Management, Inc., a wholly-owned subsidiary of
MidAmerican Capital. InterCoast Oil and Gas retained a production payment on 100
percent of the net proceeds of production from such wells until approximately 80
percent of the estimated proved developed natural gas reserves attributable to
the wells is produced. In consideration, InterCoast Oil and Gas received from
InterCoast Global Management, Inc. $5.6 million in cash and a promissory note in
the amount of $2.3 million, which is payable in 48 monthly installments over
four years and bears interest at the prime rate. The total adjusted purchase
price was $45.2 million. InterCoast Oil and Gas recorded no gain or loss related
to this transaction. The proved reserves associated with the production payment
are included in the InterCoast Entities' estimated net quantities of oil and gas
reserves presented in Note 12.
InterCoast Oil and Gas funded the net purchase price of $45.2 million under
a promissory note due to MidAmerican Capital. This promissory note was due on or
before April 12, 1997, with interest payable quarterly at a floating rate based
on LIBOR plus 55 basis points. The promissory note was repaid in full in July
1996.
The following unaudited pro forma revenues, and net income for the years
ended December 31, 1994 and 1995 and for the three months ended March 31, 1996,
presented below have been prepared assuming the acquisition described above had
been consummated as of January 1, 1994. However, such pro forma information is
not necessarily indicative of what actually would have occurred had the
transaction occurred on such date.
<TABLE>
<CAPTION>
YEAR ENDED YEAR ENDED NINE MONTHS ENDED
DECEMBER 31, DECEMBER 31, SEPTEMBER 30,
1994 1995 1996
------------ ------------ -----------------
<S> <C> <C> <C>
Revenues (in thousands)............... $ 80,860 $ 88,138 $ 164,248
Net income (in thousands)............. 9,980 7,866 11,370
------- ------- ------
</TABLE>
10. SUBSEQUENT EVENT
On November 14, 1996, InterCoast Energy and its wholly-owned subsidiary,
InterCoast Gas Services -- Delaware, signed definitive agreements to sell the
stock of the InterCoast Entities to KCS Energy, Inc. Under the terms of these
agreements, KCS Energy, Inc. will pay approximately $219 million in cash and
deliver warrants to acquire 435,000 shares of KCS Energy, Inc. common stock at a
price of $45 per share.
11. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The combined results of operations by quarter for the years ended December
31, 1994 and 1995 are as follows (in thousands):
<TABLE>
<CAPTION>
1994 QUARTER ENDED
-----------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------
<S> <C> <C> <C> <C>
Total revenues.......................... $ 15,460 $15,459 $ 14,125 $13,122
Income before income taxes.............. $ 2,391 $ 2,930 $ 2,035 $ 1,157
Net income.............................. $ 1,492 $ 1,828 $ 1,269 $ 722
</TABLE>
<TABLE>
<CAPTION>
1995 QUARTER ENDED
-----------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------
<S> <C> <C> <C> <C>
Total revenues.......................... $ 12,990 $14,182 $ 14,012 $32,276
Income before income taxes.............. $ 1,641 $ 2,652 $ 2,201 $ 3,690
Net income.............................. $ 1,055 $ 1,705 $ 1,415 $ 2,371
</TABLE>
F-37
<PAGE> 102
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
In the fourth quarter of 1994, the InterCoast Entities experienced a
significant decline in realized natural gas price causing reductions in oil and
gas revenues and income before income taxes as compared to the prior three
quarters of 1994.
In the fourth quarter of 1995, InterCoast Energy acquired certain assets of
GED Gas Services, L.L.C. The acquisition generated natural gas sales revenues of
$15.4 million in such quarter. Additionally, in the fourth quarter of 1995, the
InterCoast Entities' natural gas production volumes and realized natural gas
prices increased resulting in higher oil and gas revenues and income before
income taxes as compared to the prior three quarters of 1995.
12. SUPPLEMENTARY OIL AND GAS DISCLOSURES
Users of the following information should be aware that the process of
estimating quantities of proved and proved developed oil and gas reserves is
very complex, requiring significant subjective decisions in the evaluation of
all available geological, engineering and economic data for each reservoir. The
data for a given reservoir may also change substantially over time as a result
of numerous factors including, but not limited to, additional development
activity, evolving production history and continual reassessment of the
viability of production under varying economic conditions. Consequently,
material revisions to existing reserve estimates occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessment possible, the significance of
the subjective decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other estimates
presented in connection with financial statement disclosures.
Proved reserves are estimated quantities of natural gas, crude oil and
condensate that geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known reservoirs under
economic and operating conditions existing at the time the estimates were made.
Proved developed reserves are proved reserves that can be expected to be
recovered through wells and equipment in place and under operating methods being
utilized at the time the estimates were made.
Capitalized costs for oil and gas producing activities consist of the
following:
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------------
1993 1994 1995
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Proved properties............................... $146,422 $184,502 $223,088
Unproved properties............................. 1,487 1,629 2,059
Accumulated depletion, depreciation and
amortization.................................. (26,459) (45,061) (66,550)
-------- -------- --------
Net capitalized costs................. $121,450 $141,070 $158,597
======== ======== ========
</TABLE>
Costs incurred for oil and gas property acquisition, exploration and
development activities are as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------
1993 1994 1995
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Development......................................... $12,749 $22,000 $34,639
Property acquisitions............................... 59,913 18,705 2,726
Exploration......................................... 2,322 2,144 3,480
------- ------- -------
Net capitalized costs..................... $74,984 $42,849 $40,845
======= ======= =======
</TABLE>
F-38
<PAGE> 103
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Estimated Net Quantities of Oil and Gas Reserves--(Unaudited)
The following table sets forth the InterCoast Entities' net proved
reserves, including the changes therein, and proved developed reserves (all
within the United States) at the end of each of the three years in the period
ended December 31, 1995:
<TABLE>
<CAPTION>
NATURAL OIL AND
GAS LIQUIDS TOTAL
(MMCF) (MBBL) (MMCFE)
--------- -------- ---------
<S> <C> <C> <C>
Net proved reserves at December 31, 1992........ 64,806.5 3,111.0 83,472.5
Revisions of previous estimates............... (6,649.3) 441.8 (3,998.5)
Extensions, discoveries and other additions... 14,911.6 288.4 16,642.0
Purchases of reserves in place................ 55,740.1 5,840.3 90,781.9
Production.................................... (12,741.8) (690.8) (16,886.6)
Sales of reserves in place.................... (4,043.7) (35.6) (4,257.3)
--------- -------- ---------
Net proved reserves at December 31, 1993........ 112,023.4 8,955.1 165,754.0
Revisions of previous estimates............... (10,931.0) (1,089.0) (17,465.0)
Extensions, discoveries and other additions... 39,713.5 375.0 41,963.5
Purchases of reserves in place................ 23,804.9 1,489.6 32,742.5
Production.................................... (15,590.9) (1,024.4) (21,737.3)
Sales of reserves in place.................... (408.9) (1,402.5) (8,823.9)
--------- -------- ---------
Net proved reserves at December 31, 1994........ 148,611.0 7,303.8 192,433.8
Revisions of previous estimates............... (22,594.8) 3,265.8 (3,000.0)
Extensions, discoveries and other additions... 24,372.5 514.0 27,456.5
Purchases of reserves in place................ 1,119.2 12.7 1,195.4
Production.................................... (17,835.4) (1,027.9) (24,002.8)
Sales of reserves in place.................... 0.0 (224.4) (1,346.4)
--------- -------- ---------
Net proved reserves at December 31, 1995........ 133,672.5 9,844.0 192,736.5
========= ======== =========
Net proved developed reserves at December 31,
1993.......................................... 100,660.0 8,173.0 149,698.0
at December 31, 1994.......................... 115,099.0 6,717.0 155,401.0
at December 31, 1995.......................... 111,189.0 8,255.0 160,719.0
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves (Unaudited)
The following information has been developed utilizing procedures
prescribed by Statement of Financial Accounting Standards No. 69 "Disclosures
about Oil and Gas Producing Activities" (SFAS No. 69) and based on oil and gas
reserve and production volumes estimated, in part by the InterCoast Entities,
but primarily by the InterCoast Entities' independent reserve engineers,
Netherland, Sewell and Associates, Inc. It may be useful for certain comparative
purposes, but should not be solely relied upon in evaluating the InterCoast
Entities or their performance. Further, information contained in the following
table should not be considered as representative of realistic assessments of
future cash flows, nor should the Standardized Measure of Discounted Future Net
Cash Flows be viewed as representative of the current value of the InterCoast
Entities.
The InterCoast Entities believe that the following factors should be taken
into account in reviewing the following information: (1) future costs and
selling prices will probably differ from those required to be used in these
calculations; (2) due to future market conditions and governmental regulations,
actual
F-39
<PAGE> 104
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
rates of production achieved in future years may vary significantly from the
rate of production assumed in the calculations; (3) selection of a 10% discount
rate is arbitrary and may not be reasonable as a measure of the relative risk
inherent in realizing future net oil and gas revenues; and (4) future net
revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows were estimated by
applying period-end oil and gas prices adjusted for fixed and determinable
escalations to the estimated future production of period-end reserves. As of
December 31, 1995, approximately 37.5 Bcf of gas of the InterCoast Entities'
future production was subject to commodity price swap agreements (see Note 6).
Future cash inflows were reduced by estimated future development, abandonment
and production costs based on period-end costs in order to arrive at future net
cash flow before tax. Future income tax expense has been computed by applying
period-end statutory tax rates to aggregate future pre-tax net cash flows,
reduced by the tax basis of the properties involved and tax carryforwards. Use
of a 10% discount rate is required by SFAS No. 69.
Management does not rely solely upon the following information in making
investment and operating decisions. Such decisions are based upon a wide range
of factors, including estimates of probable as well as possible reserves and
varying price and cost assumptions considered more representative of a range of
possible economic conditions that may be anticipated.
The standardized measure of discounted future net cash flows relating to
proved oil and gas reserves is as follows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-------------------------------------
1993 1994 1995
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows.......................... $ 354,076 $ 369,430 $ 430,282
Future production costs...................... (119,855) (123,914) (155,984)
Future development and abandonment costs..... (13,886) (24,003) (16,078)
--------- --------- ---------
Future net cash flows before income taxes.... 220,335 221,513 258,220
Future income tax expense.................... (50,633) (47,526) (65,314)
10% annual discount for estimating timing of
cash
flows...................................... (51,500) (47,943) (55,982)
--------- --------- ---------
Standardized measure of discounted future net
cash flows................................. $ 118,202 $ 126,044 $ 136,924
========= ========= =========
</TABLE>
F-40
<PAGE> 105
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
A summary of the principal changes in the standardized measure of
discounted future net cash flows applicable to proved oil and gas reserves is as
follows (unaudited):
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
----------------------------------
1993 1994 1995
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Beginning of the period......................... $ 62,177 $118,202 $126,044
-------- -------- --------
Revisions of previous estimates:
Changes in prices and costs..................... (551) (25,715) 8,275
Changes in quantities........................... (3,957) (13,134) (2,627)
Changes in future development costs............. (6,016) (7,323) (2,948)
Previously estimated development costs incurred
during the period............................. 8,951 11,572 17,954
Additions to proved reserves resulting from
extensions and discoveries, less related
cost.......................................... 16,314 31,935 26,998
Sales of reserves in place...................... (2,763) (663) (769)
Purchases of reserves in place.................. 68,074 27,006 2,085
Accretion of discount........................... 7,760 13,771 14,460
Sales of oil and gas, net of production costs... (27,728) (29,129) (32,961)
Net changes in income taxes..................... (4,089) 958 (12,684)
Changes in estimated timing of production
and other..................................... 30 (1,436) (6,903)
-------- -------- --------
Net increase.................................... 56,025 7,842 10,880
-------- -------- --------
End of period................................... $118,202 $126,044 $136,924
======== ======== ========
</TABLE>
F-41
<PAGE> 106
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholder and Board of Directors of
InterCoast Energy Company:
We have audited the accompanying statements of revenues and direct
operating expenses of the Sawyer Canyon Properties (see Note 1) for the years
ended December 31, 1994 and 1995. These statements are the responsibility of
InterCoast Energy Company's management. Our responsibility is to express an
opinion on these statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the statements of revenues and direct
operating expenses are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the statements. An audit also includes assessing the accounting principles used
and significant estimates made by management, as well as evaluating the overall
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the statements of revenues and direct operating expenses
referred to above presents fairly, in all material respects, the revenues and
direct operating expenses of the Sawyer Canyon Properties (see Note 1) for the
years ended December 31, 1994 and 1995, in conformity with generally accepted
accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas
June 28, 1996
F-42
<PAGE> 107
SAWYER CANYON PROPERTIES
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
<TABLE>
<CAPTION>
YEAR ENDED THREE MONTHS
--------------------------------------- ENDED
DECEMBER 31, 1994 DECEMBER 31, 1995 MARCH 31, 1996
----------------- ----------------- --------------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C>
REVENUES:
Oil and Gas............................ $20,661 $13,084 $3,425
Gathering systems...................... 2,033 1,594 315
------- ------- ------
Total revenues................. 22,694 14,678 3,740
------- ------- ------
DIRECT OPERATING EXPENSES:
Oil and Gas operating.................. 2,625 2,953 614
Gathering systems...................... 163 105 31
------- ------- ------
Total expenses................. 2,788 3,058 645
------- ------- ------
Excess of revenues over direct operating
expenses............................... $19,906 $11,620 $3,095
======= ======= ======
</TABLE>
The accompanying notes are an integral part of this financial statement.
F-43
<PAGE> 108
SAWYER CANYON PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
(1) THE SAWYER CANYON PROPERTIES
On March 30, 1996, Enron Oil & Gas Company (EOG) entered into a purchase
and sale agreement (the Agreement) to sell certain oil and gas properties and
related assets and two gathering systems (collectively, the Sawyer Canyon
Properties) to InterCoast Oil and Gas Company (the Company). The purchase price
as of the January 1, 1996 effective date, $55.5 million, was subject to certain
adjustments including the net revenues (as defined in the Agreement) between the
effective date and the closing date. The net purchase price at closing, April
12, 1996, was approximately $53.2 million of which $3.0 million was assigned to
the carrying value of related gathering systems which were transferred to
InterCoast Gas Services Company, an affiliated company. The properties,
predominantly natural gas, and the associated gathering systems are located in
West Texas.
Concurrent with the closing of the acquisition of the Sawyer Canyon
Properties from EOG, the Company conveyed certain interests in particular wells
to InterCoast Global Management, Inc., a wholly owned subsidiary of MidAmerican
Capital Company, the Company's indirect parent. The Company retained a
production payment on 100 percent of the net proceeds of production of such
wells until approximately 80 percent of the estimated proved developed natural
gas reserves attributable to the wells has been produced. The Company received
from InterCoast Global Management, Inc. $5.6 million in cash and a promissory
note in the amount of $2.3 million, which is payable in 48 monthly installments
over four years and bears interest at the prime rate. The Company recorded no
gain or loss on this transaction.
(2) BASIS OF PRESENTATION
Certain costs, such as depreciation, depletion and amortization, general
and administrative expenses and federal and state income taxes were not
allocated to the above properties because the property interests and related
assets and gathering systems acquired represent only a portion of EOG's business
and the costs incurred by EOG are not necessarily indicative of the costs to be
incurred by the Company. Historical financial information reflecting financial
position, results of operations and cash flows of the Sawyer Canyon Properties
are not presented because the entire acquisition cost was assigned to the gas
and oil property interests and the related gathering systems. Accordingly, the
historical statements of revenues and direct operating expenses have been
presented in lieu of the financial statements required under Rule 3-05 of
Securities and Exchange Commission Regulation S-X.
Revenues and direct operating expenses for the gas and oil properties
included in the accompanying statement represent EOG's interest in the
properties and are presented on the accrual basis of accounting and may not be
representative of future operations. Revenues on the oil and gas properties are
shown net of any applicable severance taxes. Certain of the oil and gas
properties qualify as high-cost natural gas wells and are currently exempt from
Texas severance taxes. Depreciation, depletion and amortization, allocated
general and administrative expenses and federal and state income taxes have been
excluded.
Revenues and direct operating expenses for the two gathering systems are
presented on the accrual basis of accounting and may not be representative of
future operations. Depreciation, depletion and amortization, allocated general
and administrative expenses and federal and state income taxes have been
excluded.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of revenues and direct operating
expenses during the reporting period. Actual results could differ from those
estimates.
F-44
<PAGE> 109
SAWYER CANYON PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES -- (CONTINUED)
(3) RELATED PARTY TRANSACTIONS
Included in oil and gas revenues (excluding severance taxes and gathering
and transportation expenses) for the gas and oil properties is approximately
$21.2 million, $13.0 million and $3.0 million for the years ended December 31,
1994 and 1995, and the three months ended March 31, 1996, respectively, related
to the sale of natural gas, crude oil and condensate volumes to affiliates of
EOG.
Included in revenues for the two gathering systems is approximately $1.8
million, $1.2 million and $0.3 million for the years ended December 31, 1994 and
1995, and the three months ended March 31, 1996, respectively, from the
transportation of natural gas for EOG's production volumes, which are shown as a
reduction in the related oil and gas revenues.
(4) COMMITMENTS AND CONTINGENCIES
Pursuant to the terms of the Agreement, certain claims, litigation, or
disputes pending as of the effective date and certain matters arising in
connection with ownership of the properties or the gathering systems prior to
the effective date are retained by EOG.
(5) SUPPLEMENTAL FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
Users of the following information should be aware that the process of
estimating quantities of proved and proved developed oil and gas reserves is
very complex, requiring significant subjective decisions in the evaluation of
all available geological, engineering and economic data for each reservoir. The
data for a given reservoir may also change substantially over time as a result
of numerous factors including, but not limited to, additional development
activity, evolving production history and continual reassessment of the
viability of production under varying economic conditions. Consequently,
material revisions to existing reserve estimates occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the significance of
the subjective decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other estimates
presented in connection with financial statement disclosures.
Proved reserves are estimated quantities of natural gas, crude oil and
condensate, that geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known reservoirs under
economic and operating conditions existing at the time the estimates were made.
Proved developed reserves are proved reserves expected to be recovered
through wells and equipment in place and under operating methods being utilized
at the time the estimates were made.
Estimates of proved and proved developed reserves at December 31, 1993 and
1994 were based on studies performed by the engineering staff of EOG. Estimates
of proved and proved developed reserves at December 31, 1995 are based on
estimates prepared by Netherland, Sewell and Associates, Inc.
F-45
<PAGE> 110
SAWYER CANYON PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES -- (CONTINUED)
Estimated Net Quantities of Oil and Gas Reserves
<TABLE>
<CAPTION>
OIL AND
GAS LIQUIDS
(MMCF) (MBBI)
------- -------
<S> <C> <C>
Net proved reserves at December 31, 1993........................... 79,614 51
Production....................................................... (10,903) (32)
------- ---
Net proved reserves at December 31, 1994........................... 68,711 19
Production....................................................... (8,145) (17)
Revisions of previous estimates and other........................ (2,812) 77
------- ---
Net proved reserves at December 31, 1995........................... 57,754 79
======= ===
Net proved developed reserves
at December 31, 1994............................................. 66,449 40
at December 31, 1995............................................. 55,546 72
</TABLE>
F-46
<PAGE> 111
SAWYER CANYON PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES -- (CONTINUED)
Standardized Measure of Discounted Future Net Cash Flows Relating to Oil and
Gas Properties
The following information has been developed utilizing procedures described
by Statement of Financial Accounting Standards No. 69 "Disclosures About Oil and
Gas Producing Activities" and based on oil and gas reserve and production
volumes estimated by the engineering staff of Netherland, Sewell and Associates,
Inc. It may be useful for certain comparison purposes, but should not be solely
relied upon in evaluating the oil and gas properties or their performance.
Further, information contained in the following table should not be considered
as representative of realistic assessments of future cash flows, nor should the
Standardized Measure of Discounted Future Net Cash Flows be viewed as
representative of the current value of the oil and gas properties.
The future cash flows presented below are based on sales prices, cost
rates, and statutory income tax rates in existence as of the date of the
projections estimated by Netherland, Sewell and Associates, Inc. It is possible
that material revisions to some estimates of natural gas and crude oil reserves
may occur in the future development and production of the reserves may occur in
periods other than those assumed, and actual prices realized and costs incurred
may vary significantly from those used.
The future cash flows presented by the Company in the future will be based
on the Company's cost structure and timing of future development and production
and accordingly may be significantly different from those of EOG.
<TABLE>
<CAPTION>
DECEMBER 31, 1994 DECEMBER 31, 1995
----------------- -----------------
(IN THOUSANDS)
<S> <C> <C>
Future cash inflows............................... $ 145,946 $ 133,190
Future production costs........................... (45,659) (43,034)
Future development costs.......................... (1,573) (1,573)
-------- --------
Future net cash flows............................. 98,714 88,583
Discount to present value at 10% annual rate...... (39,129) (33,171)
-------- --------
Standardized measure of discounted future net cash
flows relating to proved oil and gas reserves... $ 59,585 $ 55,412
======== ========
</TABLE>
Changes in Standardized Measure of Discounted Future Net Cash Flows
The following table sets forth the changes in the standardized measure of
discounted future net cash flows relating to proved oil and gas reserves for the
years ended December 31, 1994 and 1995:
<TABLE>
<CAPTION>
DECEMBER 31, 1994 DECEMBER 31, 1995
----------------- -----------------
(IN THOUSANDS)
<S> <C> <C>
Beginning of period............................... $ 70,565 $ 59,585
Accretion of discount............................. 7,056 5,958
Sales of oil and gas, net of production costs..... (18,036) (10,131)
-------- --------
Net decrease...................................... (10,980) (4,173)
-------- --------
End of period..................................... $ 59,585 $ 55,412
======== ========
</TABLE>
F-47
<PAGE> 112
NO DEALER, SALESPERSON OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS OTHER THAN THOSE CONTAINED IN OR
INCORPORATED BY REFERENCE IN THIS PROSPECTUS IN CONNECTION WITH THE OFFER MADE
BY THIS PROSPECTUS AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATIONS
MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE COMPANY OR ANY OF THE
UNDERWRITERS. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE
HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THERE HAS
BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE THE DATE HEREOF. THIS
PROSPECTUS DOES NOT CONSTITUTE AN OFFER OR SOLICITATION BY ANYONE IN ANY
JURISDICTION IN WHICH SUCH OFFER OR SOLICITATION IS NOT AUTHORIZED OR IN WHICH
THE PERSON MAKING SUCH OFFER OR SOLICITATION IS NOT QUALIFIED TO DO SO OR TO ANY
PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH SOLICITATION.
---------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
<S> <C>
Prospectus Summary........................ 3
Risk Factors.............................. 10
Disclosure Regarding Forward-Looking
Statements.............................. 13
Use of Proceeds........................... 14
Capitalization............................ 15
Price Range of Common Stock............... 16
Dividend Policy........................... 16
Pro Forma Financial Information........... 17
Management's Discussion and Analysis of
Financial Condition and Results of
Operations.............................. 24
Business and Properties................... 33
Management................................ 54
Security Ownership by Certain Beneficial
Owners and Management................... 56
Description of Capital Stock.............. 57
Underwriting.............................. 59
Certain Legal Matters..................... 61
Accountants............................... 61
Reserve Engineers......................... 61
Available Information..................... 61
Incorporation of Certain Documents by
Reference............................... 62
Glossary.................................. 63
Index to Financial Statements............. F-1
</TABLE>
3,000,000 SHARES
KCS ENERGY, INC.
COMMON STOCK
($.01 PAR VALUE)
KCS ENERGY CORP. LOGO
SALOMON BROTHERS INC
DONALDSON, LUFKIN & JENRETTE
SECURITIES CORPORATION
PRUDENTIAL SECURITIES INCORPORATED
MORGAN KEEGAN &
COMPANY, INC.
SOUTHCOAST CAPITAL
CORPORATION
PROSPECTUS
DATED JANUARY 29, 1997
<PAGE> 113
Filed Pursuant to Rule 424(b)(4)
Registration No. 333-15581
PROSPECTUS
3,000,000 SHARES
KCS ENERGY, INC.
[KCS ENERGY CORP. LOGO]
COMMON STOCK
($.01 PAR VALUE)
The shares of Common Stock, par value $.01 per share (the "Common Stock"), of
KCS Energy, Inc. ("KCS" or the "Company") being offered hereby (the "Shares")
are being issued and sold by the Company.
The Shares are being sold in two concurrent offerings (the "Offerings"), one
offering initially in the United States and Canada (the "U.S. Offering") through
U.S. underwriters (the "U.S. Underwriters") and one initially outside the United
States and Canada (the "International Offering") through international
underwriters (the "International Underwriters"). The U.S. Underwriters and the
International Underwriters are hereinafter collectively referred to as the
"Underwriters." Of the 3,000,000 Shares being offered, 2,400,000 are being
offered in the U.S. Offering and 600,000 are being offered in the International
Offering, subject to transfers between the U.S. Underwriters and the
International Underwriters. See "Underwriting."
The Common Stock is listed on the New York Stock Exchange under the symbol
"KCS." On January 29, 1997, the last reported sale price for the Common Stock,
as reported on the New York Stock Exchange Composite Transactions Tape, was
$39.625 per share. See "Price Range of Common Stock."
SEE "RISK FACTORS" BEGINNING ON PAGE 10 FOR A DISCUSSION OF CERTAIN FACTORS THAT
SHOULD BE CONSIDERED BY PROSPECTIVE PURCHASERS OF THE COMMON STOCK.
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
- --------------------------------------------------------------------------------
<TABLE>
<S> <C> <C> <C>
PRICE TO UNDERWRITING PROCEEDS TO
PUBLIC DISCOUNT COMPANY(1)
Per Share....................... $39.00 $1.80 $37.20
Total(2)........................ $117,000,000 $5,400,000 $111,600,000
</TABLE>
- --------------------------------------------------------------------------------
(1) Before deducting offering expenses payable by the Company, estimated at
$883,125.
(2) The Company has granted the Underwriters 30-day options to purchase up to an
aggregate of 360,000 and 90,000 additional shares of Common Stock,
respectively, at the Price to Public, less Underwriting Discount, solely to
cover over-allotments, if any. If the Underwriters exercise such options in
full, the total Price to Public, Underwriting Discount and Proceeds to
Company will be $134,550,000, $6,210,000 and $128,340,000, respectively. See
"Underwriting."
The Common Stock is offered subject to receipt and acceptance by the
Underwriters, to prior sale and to the Underwriters' right to reject any order
in whole or in part and to withdraw, cancel or modify the offer without notice.
It is expected that delivery of the Common Stock will be made at the office of
Salomon Brothers Inc, Seven World Trade Center, New York, New York, or through
the facilities of The Depository Trust Company, on or about February 4, 1997.
SALOMON BROTHERS INTERNATIONAL LIMITED
DONALDSON, LUFKIN & JENRETTE
SECURITIES CORPORATION
PRUDENTIAL-BACHE SECURITIES
MORGAN KEEGAN & COMPANY, INC.
SOUTHCOAST CAPITAL
CORPORATION
The date of this Prospectus is January 29, 1997.
<PAGE> 114
[ALTERNATE INSIDE FRONT COVER PAGE FOR INTERNATIONAL PROSPECTUS]
FOR UNITED KINGDOM PURCHASERS: THE SHARES OF COMMON STOCK MAY NOT BE OFFERED OR
SOLD IN THE UNITED KINGDOM OTHER THAN TO PERSONS WHOSE ORDINARY ACTIVITIES
INVOLVE THEM IN ACQUIRING, HOLDING, MANAGING OR DISPOSING OF INVESTMENTS,
WHETHER AS PRINCIPAL OR AGENT (EXCEPT IN CIRCUMSTANCES THAT DO NOT CONSTITUTE AN
OFFER TO THE PUBLIC WITHIN THE MEANING OF THE PUBLIC OFFERS OF SECURITIES
REGULATIONS 1995 OR THE FINANCIAL SERVICES ACT 1986), AND THIS PROSPECTUS MAY
ONLY BE ISSUED OR PASSED ON TO ANY PERSON IN THE UNITED KINGDOM IF THAT PERSON
IS OF A KIND DESCRIBED IN ARTICLE 11(3) OF THE FINANCIAL SERVICES ACT 1986
(INVESTMENT ADVERTISEMENTS) (EXEMPTIONS) ORDER 1996 OR IS A PERSON TO WHOM THE
PROSPECTUS MAY OTHERWISE LAWFULLY BE PASSED ON.
IN CONNECTION WITH THE OFFERINGS, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE
COMMON STOCK AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN
MARKET. SUCH STABILIZING TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK STOCK
EXCHANGE OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT
ANY TIME.
<PAGE> 115
PROSPECTUS SUMMARY
The following summary is qualified in its entirety by the more detailed
information and financial statements (including the notes thereto) included
elsewhere in this Prospectus and in the documents incorporated herein by
reference. Unless the context otherwise requires, "Company" and "KCS" refer to
KCS Energy, Inc. and its consolidated subsidiaries. Except as otherwise
specified, all data set forth in this Prospectus assumes no exercise of the
Underwriters' over-allotment options. See "Glossary" for definitions of certain
terms used herein.
THE COMPANY
GENERAL
KCS Energy, Inc. ("KCS" or the "Company") is an independent oil and gas
company primarily engaged in the acquisition, exploitation, development and, to
a lesser extent, exploration of domestic oil and gas properties, and in the
production and marketing of oil and gas. Through its experienced management and
geological and engineering staff, the Company has successfully increased the
value of its properties through drilling and other exploitation techniques and
has substantially increased its reserves, production and cash flow. Over the
five-year period ended December 31, 1995, KCS replaced 400% of production and
increased proved oil and gas reserves 395% to 186.1 Bcfe at December 31, 1995.
During the same period, the Company increased its oil and gas production 392% to
20.3 Bcfe, representing a compound annual growth rate of 49%. In addition, the
Company increased EBITDA from $7.1 million in 1991 to $75.1 million in 1995.
The Company's operations to date have focused primarily on properties in
the onshore Gulf Coast and Rocky Mountain regions. KCS augments its working
interest ownership of properties with a volumetric production payment ("VPP")
program to acquire oil and gas from properties which to date have been located
primarily in the offshore Gulf Coast region and in the Niagaran Reef trend in
Michigan. As of December 31, 1996, the Company completed the arrangements for
the acquisition of InterCoast Oil and Gas Company (formerly Medallion Production
Company and renamed KCS Medallion Resources, Inc.) and certain of its affiliates
(the "Medallion Acquisition"), the Company's largest acquisition to date. The
Medallion Acquisition expanded the Company's operations to include a third core
operating area, the Mid-Continent region, encompassing west Texas, the Texas
Panhandle, northwest Oklahoma and north Louisiana. At June 30, 1996, on a pro
forma basis reflecting the Medallion Acquisition, proved oil and gas reserves
were 369.4 Bcfe (84% proved developed), approximately double the Company's
historical proved reserves at December 31, 1995, and represented a PV-10 value
of $408.3 million. Approximately 63% of the Company's reserves on a pro forma
basis are attributable to wells it operates.
Historically, the Company's most significant field was the Bob West Field
in south Texas, which accounted for approximately 16% (8% on a pro forma basis)
of the Company's production during the nine months ended September 30, 1996.
Most of the Company's natural gas sold from the Bob West Field was covered by an
above-market, take-or-pay contract (the "Tennessee Gas Contract") with Tennessee
Gas Pipeline Company ("Tennessee Gas"), which had been the subject of several
lawsuits. On December 23, 1996, the Company and Tennessee Gas entered into a
settlement covering all claims and litigation between them related to the
Tennessee Gas Contract. As part of the settlement, the Tennessee Gas Contract
was terminated effective January 1, 1997, approximately two years prior to its
expiration date. The parties also agreed to the dismissal of the contract
dispute that resulted in a November 1996 jury award to Tennessee Gas of $143.2
million (including punitive damages of approximately $114 million). The December
1996 settlement did not affect the Company's successful conclusion of litigation
earlier in the year relating to the validity and pricing provisions of the
Tennessee Gas Contract and its recovery of past underpayments that had accrued
under the contract (the "Tennessee Gas Receivable").
3
<PAGE> 116
BUSINESS STRATEGY
The Company has grown through a strategy of reserve acquisitions and
development and exploratory drilling. The Company plans to continue to broaden
its reserve base and increase production and cash flow through (i) the
acquisition of attractively priced oil and gas companies and producing
properties that provide additional development or exploratory potential, (ii)
the exploitation and development of its existing asset base, (iii) the operation
and ownership of a majority working interest in a significant number of its
properties to allow the Company greater control over future development,
drilling, completing and lifting costs and marketing of production, (iv) the
acquisition of oil and gas reserves through the VPP program, (v) the pursuit of
a balanced exploration program that includes a number of high-potential
opportunities, and (vi) the extensive use of advanced technologies, most notably
3-D seismic, computer-enhanced basin analysis, reservoir simulation and
specialized drilling applications and stimulation techniques to better delineate
or produce reserves.
To implement its strategy, the Company intends to take advantage of several
key strengths, including (i) an experienced and capable team of oil and gas
industry professionals with a meaningful financial stake in the success of the
Company, (ii) a significant inventory of attractive development and exploratory
drilling opportunities within its existing property base and undeveloped acreage
position, (iii) established relationships with proven industry partners that
provide opportunities to participate in diverse exploration prospects, (iv) an
efficient administrative and operating structure that emphasizes an
entrepreneurial and opportunistic approach, and (v) a strong financial focus
which manifests itself not only in innovative transactions, but also in asset
risk management.
ACQUISITION ACTIVITIES
Medallion Acquisition. As of December 31, 1996, the Company completed the
arrangements for the acquisition of all outstanding stock of InterCoast Oil and
Gas Company (formerly Medallion Production Company), GED Energy Services, Inc.
and InterCoast Gas Services Company (collectively referred to as "Medallion"),
indirect wholly-owned subsidiaries of MidAmerican Energy Holdings Company
("MidAmerican"), for a total purchase price of approximately $214.4 million,
consisting of $209.4 million in cash (reduced at closing by $15.3 million
principally to reflect free cash flow from Medallion's operations subsequent to
the July 1, 1996 effective date) and warrants to purchase 435,000 shares of
Common Stock. Medallion's principal assets, estimated as of June 30, 1996, were
202.1 Bcfe of proved oil and gas reserves, consisting of 161.3 Bcf of natural
gas (80% of total proved reserves) and 6.8 MMbbls of oil and condensate, located
primarily in the Mid-Continent region. Proved developed reserves account for 88%
of Medallion's total proved reserves, and approximately 68% of these reserves
are attributable to wells it operates. The Medallion Acquisition more than
doubled the Company's reserve base and added substantial management and
technical expertise, particularly in the new Mid-Continent core area.
Over the three and one half-year period ended June 30, 1996, Medallion
replaced 251% of its production and increased reserves 148% through property
acquisitions, its Extensional Infill Drilling ("EID") program and, to a lesser
extent, exploratory drilling, all of which the Company expects to continue.
Since its acquisition by MidAmerican in April 1992, Medallion has acquired 188.7
Bcfe of proved reserves through 31 acquisitions at an average acquisition cost
of $0.67 per Mcfe. Medallion's EID program allows it to drill and produce a
greater amount of reserves within producing fields than would otherwise be
produced without making a major capital investment in undeveloped leasehold
acreage. During the three-year period ended December 31, 1995, Medallion added
53.7 Bcfe of proved reserves at an average finding cost of $0.75 per Mcfe by
successfully completing 52 of 87 EID prospects.
Rocky Mountain Acquisition. In November 1995, the Company acquired
substantially all of the oil and gas assets of Natural Gas Processing Company
for a purchase price of approximately $33 million (the "Rocky Mountain
Acquisition"). The Company acquired interests in over 30 different fields,
principally in six producing basins located in Wyoming, Colorado, Montana and
North Dakota. Proved reserves attributable to the properties acquired were
estimated to be 66.7 Bcfe at September 30, 1995, consisting of 40.9 Bcf of
natural gas and 4.3 MMbbls of oil and representing an average acquisition cost
4
<PAGE> 117
of $0.49 per Mcfe. Since the acquisition, the Company has undertaken an
aggressive field development and acreage acquisition program in the Rocky
Mountain region which has resulted in several recent drilling successes and
prospective drilling opportunities, most notably in the Manderson Field in
Wyoming. Approximately half of the natural gas production from the acquired
properties is subject to multi-year contracts with local utility companies at
prices that range from $1.70 to $2.00 per Mcf.
Michigan Acquisition. In December 1995, the Company acquired 24.6 Bcfe of
proved reserves in the northern and southern Niagaran Reef trends in Michigan
for $31 million, including a volumetric production payment covering certain
reserves, escalating working interests in related properties and participation
rights and an overriding royalty interest in an exploration program,
representing an average acquisition cost of $1.26 per Mcfe (the "Michigan
Acquisition"). The VPP provides for the delivery to the Company of 13.7 Bcf of
natural gas and 1.1 MMbbls of oil to be delivered (without any burden of
development and lease operating expenses) from December 1995 through January
2006. Based on independent reserve reports as of September 30, 1995, the
separately acquired working interests added 3.1 Bcf of natural gas and 219 Mbbls
of oil to the Company's proved reserves.
DEVELOPMENT AND EXPLORATION ACTIVITIES
During the three-year period ended December 31, 1995, the Company
participated in the drilling of 61 development wells with a 98% success rate.
The majority of this development (38 wells and 38 completions) was in the Bob
West Field. During the first nine months of 1996, however, the Company
substantially increased its level of development drilling in other areas and
drilled 27 of 29 wells and completed 24 of 27 wells in areas other than the Bob
West Field. The Company's activities outside the Bob West Field are now focused
on the Manderson Field in the Big Horn Basin of Wyoming, the Sweet Grass Arch
area of Montana, the Langham Creek Area and Glasscock Ranch Fields in Texas and
the Laurel Ridge Field and the Tensas Parish Area in Louisiana. The Company has
currently identified over 450 development drilling and recompletion locations
and 170 EID locations, representing approximately a four-year inventory, and has
initially budgeted $70 million for development activities in 1997. The Company
intends to focus its development efforts primarily on the fields in the Rocky
Mountain and onshore Gulf Coast regions described above and on its newly
acquired properties in the Mid-Continent region.
During the three-year period ended December 31, 1995, the Company
participated in the drilling of 58 exploratory wells with a 50% success rate.
Discoveries included wells in the Bob West Field, Langham Creek Area and Laurel
Ridge Field. During the first nine months of 1996, the Company participated in
the drilling of 11 exploratory wells (all of which were outside the Bob West
Field) and completed five wells, two of which it operates. Discoveries in 1996
included the Aubrey and Wilsonia Fields in the Tensas Parish Area in Louisiana.
The Company has interests in more than 172,000 gross (140,000 net) undeveloped
acres and has established an initial budget of $25 million for exploration in
1997, including amounts for 3-D seismic data acquisition and analysis. The
Company intends to participate in up to 50 prospects in 1997, including both
low-risk and high-risk, high-potential projects in order to maintain a balanced
program with the potential for significant reserve additions. Exploration
activities will focus primarily on properties located in the onshore Gulf Coast
regions of Texas and Louisiana and in the Rocky Mountains. The Company also
intends to further analyze the undeveloped acreage it acquired in the Medallion
Acquisition for possible exploration projects and to continue its participation
in exploration projects in Michigan.
The Company's executive offices are located at 379 Thornall Street, Edison,
New Jersey 08837 and its telephone number is (908) 632-1770.
5
<PAGE> 118
THE OFFERINGS
<TABLE>
<S> <C>
Common Stock offered by the Company:
U.S. Offering........................... 2,400,000 shares
International Offering.................. 600,000 shares
--------------
Total.............................. 3,000,000 shares
Common Stock to be outstanding after the
Offerings.................................. 14,587,422 shares(1)
Use of proceeds.............................. The net proceeds will be used to reduce the
outstanding indebtedness under the Company's
Bank Credit Facilities, including the
Revolving Credit Agreement used to fund a
portion of the Medallion Acquisition. See
"Use of Proceeds" and "Business and
Properties -- Recent
Acquisitions -- Medallion Acquisition."
New York Stock Exchange symbol............... KCS
</TABLE>
- ---------------
(1) Does not include 529,575 shares of Common Stock reserved for issuance
pursuant to outstanding stock options and warrants to purchase 435,000
shares of Common Stock issued in connection with the Medallion Acquisition.
RISK FACTORS
In addition to the other information in this Prospectus, prospective
purchasers of the Common Stock should carefully consider certain risk factors in
evaluating an investment in the Common Stock. See "Risk Factors."
6
<PAGE> 119
SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
The following table sets forth selected historical and pro forma financial
information of the Company and should be read in conjunction with the financial
statements (including the notes thereto) of KCS Energy, Inc., the InterCoast
Entities (Medallion) and the Sawyer Canyon Properties and the information under
the captions "Pro Forma Financial Information" and "Management's Discussion and
Analysis of Financial Condition and Results of Operations" included elsewhere in
this Prospectus.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------------------------------- --------------------------------------------
PRO FORMA PRO FORMA
AS ADJUSTED(1)(2) AS ADJUSTED(2)(3)
1993 1994 1995 1995 1995 1996 1996
---------- ---------- ---------- ----------------- ---------- ----------- -----------------
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenue:
Oil and gas exploration
and production........ $ 40,455 $ 66,215 $ 86,629 $ 162,857 $ 63,425 $ 79,051 $ 134,020
Natural gas
transportation and
marketing............. 264,710 279,155 365,354 450,502 270,557 238,254 347,533
Intercompany............ (876) (3,657) (2,018) (2,018) (1,708) (701) (701)
---------- ---------- ---------- ---------- ---------- ----------- ----------
Total............. 304,289 341,713 449,965 611,341 332,274 316,604 480,852
Operating costs and
expenses:
Cost of natural gas
sales................. 253,435 265,076 356,186 437,763 264,097 231,063 337,609
Other operating and
administrative
expenses.............. 15,018 18,285 18,669 44,672 12,950 19,427 35,955
Depreciation, depletion
and amortization...... 8,036 19,740 39,209 66,732 29,299 33,933 54,377
---------- ---------- ---------- ---------- ---------- ----------- ----------
Total............. 276,489 303,101 414,064 549,167 306,346 284,423 427,941
---------- ---------- ---------- ---------- ---------- ----------- ----------
Operating income......... 27,800 38,612 35,901 62,174 25,928 32,181 52,911
Interest and other
income, net............. 704 1,039 3,713 3,713 2,311 4,850 4,850
Interest expense......... (1,983) (2,938) (7,732) (25,667) (4,912) (13,858) (18,073)
---------- ---------- ---------- ---------- ---------- ----------- ----------
Income before income
taxes................... 26,521 36,713 31,882 40,220 23,327 23,173 39,688
Federal and state income
taxes................... 7,910 12,556 10,576 13,568 7,645 8,367 14,266
---------- ---------- ---------- ---------- ---------- ----------- ----------
Net income............... $ 18,611 $ 24,157 $ 21,306 $ 26,652 $ 15,682 $ 14,806 $ 25,422
========== ========== ========== ========== ========== =========== ==========
Earnings per share....... $ 1.60 $ 2.05 $ 1.81 $ 1.81 $ 1.33 $ 1.25 $ 1.71
Average common shares
outstanding............. 11,658,370 11,804,989 11,760,701 14,760,701 11,766,011 11,886,434 14,886,434
Dividend per common
share................... $ 0.06 $ 0.09 $ 0.12 $ 0.12 $ 0.09 $ 0.09 $ 0.09
OTHER DATA:
EBITDA(4)................ $ 35,836 $ 58,352 $ 75,110 $ 128,906 $ 55,227 $ 66,114 $ 107,288
Capital expenditures..... 48,455 74,953 128,699 340,240 57,455 52,735 264,276
</TABLE>
<TABLE>
<CAPTION>
SEPTEMBER 30, 1996
----------------------------------------------------
PRO FORMA
HISTORICAL PRO FORMA(3) AS ADJUSTED(2)(3)
---------- ------------ -----------------
(UNAUDITED)
<S> <C> <C> <C>
BALANCE SHEET DATA:
Cash and cash equivalents................................... $ 53,597 $ 7,109 $ 7,109
Working capital............................................. 56,970 16,906 16,906
Oil and gas properties, net................................. 206,308 400,583 400,583
Total assets................................................ 341,152 528,311 528,311
Long-term debt.............................................. 149,830 306,343 195,626
Total stockholders' equity.................................. 116,312 121,310 232,027
</TABLE>
- ---------------
(1) Gives effect to the Medallion Acquisition, the acquisition of the Sawyer
Canyon Properties by Medallion, the Company's Rocky Mountain Acquisition and
Michigan Acquisition and the Company's Senior Notes offering as if each
transaction had occurred on January 1, 1995.
(2) Gives effect to the Offerings.
(3) Gives effect to the Medallion Acquisition and the acquisition of the Sawyer
Canyon Properties by Medallion and the application of $50.0 million of cash
to reduce long-term debt.
(4) EBITDA represents income before depletion, depreciation, amortization,
interest expense, interest and other income and income taxes. EBITDA is a
financial measure commonly used in the Company's industry and should not be
considered in isolation or as a substitute for net income, cash flow
provided by operating activities or other income or cash flow data prepared
in accordance with generally accepted accounting principles or as a measure
of a company's profitability or liquidity.
7
<PAGE> 120
SUMMARY HISTORICAL AND PRO FORMA OIL AND GAS RESERVE AND OPERATING DATA -- KCS
The following table sets forth summary information with respect to
estimates of the Company's proved oil and gas reserves at the end of the periods
indicated. The table also sets forth information with respect to estimates of
the pro forma proved reserves at June 30, 1996, after giving effect to the
Medallion Acquisition. Net production data and other data at September 30, 1996
are also shown giving pro forma effect to the Medallion Acquisition. For
additional information relating to the Company's oil and gas reserves and
operating data, see "Business and Properties," "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the notes to the
Consolidated Financial Statements included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
HISTORICAL
-----------------------------------------------
DECEMBER 31, PRO FORMA
----------------------------------- JUNE 30, JUNE 30,
1993 1994 1995 1996 1996
--------- --------- --------- -------- ---------
<S> <C> <C> <C> <C> <C>
RESERVE DATA:
Proved developed reserves:
Oil (Mbbls)............................ 1,579 1,336 3,808 4,377 10,856
Natural gas (MMcf)..................... 61,016 74,215 121,987 105,709 244,120
Total (MMcfe)........................ 70,490 82,231 144,835 131,971 309,256
Proved undeveloped reserves:
Oil (Mbbls)............................ 999 983 3,709 3,421 3,739
Natural gas (MMcf)..................... 8,724 14,969 18,976 14,833 37,753
Total (MMcfe)........................ 14,718 20,867 41,230 35,359 60,187
Total proved reserves:
Oil (Mbbls)............................ 2,578 2,319 7,517 7,798 14,595
Natural gas (MMcf)..................... 69,740 89,184 140,963 120,542 281,873
Total (MMcfe)........................ 85,208 103,098 186,065 167,330 369,443
Estimated future net revenue before
income taxes ($000) (1)(2)............. $334,209(3) $307,533 $405,049 $288,024(4) $602,375(4)
Present value of estimated future net
revenues before income taxes ($000)
(2)(5)................................. $250,275(3) $241,705 $291,085 $196,826(4) $408,265(4)
Standardized measure of discounted future
net cash flows ($000) (2)(6)........... $185,534(3) $179,660 $231,763 -- --
Reserve replacement percentage........... 412.8% 242.3% 527.2% -- --
Reserve life (in years).................. 10.6 8.2 9.2 -- --
</TABLE>
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------------------- ----------------------------
PRO FORMA PRO FORMA
1993 1994 1995 1995 1995 1996 1996
------ ------- ------- --------- ------ ------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
NET PRODUCTION DATA:
Oil (Mbbls)......................... 179 211 196 1,224 111 547 1,324
Natural gas (MMcf):
Tennessee Gas Contract............ 4,472 6,851 6,924 6,924 5,446 3,576 3,576
Other............................. 2,505 4,453 12,205 30,040 7,858 15,346 32,756
------ ------- ------- ------- ------ ------- -------
Total........................... 6,977 11,304 19,129 36,964 13,304 18,922 36,332
Total (MMcfe)....................... 8,051 12,570 20,305 44,308 13,970 22,204 44,276
OTHER DATA:
Average sales prices:
Oil (per bbl)..................... $17.57 $ 15.16 $ 17.28 $ 16.58 $17.53 $ 19.72 $ 19.24
Natural gas (per Mcf):
Tennessee Gas Contract.......... 7.09 7.49 7.90 7.90 7.84 8.38 8.38
Other........................... 2.02 1.81 1.62 1.64 1.56 2.29 2.13
Average......................... 5.27 5.54 4.29 3.02 4.60 3.61 2.84
Average equivalent sales price
(per Mcfe)........................ $ 5.02 $ 5.27 $ 4.27 $ 2.97 $ 4.54 $ 3.56 $ 2.90
Average lifting cost (per Mcfe)..... 0.62 0.56 0.33 0.48 0.31 0.37 0.47
General and administrative expense
(per Mcfe)(7)..................... 0.52 0.39 0.23 0.17 0.24 0.25 0.20
------ ------- ------- ------- ------ ------- -------
Cash margin (per Mcfe).............. $ 3.88 $ 4.32 $ 3.71 $ 2.32 $ 3.99 $ 2.94 $ 2.23
</TABLE>
- ---------------
(1) Reflects estimated future cash inflows less future production and
development costs.
(2) Estimates at December 31 in 1993, 1994 and 1995 reflect the contract price
to be paid for natural gas delivered from the Bob West Field under the
Tennessee Gas Contract until January 1999.
(3) Reflects data as of September 30, 1993, the Company's former fiscal year
end.
(4) As a result of the early termination of the Tennessee Gas Contract effective
January 1, 1997, estimates at each of Historical and Pro Forma June 30, 1996
reflect downward revisions from earlier reserve reports in the amounts of
$59.5 million for estimated future net revenues before income taxes (based
upon an estimated realized spot market price for natural gas of $2.10 per
Mcf at June 30, 1996) and $51.4 million for present value of estimated
future net revenues before income taxes. See "Business and
Properties -- Legal Proceedings -- Tennessee Gas Litigation."
(5) Reflects estimated future net revenue before income taxes discounted at 10%
per annum.
(6) Reflects present value of estimated future net revenue before income taxes,
less future income taxes discounted at 10% per annum.
(7) Includes all corporate general and administrative expenses.
8
<PAGE> 121
SUMMARY HISTORICAL AND PRO FORMA OIL AND GAS RESERVE AND OPERATING
DATA -- MEDALLION
The following tables set forth summary information with respect to
estimates of Medallion's proved oil and gas reserves at the end of the periods
indicated and production and prices for the periods indicated. For additional
information relating to Medallion's oil and gas reserves and operating data, see
"Business and Properties" and the notes to the Combined Financial Statements of
the InterCoast Entities (Medallion) included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------ JUNE 30,
1993 1994 1995 1996
-------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
RESERVE DATA:
Proved developed reserves:
Oil (Mbbls)........................ 8,173 6,717 8,255 6,479
Natural gas (MMcf)................. 100,660 115,099 111,189 138,411
Total (MMcfe)................... 149,698 155,401 160,719 177,285
Proved undeveloped reserves:
Oil (Mbbls)........................ 782 587 1,589 318
Natural gas (MMcf)................. 11,363 33,512 22,484 22,920
Total (MMcfe)................... 16,055 37,034 32,018 24,828
Total proved reserves:
Oil (Mbbls)........................ 8,955 7,304 9,844 6,797
Natural gas (MMcf)................. 112,023 148,611 133,673 161,331
Total (MMcfe)................... 165,754 192,435 192,737 202,113
Estimated future net revenue before
income taxes ($000)(1)............. $220,335 $221,513 $258,220 $314,351
Present value of estimated future net
revenues before income taxes
($000)(2).......................... $137,711 $144,595 $168,159 $211,439
Standardized measure of discounted
future net cash flows ($000)(3).... $118,202 $126,044 $136,924 --
Reserve replacement percentage....... 612.0% 263.0% 107.0% --
Reserve life (in years).............. 9.8 8.9 8.0 --
</TABLE>
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------ -------------------
1993 1994 1995 1995 1996
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
NET PRODUCTION DATA:
Oil (Mbbls).......................... 691 1,024 1,028 780 777
Natural gas (MMcf)................... 12,742 15,591 17,835 12,991 17,410
Total (MMcfe)........................ 16,888 21,735 24,003 17,671 22,072
OTHER DATA:
Average sales prices:
Oil (per bbl)...................... $ 16.06 $ 14.93 $ 16.45 $ 16.54 $ 18.92
Natural gas (per Mcf).............. 2.04 1.82 1.65 1.58 2.00
Average equivalent sales price (per
Mcfe).............................. 2.20 2.01 1.93 1.89 2.24
Average lifting cost (per Mcfe)...... 0.56 0.69 0.61 0.62 0.56
</TABLE>
- ---------------
(1) Reflects estimated future cash inflows less future production and
development costs.
(2) Reflects estimated future net revenue before income taxes discounted at 10%
per annum.
(3) Reflects present value of estimated future net revenue before income taxes,
less future income taxes discounted at 10% per annum.
9
<PAGE> 122
RISK FACTORS
In addition to the other information set forth in this Prospectus,
prospective purchasers of the Common Stock should carefully consider the
following risk factors in evaluating an investment in the Common Stock. This
Prospectus contains forward-looking statements which involve certain
assumptions, risks and uncertainties. The Company's actual results could differ
materially from those anticipated in these forward-looking statements as a
result of certain factors, including those set forth in the following risk
factors and elsewhere in this Prospectus. See "Disclosure Regarding
Forward-Looking Statements."
VOLATILE NATURE OF OIL AND GAS MARKETS; FLUCTUATIONS IN PRICES
The Company's future financial condition and results of operations are
highly dependent on the demand and prices received for the Company's oil and gas
production and on the costs of acquiring, developing and producing reserves. Oil
and gas prices have historically been volatile and are expected by the Company
to continue to be volatile in the future. Prices for oil and gas are subject to
wide fluctuation in response to relatively minor changes in the supply of and
demand for oil and gas, market uncertainty and a variety of additional factors
that are beyond the Company's control. These factors include political
conditions in the Middle East and elsewhere, domestic and foreign supply of oil
and gas, the level of consumer demand, weather conditions, domestic and foreign
government regulations and taxes, the price and availability of alternative
fuels and overall economic conditions. A decline in oil or gas prices may
adversely affect the Company's cash flow, liquidity and profitability. Lower oil
or gas prices also may reduce the amount of the Company's oil and gas that can
be produced economically. It is impossible to predict future oil and gas price
movements with any certainty.
DEPENDENCE ON ACQUIRING AND FINDING ADDITIONAL RESERVES
The Company's prospects for future growth and profitability will depend
predominately on its ability to replace present reserves through acquisitions
and development, EID and exploratory drilling, as well as on its ability to
successfully develop additional reserves. The decision to acquire a business or
to purchase, explore or develop an interest or property will depend in part on
the evaluation of data obtained through geophysical and geological analyses and
engineering studies, the results of which are often inconclusive or subject to
varying interpretations. Acquisitions may not be available at attractive prices,
and there can be no assurance that the Company's acquisition and exploration
activities or planned development projects will result in significant additional
reserves or that the Company will have continuing success at drilling
economically productive wells. Without successfully acquiring or developing
additional reserves, the Company's proved reserves and revenues will decline.
SUBSTANTIAL CAPITAL REQUIREMENTS
The Company has made, and likely will continue to make, substantial capital
expenditures in connection with the acquisition, development and exploration of
oil and gas properties. Historically, the Company has funded its capital
expenditures with cash flow from operations and funds from long-term debt
financing, including bank financing secured by its oil and gas and natural gas
transportation assets (the "Master Note Facility"), its receivables (the
"Receivable Facility") and its VPP program assets (the "VPP Facility"). In July
1996, the Receivable Facility was repaid and terminated, and in September 1996,
the Master Note and VPP Facilities were consolidated into one revolving credit
facility (the "Credit Facility"). In addition, the Company entered into a new
revolving credit agreement simultaneously with the consummation of the Medallion
Acquisition (the "Revolving Credit Agreement") (the Credit Facility and the
Revolving Credit Agreement are collectively referred to as the "Bank Credit
Facilities"). The Company anticipates that the net proceeds from the Offerings,
together with its cash flow from operations, net proceeds from the sale of
non-strategic assets and the availability of credit under the Bank Credit
Facilities, will be sufficient to fund the approximately $160 million of capital
expenditures budgeted for drilling and acquisition activities in 1997. Future
cash flows and the availability of financing are subject to a number of
variables, such as the level of production from existing wells, prices of oil
and gas and the Company's success in locating and producing new reserves. If
revenues were to decrease as
10
<PAGE> 123
a result of lower oil and gas prices, decreased production or otherwise, and the
Company had no availability under its Bank Credit Facilities, the Company could
be limited in its ability to replace its reserves or to maintain production at
current levels, resulting in a decrease in production and revenue over time. If
the Company's cash flow from operations and availability under its Bank Credit
Facilities are not sufficient to satisfy its capital expenditure requirements,
there can be no assurance that additional debt or equity financing will be
available to meet these requirements.
RELIANCE ON ESTIMATES OF RESERVES AND FUTURE NET CASH FLOWS
There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves, including many factors beyond the Company's
control. This Prospectus includes independent engineering estimates of the
Company's oil and gas reserves and future net cash flows that are based on the
reports of three different firms. Reserve engineering is a subjective process of
estimating underground accumulations of oil and gas that cannot be measured in
an exact manner. Estimates of economically recoverable oil and gas reserves and
of future net cash flow necessarily depend upon a number of variable factors and
assumptions, such as historical production from the area compared with
production from other producing areas, the assumed effects of regulation by
governmental agencies and assumptions concerning future oil and gas prices,
operating costs, severance and excise taxes, development costs and workover and
remedial costs, all of which may in fact vary considerably from actual results.
For these reasons, estimates of the economically recoverable quantities of oil
and gas attributable to any particular group of properties, classifications of
such reserves based on risk of recovery and estimates of the future net cash
flows expected therefrom prepared by different engineers or by the same
engineers at different times may vary significantly. Actual production, revenues
and expenditures with respect to the Company's reserves likely will vary from
estimates, and such variances may be material. In addition, the Company's
reserves and future cash flows may be subject to revisions, based upon
production history, results of future development, oil and gas prices,
performance of counterparties under agreements to which the Company is a party,
operating and development costs and other factors. See "Business and
Properties -- Oil and Gas Reserves."
The PV-10 values referred to in this Prospectus should not be construed as
the current market value of the estimated oil and gas reserves attributable to
the Company's properties. In accordance with applicable requirements of the
Securities and Exchange Commission ("SEC"), PV-10 is generally based on prices
and costs as of the date of the estimate, whereas actual future prices and costs
may be materially higher or lower. Actual future net cash flows also will be
affected by factors such as the amount and timing of actual production, supply
and demand for oil and gas, curtailments or increases in consumption by natural
gas purchasers and changes in governmental regulations or taxation. The timing
of actual future net cash flows from proved reserves, and thus their actual
present value, will be affected by the timing of both the production and the
incurrence of expenses in connection with development and production of oil and
gas properties. In addition, the 10% discount factor, which is required by the
SEC to be used to calculate PV-10 for reporting purposes, is not necessarily the
most appropriate discount factor based on interest rates in effect from time to
time and risks associated with the Company and its properties or the oil and gas
industry in general.
SUBSTANTIAL INDEBTEDNESS AND RESTRICTIONS
At December 31, 1996, the Company had outstanding $150 million in 11%
Senior Notes (the "Senior Notes") issued pursuant to an indenture governing the
Senior Notes (the "Indenture") and approximately $0.1 million of outstanding
indebtedness under the Credit Facility. In addition, in connection with the
consummation of the Medallion Acquisition, the Company incurred additional
indebtedness of $160.5 million. See "Capitalization." Giving effect to the
Offerings and the application of the net proceeds to repay amounts owed under
the Bank Credit Facilities, the Company expects to have approximately $156
million available for borrowing under the Bank Credit Facilities immediately
after the Offerings.
11
<PAGE> 124
The Company's level of indebtedness will have several important effects on
its future operations. A significant portion of the Company's cash flow from
operations must be dedicated to the payment of interest on its indebtedness and
will not be available for other purposes. The covenants contained in the Bank
Credit Facilities and the Indenture require the Company to meet certain
financial tests. Other restrictions will limit its ability to borrow additional
funds and may affect the Company's flexibility in planning for and reacting to
changes in its business, including possible acquisition activities. The
Company's ability to obtain additional financing in the future for working
capital, capital expenditures, acquisitions, general corporate purposes or other
purposes may also be restricted. There can be no assurance that the Company will
be able to remain in compliance with the financial ratios prescribed under the
Bank Credit Facilities. Failure to do so would result in a default and could
lead to the acceleration of the Company's indebtedness under the Bank Credit
Facilities and the Indenture. Moreover, if the Company's revenues were to
decrease as a result of lower oil and gas prices, decreased production or
otherwise, the borrowing base under the Bank Credit Facilities could be reduced
and could restrict the Company's future growth.
EXPLORATION RISKS
Exploratory drilling activities are subject to many risks, including the
risk that no commercially productive reservoirs will be encountered, and there
can be no assurance that new wells drilled by the Company will be productive or
that the Company will recover all or any portion of its investment. Drilling for
oil and gas may involve unprofitable efforts, not only from non-productive
wells, but from wells that are productive but do not produce sufficient net
revenues to return a profit after drilling, operating and other costs. The cost
of drilling, completing and operating wells is often uncertain. The Company's
drilling operations may be curtailed, delayed or canceled as a result of
numerous factors, many of which are beyond the Company's control, including
title problems, weather conditions, compliance with governmental requirements
and shortages or delays in the delivery of equipment and services.
MARKETING RISKS
The Company's ability to market oil and gas at commercially acceptable
prices is dependent on, among other factors, the availability and capacity of
gathering systems and pipelines, federal and state regulation of production and
transportation, general economic conditions and changes in supply and demand.
The Company's inability to respond appropriately to these changing factors could
have a negative effect on the Company's profitability.
ACQUISITION RISKS
Acquisitions of oil and gas businesses and properties and volumetric
production payments have been an important element of the Company's success, and
the Company will continue to seek acquisitions in the future. Even though the
Company performs a review (including a limited review of title and other
records) of the major properties it seeks to acquire that it believes is
consistent with industry practices, such reviews are inherently incomplete and
it is generally not feasible for the Company to review in-depth every property
and all records. Even an in-depth review may not reveal existing or potential
problems or permit the Company to become familiar enough with the properties to
assess fully their deficiencies and capabilities, and the Company may assume
environmental and other liabilities in connection with acquired businesses and
properties.
OPERATING RISKS
The Company's operations are subject to numerous risks inherent in the oil
and gas industry, including the risks of fire, explosions, blow-outs, pipe
failure, abnormally pressured formations and environmental accidents such as oil
spills, natural gas leaks, ruptures or discharges of toxic gases, the occurrence
of any of which could result in substantial losses to the Company due to injury
or loss of life, severe damage to or destruction of property, natural resources
and equipment, pollution or other environmental damage, clean-up
responsibilities, regulatory investigation and penalties and suspension
12
<PAGE> 125
of operations. The Company's operations may be materially curtailed, delayed or
canceled as a result of numerous factors, including the presence of
unanticipated pressure or irregularities in formations, accidents, title
problems, weather conditions, compliance with governmental requirements and
shortages or delays in the delivery of equipment. In accordance with customary
industry practice, the Company maintains insurance against some, but not all, of
the risks described above. There can be no assurance that the levels of
insurance maintained by the Company will be adequate to cover any losses or
liabilities. The Company cannot predict the continued availability of insurance,
or availability at commercially acceptable premium levels.
COMPETITIVE INDUSTRY
The oil and gas industry is highly competitive. The Company competes for
oil and gas business and property acquisitions and for the exploration,
development, production, transportation and marketing of oil and gas, as well as
for equipment and personnel, with major oil and gas companies, other independent
oil and gas concerns and individual producers and operators. Many of these
competitors have financial and other resources which substantially exceed those
available to the Company.
GOVERNMENT REGULATION
The Company's business is subject to certain federal, state and local laws
and regulations relating to the drilling for and production, transportation and
marketing of oil and gas, as well as environmental and safety matters. Such laws
and regulations have generally become more stringent in recent years, often
imposing greater liability on an increasing number of parties. Because the
requirements imposed by such laws and regulations are frequently changed, the
Company is unable to predict the effect or cost of compliance with such
requirements or their effects on oil and gas use or prices. In addition,
legislative proposals are frequently introduced in Congress and state
legislatures which, if enacted, might significantly affect the oil and gas
industry. In view of the many uncertainties which exist with respect to any
legislative proposals, the effect on the Company of any legislation which might
be enacted cannot be predicted. See "Business and Properties -- Regulation."
CERTAIN ANTI-TAKEOVER PROVISIONS
The Company's Certificate of Incorporation and Bylaws and the Delaware
General Corporation Law contain provisions that may have the effect of
discouraging unsolicited takeover proposals for the Company. These provisions,
among other things, provide for the classification of the Board of Directors,
restrict the ability of stockholders to take action by written consent,
authorize the Board of Directors to designate the terms of and issue new series
of preferred stock, limit the personal liability of directors, require the
Company to indemnify directors and officers to the fullest extent permitted by
applicable law and impose restrictions on business combinations with certain
interested parties.
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This Prospectus includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended (the "Securities Act"),
and Section 21E of the Securities Exchange Act of 1934, as amended (the
"Exchange Act"). All statements other than statements of historical facts
included in this Prospectus, including without limitation, statements under
"Prospectus Summary," "Risk Factors," "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and "Business and Properties,"
regarding planned capital expenditures, increases in oil and gas production, the
number of anticipated wells to be drilled after the date of this Prospectus, the
Company's financial position, business strategy and other plans and objectives
for future operations, are forward-looking statements. Although the Company
believes that the expectations reflected in such forward-looking statements are
reasonable, it can give no assurance that such expectations will prove to have
been correct. There are numerous uncertainties inherent in estimating quantities
of proved oil and gas reserves and in projecting future rates of production and
timing of development expenditures, including many
13
<PAGE> 126
factors beyond the control of the Company. Reserve engineering is a subjective
process of estimating underground accumulations of oil and gas that cannot be
measured in an exact way, and the accuracy of any reserve estimate is a function
of the quality of available data and of engineering and geological
interpretation and judgment. As a result, estimates made by different engineers
often vary from one another. In addition, results of drilling, testing and
production subsequent to the date of an estimate may justify revisions of such
estimate and such revisions, if significant, would change the schedule of any
further production and development drilling. Accordingly, reserve estimates are
generally different from the quantities of oil and gas that are ultimately
recovered. Additional important factors that could cause actual results to
differ materially from the Company's expectations are disclosed under "Risk
Factors" and elsewhere in this Prospectus, including without limitation in
conjunction with the forward-looking statements included in this Prospectus. All
subsequent written and oral forward-looking statements attributable to the
Company or persons acting on its behalf are expressly qualified in their
entirety by such factors.
USE OF PROCEEDS
The net proceeds to the Company from the Offerings are estimated to be
approximately $110.7 million ($127.5 million if the Underwriters' over-allotment
options are exercised in full), after deducting estimated offering expenses
payable by the Company. These net proceeds will be used by the Company to reduce
the outstanding indebtedness under the Bank Credit Facilities, including amounts
under the Revolving Credit Agreement used to fund a portion of the Medallion
Acquisition. Substantially all of the indebtedness incurred under the Bank
Credit Facilities was used to consummate the Medallion Acquisition.
At December 31, 1996, the outstanding balance under the Credit Facility was
$0.1 million. To consummate the Medallion Acquisition, the Company borrowed
$55.5 million under the Credit Facility and $105 million under the Revolving
Credit Agreement and paid the balance of the adjusted cash purchase price from
available cash. After receipt of the net proceeds from the Offerings, it is the
Company's intention to reduce the outstanding indebtedness under the Credit
Facility and the Revolving Credit Agreement by approximately $110.7 million,
leaving an outstanding balance under the Bank Credit Facilities of approximately
$54 million.
At January 29, 1997, the Credit Facility had a borrowing base of $75
million and bore interest at a rate of 7.2% per annum. At January 29, 1997, the
Revolving Credit Agreement had a borrowing base of $135 million and bore
interest at a rate of 9.5% per annum. It is secured by substantially all the
assets of Medallion and a pledge of Medallion's common stock. The interest rates
payable under the Bank Credit Facilities fluctuate based on certain published
interest rates. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Liquidity and Capital Resources -- Debt Financing."
14
<PAGE> 127
CAPITALIZATION
The following table sets forth as of September 30, 1996 (i) the actual
capitalization of the Company, (ii) the pro forma capitalization of the Company
after giving effect to the debt incurred pursuant to the Medallion Acquisition
under the Bank Credit Facilities, including the Revolving Credit Agreement, and
to the warrants to purchase 435,000 shares of Common Stock issued in connection
with the Medallion Acquisition and (iii) the pro forma as adjusted
capitalization of the Company after giving effect to the Offerings, the receipt
of the net proceeds therefrom and the application of such net proceeds as set
forth under "Use of Proceeds." The table should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations," "Pro Forma Financial Information" and the Company's Consolidated
Financial Statements (including the notes thereto) included elsewhere in this
Prospectus.
<TABLE>
<CAPTION>
SEPTEMBER 30, 1996
------------------------------------
PRO FORMA
ACTUAL PRO FORMA AS ADJUSTED
-------- --------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Long-term debt:
Bank Credit Facilities................................ $ 100 $156,613 $ 45,896
11% Senior Notes due 2003............................. 149,434 149,434 149,434
Other................................................. 296 296 296
-------- -------- --------
Total long-term debt.......................... 149,830 306,343 195,626
Stockholders' equity:
Preferred stock: 5,000,000 shares authorized; none
issued............................................. -- -- --
Common stock, par value $0.01 per share: 50,000,000
shares authorized; 12,488,120 issued; 15,488,120 as
adjusted........................................... 125 125 155
Stock warrants issued................................. 626 5,624 5,624
Additional paid-in capital............................ 25,371 25,371 136,058
Retained earnings..................................... 93,578 93,578 93,578
Less treasury stock, 900,748 shares at cost........... (3,388) (3,388) (3,388)
-------- -------- --------
Total stockholders' equity.................... 116,312 121,310 232,027
-------- -------- --------
Total capitalization.......................... $266,142 $427,653 $427,653
======== ======== ========
</TABLE>
15
<PAGE> 128
PRICE RANGE OF COMMON STOCK
The Common Stock is traded on the New York Stock Exchange under the symbol
"KCS." The high and low closing sales prices for the periods listed below were
taken from the New York Stock Exchange Composite Transactions Tape. The last
reported sales price of the Common Stock on January 29, 1997 was $39.625.
<TABLE>
<CAPTION>
HIGH LOW
------ ------
<S> <C> <C>
1994
First Quarter............................................... $29.00 $21.75
Second Quarter.............................................. 26.38 19.63
Third Quarter............................................... 21.88 16.13
Fourth Quarter.............................................. 18.75 12.25
1995
First Quarter............................................... 17.25 14.63
Second Quarter.............................................. 22.25 15.25
Third Quarter............................................... 21.88 13.75
Fourth Quarter.............................................. 16.75 9.88
1996
First Quarter............................................... 15.75 13.38
Second Quarter.............................................. 28.75 15.63
Third Quarter............................................... 35.63 26.75
Fourth Quarter.............................................. 44.13 28.88
1997
First Quarter (through January 29, 1997).................... 42.00 34.88
</TABLE>
There were 1,184 stockholders of record of the Common Stock on December 31,
1996.
DIVIDEND POLICY
The Company commenced paying cash dividends on its Common Stock in February
1992. For the years ended December 1993, 1994 and 1995, the Company's annual
dividends paid were $0.06, $0.09 and $0.12 per share, respectively. On November
21, 1996, the Company declared its most recent quarterly dividend of $0.03 per
share for record holders of its Common Stock as of January 10, 1997, payable on
February 20, 1997. The Company's policy is to retain a substantial portion of
its earnings to provide funds for reinvestment within the Company's business.
The Company is a holding company that conducts all of its operations through its
subsidiaries. As a result, the Company's ability to pay dividends is dependent
upon the cash flow of its subsidiaries. The payment of dividends is also
contingent upon, among other factors, business conditions, business results,
operating cash requirements and the financial condition of the Company, and will
be at the discretion of the Board of Directors. In addition, under the terms of
the Indenture and the Bank Credit Facilities, the payment of dividends is
limited to 50% of the Company's consolidated net income commencing October 1,
1995. See Note 4 to the Consolidated Financial Statements.
16
<PAGE> 129
PRO FORMA FINANCIAL INFORMATION
The following unaudited pro forma financial information is derived from the
historical financial statements of KCS Energy, Inc., the InterCoast Entities
(Medallion) and the Sawyer Canyon Properties included elsewhere in this
Prospectus.
The unaudited Pro Forma Statement of Consolidated Income for the year ended
December 31, 1995 reflects (i) the Company's Rocky Mountain Acquisition and
Michigan Acquisition, (ii) the sale of the Senior Notes, (iii) the Medallion
Acquisition (which includes Medallion's acquisition of the Sawyer Canyon
Properties in April 1996) and (iv) the Offerings and the application of the
estimated net proceeds therefrom as if each transaction had occurred on January
1, 1995.
The unaudited Pro Forma Statement of Consolidated Income for the nine
months ended September 30, 1996 reflects the Medallion Acquisition (which
includes Medallion's acquisition of the Sawyer Canyon Properties in April 1996),
the Offerings and the application of the estimated net proceeds therefrom as if
each transaction had occurred on January 1, 1995.
The unaudited Pro Forma Consolidated Balance Sheet as of September 30, 1996
reflects the Medallion Acquisition, the Offerings and the application of the
estimated net proceeds therefrom as if each transaction had occurred on
September 30, 1996.
The unaudited pro forma financial data should be read in conjunction with
the notes thereto and the Consolidated Financial Statements of the Company
(including the notes thereto) included elsewhere in this Prospectus. The
unaudited pro forma financial data does not purport to be indicative of the
financial position or results of operations that would actually have occurred if
the transactions described had occurred as presented in such statements or that
may be obtained in the future. In addition, future results may vary
significantly from the results reflected in such statements due to normal crude
oil and gas production declines, changes in prices received for crude oil and
gas, future acquisitions and dispositions of reserves, changes in estimates of
reserves and of the future net revenues therefrom and other factors.
17
<PAGE> 130
KCS ENERGY, INC.
PRO FORMA STATEMENT OF CONSOLIDATED INCOME
FOR THE YEAR ENDED DECEMBER 31, 1995
(UNAUDITED, DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
KCS
ACQUISITIONS
AND NOTE KCS MEDALLION ACQUISITION
KCS OFFERING PRO FORMA MEDALLION MEDALLION PRO FORMA AND OTHER
HISTORICAL ADJUSTMENTS COMBINED HISTORICAL ACQUISITIONS COMBINED ADJUSTMENTS
---------- ------------ --------- ---------- ------------- --------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Revenue........................ $ 449,965 $ 15,035(a) $ 465,000 $ 73,460 $ 72,881(a) $ 146,341 $ --
Operating costs and expenses:
Cost of natural gas sales..... 356,186 -- 356,186 24,361 57,216(a) 81,577 --
Other operating and
administrative expenses..... 18,669 4,769(a) 23,438 17,210 4,024(a) 21,234 --
Depreciation, depletion and
amortization................ 39,209 5,207(b) 44,416 21,705 -- 21,705 611(b)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating costs and expenses.. 414,064 9,976 424,040 63,276 61,240 124,516 611
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating income............ 35,901 5,059 40,960 10,184 11,641 21,825 (611)
Interest and other income,
net........................... 3,713 -- 3,713 -- -- -- --
Interest expense............... (7,732) (11,108)(c) (18,840) -- -- -- (6,827)(d)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Income before income taxes
(benefit)..................... 31,882 (6,049) 25,833 10,184 11,641 21,825 (7,438)
Federal and state income taxes
(benefit)..................... 10,576 (2,117)(e) 8,459 3,638 4,074(e) 7,712 (2,603)(e)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Net income (loss)......... $ 21,306 $ (3,932) $ 17,374 $ 6,546 $ 7,567 $ 14,113 $ (4,835)
========== ========== ========== ========== ========== ========== ==========
Earnings per share............. $ 1.81
==========
Average shares outstanding..... 11,760,701 3,000,000
========== ==========
<CAPTION>
PRO FORMA
AS ADJUSTED
-----------
<S> <C>
Revenue........................ $ 611,341
Operating costs and expenses:
Cost of natural gas sales..... 437,763
Other operating and
administrative expenses..... 44,672
Depreciation, depletion and
amortization................ 66,732
----------
Operating costs and expenses.. 549,167
----------
Operating income............ 62,174
Interest and other income,
net........................... 3,713
Interest expense............... (25,667)
----------
Income before income taxes
(benefit)..................... 40,220
Federal and state income taxes
(benefit)..................... 13,568
----------
Net income (loss)......... $ 26,652
==========
Earnings per share............. $ 1.81
==========
Average shares outstanding..... 14,760,701
==========
</TABLE>
See accompanying Notes to Unaudited Pro Forma Consolidated Financial Statements.
18
<PAGE> 131
KCS ENERGY, INC.
PRO FORMA STATEMENT OF CONSOLIDATED INCOME
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1996
(UNAUDITED, DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
MEDALLION ACQUISITION
KCS MEDALLION SAWYER CANYON PRO FORMA AND OTHER PRO FORMA
HISTORICAL HISTORICAL PROPERTIES(F) COMBINED ADJUSTMENTS AS ADJUSTED
----------- ----------- ---------------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Revenue........................ $ 316,604 $ 160,508 $ 3,740 $ 164,248 $ -- $ 480,852
Operating costs and expenses:
Cost of natural gas sales.... 231,063 106,546 -- 106,546 -- 337,609
Other operating and
administrative expenses.... 19,427 15,883 645 16,528 -- 35,955
Depreciation, depletion and
amortization............... 33,933 20,360 -- 20,360 84(g) 54,377
----------- ----------- ----------- ----------- ----------- -----------
Operating costs and
expenses................... 284,423 142,789 645 143,434 84 427,941
----------- ----------- ----------- ----------- ----------- -----------
Operating income........... 32,181 17,719 3,095 20,814 (84) 52,911
Interest and other income,
net.......................... 4,850 -- -- -- -- 4,850
Interest expense............... (13,858) (992) -- (992) (3,223)(h) (18,073)
----------- ----------- ----------- ----------- ----------- -----------
Income before income taxes
(benefit).................... 23,173 16,727 3,095 19,822 (3,307) 39,688
Federal and state income taxes
(benefit).................... 8,367 5,973 1,083(i) 7,056 (1,157)(i) 14,266
----------- ----------- ----------- ----------- ----------- -----------
Net income (loss)..... $ 14,806 $ 10,754 $ 2,012 $ 12,766 $ (2,150) $ 25,422
=========== =========== =========== =========== =========== ===========
Earnings per share............. $ 1.25 $ 1.71
=========== ===========
Average shares outstanding..... 11,886,434 3,000,000 14,886,434
=========== =========== ===========
</TABLE>
See accompanying Notes to Unaudited Pro Forma Consolidated Financial Statements.
19
<PAGE> 132
KCS ENERGY, INC.
PRO FORMA CONSOLIDATED BALANCE SHEET
AS OF SEPTEMBER 30, 1996
(UNAUDITED, DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
ACQUISITION PRO
KCS MEDALLION AND OTHER FORMA OFFERING PRO FORMA
HISTORICAL HISTORICAL ADJUSTMENTS COMBINED ADJUSTMENTS AS ADJUSTED
---------- ---------- ----------- --------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents........... $ 53,597 $ 3,542 $ (50,030)(m) $ 7,109 $ -- $ 7,109
Trade accounts receivable, net...... 39,146 29,740 -- 68,886 -- 68,886
Fuel inventories.................... 884 -- -- 884 -- 884
Other current assets................ 5,055 2,332 -- 7,387 -- 7,387
-------- -------- ---------- -------- ---------- --------
Current assets.................... 98,682 35,614 (50,030) 84,266 -- 84,266
Property, plant and equipment, net:
Oil and gas properties, net......... 206,308 199,427 (5,152)(j) 400,583 -- 400,583
Natural gas transportation systems,
net............................... 22,296 2,950 2,050(j) 27,296 -- 27,296
Other property, plant and
equipment......................... 2,979 1,174 (674)(j) 3,479 -- 3,479
-------- -------- ---------- -------- ---------- --------
Property, plant and equipment,
net............................. 231,583 203,551 (3,776) 431,358 -- 431,358
-------- -------- ---------- -------- ---------- --------
Investments and other assets.......... 10,887 5,066 (3,266)(j) 12,687 -- 12,687
-------- -------- ---------- -------- ---------- --------
$341,152 $244,231 $ (57,072) $528,311 $ -- $528,311
======== ======== ========== ======== ========== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable.................... $ 34,680 $ 21,461 $ -- $ 56,141 $ -- $ 56,141
Accrued liabilities................. 7,032 4,187 -- 11,219 -- 11,219
-------- -------- ---------- -------- ---------- --------
Current liabilities............... 41,712 25,648 -- 67,360 -- 67,360
Deferred credits and other
liabilities......................... 33,298 31,866 (31,866)(j) 33,298 -- 33,298
Long-term debt........................ 149,830 52,402 104,111(k)(m) 306,343 (110,717)(n) 195,626
Stockholders' equity:
Preferred stock..................... -- -- -- -- -- --
Common stock........................ 125 3 (3)(j) 125 30(n) 155
Additional paid-in capital.......... 25,997 100,769 (95,771)(l) 30,995 110,687(n) 141,682
Retained earnings................... 93,578 33,543 (33,543)(j) 93,578 -- 93,578
Less treasury stock................. (3,388) -- -- (3,388) -- (3,388)
-------- -------- ---------- -------- ---------- --------
Total stockholders' equity.... 116,312 134,315 (129,317) 121,310 110,717 232,027
-------- -------- ---------- -------- ---------- --------
$341,152 $244,231 $ (57,072) $528,311 $ -- $528,311
======== ======== ========== ======== ========== ========
</TABLE>
See accompanying Notes to Unaudited Pro Forma Consolidated Financial Statements.
20
<PAGE> 133
KCS ENERGY, INC.
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
(DOLLARS IN THOUSANDS)
The accompanying pro forma financial statements have been prepared to
reflect certain adjustments to the historical consolidated financial statements
of the Company.
Unaudited Pro Forma Statement of Consolidated Income for the Year Ended December
31, 1995:
(a) Adjustments to reflect revenues, cost of sales and other operating
expenses from January 1, 1995, until the dates of the Rocky Mountain
Acquisition and the Michigan Acquisition by the Company, the Sawyer Canyon
and other acquisitions of Medallion, and the Medallion Acquisition by the
Company.
(b) Adjustments to reflect depreciation, depletion and amortization
expense calculated using the future gross revenue method applied to the
adjusted basis of the acquired properties and entities using the purchase
method of accounting.
(c) Adjustment to reflect additional interest expense calculated,
assuming the Company's As Adjusted debt balance at December 31, 1995
($170,529), was outstanding for the entire year, including amortization of
deferred financing cost.
(d) Adjustment to reflect incremental interest expense under the Bank
Credit Facilities ($15,488) to fund the $206,543 cash payment for the
Medallion Acquisition, and to reflect the interest expense savings ($8,661)
resulting from the application of the estimated net proceeds of $110,717
from the Offerings ($117,000 in gross proceeds net of $6,283 in estimated
underwriting discount and expenses and an offering price of $39.00 per
share).
(e) Adjustments to the provision for income taxes related to the above
adjustments.
Unaudited Pro Forma Statement of Consolidated Income for the Nine Months ended
September 30, 1996:
(f) Reflects results of operations for the Sawyer Canyon Properties
for the three months ended March 31, 1996, prior to their acquisition by
Medallion on April 1, 1996.
(g) Adjustment to reflect depreciation, depletion and amortization
expense calculated using the future gross revenue method applied to the
adjusted basis of the Medallion Acquisition using the purchase method of
accounting.
(h) Adjustment to reflect interest expense savings ($1,915) based on
the assumption that the September 30, 1996 debt balance had been
outstanding for the entire nine-month period, to reflect incremental
interest expense under the Bank Credit Facilities ($11,616) to fund the
$206,543 cash payment for the Medallion Acquisition, and to reflect the
interest expense savings ($6,478) as a result of the application of the
estimated net proceeds of $110,717 from the Offerings.
(i) Adjustment to the provision for income taxes related to the above
adjustments.
Unaudited Pro Forma Consolidated Balance Sheet as of September 30, 1996:
(j) Adjustment to (i) eliminate the historical basis of certain assets
and liabilities of Medallion and (ii) reflect the adjusted basis of these
items using the purchase method of accounting. (See detail of the purchase
price and related allocation to assets and liabilities in the table below.)
(k) Adjustment to reflect the elimination of the historical debt of
Medallion of $52,402 and additional debt under the Bank Credit Facilities
of $206,543 used to fund a portion of the Medallion Acquisition.
21
<PAGE> 134
KCS ENERGY, INC.
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(DOLLARS IN THOUSANDS)
(l) Adjustment to reflect the elimination of the historical paid-in
capital of Medallion and the issuance of warrants to purchase 435,000
shares of Common Stock granted in connection with the Medallion Acquisition
presented at estimated fair value ($4,998).
(m) Reflects the application of $50,030 from cash to reduce long-term
debt.
(n) Adjustment to reflect the application of the estimated net
proceeds of $110,717 from the Offerings to reduce long-term debt.
The following table summarizes elements of the Medallion Acquisition, which was
accounted for by the Company as a purchase transaction:
<TABLE>
<S> <C>
Consideration:
Cash Purchase Price....................................... $ 209,396
Adjustment to reflect free cash flow from Medallion's
operations subsequent to the effective date of July 1,
1996 and through September 30, 1996.................... (2,853)
Cash paid to seller....................................... 206,543
Common stock warrants issued to seller.................... 4,998
Liabilities Assumed:
Current liabilities....................................... 25,648
Assets Acquired:
Current assets............................................ (35,614)
Other assets.............................................. (1,800)
---------------
$ 199,775
===============
</TABLE>
22
<PAGE> 135
KCS ENERGY, INC.
SELECTED HISTORICAL FINANCIAL INFORMATION
The historical financial data presented below is derived from the Company's
financial statements. The information in this table should be read in
conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and the Consolidated Financial Statements (including
the notes thereto) included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------------------------------------------- -----------------------
1991 1992 1993 1994 1995 1995 1996
---------- ---------- ---------- ---------- ---------- ---------- ----------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA) (UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenue:
Oil and gas exploration and
production....................... $ 9,302 $ 13,496 $ 40,455 $ 66,215 $ 86,629 $ 63,425 $ 79,051
Natural gas transportation and
marketing........................ 108,549 141,562 264,710 279,155 365,354 270,557 238,254
Intercompany....................... (624) (779) (876) (3,657) (2,018) (1,708) (701)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total........................ 117,227 154,279 304,289 341,713 449,965 332,274 316,604
Operating costs and expenses:
Cost of natural gas sales.......... 100,072 133,590 253,435 265,076 356,186 264,097 231,063
Other operating and administrative
expenses......................... 10,017 10,806 15,018 18,285 18,669 12,950 19,427
Depreciation, depletion and
amortization..................... 3,227 3,800 8,036 19,740 39,209 29,299 33,933
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total........................ 113,316 148,196 276,489 303,101 414,064 306,346 284,423
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating income.................... 3,911 6,083 27,800 38,612 35,901 25,928 32,181
Interest and other income, net...... 787 757 704 1,039 3,713 2,311 4,850
Interest expense.................... (1,239) (1,297) (1,983) (2,938) (7,732) (4,912) (13,858)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Income before income taxes.......... 3,459 5,543 26,521 36,713 31,882 23,327 23,173
Federal and state income taxes...... 885 1,533 7,910 12,556 10,576 7,645 8,367
---------- ---------- ---------- ---------- ---------- ---------- ----------
Net income.......................... $ 2,574 $ 4,010 $ 18,611 $ 24,157 $ 21,306 $ 15,682 $ 14,806
========== ========== ========== ========== ========== ========== ==========
Earnings per share.................. $ 0.24 $ 0.36 $ 1.60 $ 2.05 $ 1.81 $ 1.33 $ 1.25
Average common shares outstanding... 10,750,490 11,138,157 11,658,370 11,804,989 11,760,701 11,766,011 11,886,434
Dividends per common share.......... $ 0.01 $ 0.03 $ 0.06 $ 0.09 $ 0.12 $ 0.09 $ 0.09
OTHER DATA:
EBITDA.............................. $ 7,138 $ 9,883 $ 35,836 $ 58,352 $ 75,110 $ 55,227 $ 66,114
Capital expenditures................ 7,809 13,867 48,455 74,953 128,699 57,455 52,735
BALANCE SHEET DATA (AT END OF
PERIOD):
Cash and cash equivalents........... $ 1,914 $ 4,292 $ 5,369 $ 988 $ 5,846 $ 4,187 $ 53,597
Working capital..................... 4,002 5,966 10,368 16,215(1) 60,090(1) 43,437(1) 56,970
Oil and gas properties, net......... 19,028 30,828 70,477 125,621 204,958 146,130 206,308
Total assets........................ 72,077 88,220 165,990 214,423 360,609 271,982 341,152
Long-term debt...................... 15,707 21,637 36,289 61,970 165,529 90,800 149,830
Total stockholders' equity.......... 26,317 30,233 59,765 80,668 101,576 95,626 116,312
</TABLE>
- ---------------
(1) Includes the Tennessee Gas Receivable at such dates.
23
<PAGE> 136
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following is a discussion and analysis of the Company's financial
condition and results of operations and should be read in conjunction with the
Company's Consolidated Financial Statements (including the notes thereto)
included elsewhere in this Prospectus.
GENERAL
In the past year, several important developments have had and will continue
to have a significant impact on the Company's financial condition and results of
operations. On December 23, 1996, the Company and Tennessee Gas entered into a
settlement covering all claims and litigation between them related to the
Tennessee Gas Contract. As part of the settlement, the Tennessee Gas Contract
was terminated effective January 1, 1997, approximately two years prior to its
expiration date. The parties also agreed to the dismissal of the contract
dispute that resulted in a November 1996 jury award to Tennessee Gas of $143.2
million (including $114 million in punitive damages). See "Business and
Properties -- Legal Proceedings -- Tennessee Gas Litigation." The early
termination of the Tennessee Gas Contract with its above-market pricing
provisions resulted in downward revisions in the amounts of $59.5 million for
estimated future net revenues before income taxes (based upon a natural gas
price of $2.10 per Mcf, the assumed realized spot market price on June 30, 1996)
and $51.4 million for PV-10, as compared to prior reserve reports prepared as of
June 30, 1996. Except for the revisions to future net revenues, the Company's
financial statements will not be directly affected as a result of the settlement
and early termination of the contract.
The December 1996 settlement did not affect the Company's successful
conclusion of litigation earlier in the year relating to the validity and
pricing provisions of the Tennessee Gas Contract and its recovery of past
underpayments (including interest and net of severance taxes and other payables
related to the contract) that had accrued under the contract. On September 30,
1996, Tennessee Gas paid the Company approximately $70 million, representing the
amount of the Tennessee Gas Receivable at that date.
As of December 31, 1996, the Company completed the arrangements for the
acquisition of all of the outstanding stock of Medallion for a total purchase
price of approximately $214.4 million, consisting of $209.4 million in cash
(reduced at the January 2, 1997 closing by $15.3 million principally to reflect
free cash flow from Medallion's operations subsequent to the July 1, 1996
effective date) and warrants to purchase 435,000 shares of Common Stock. The
Company has also made two other significant recent acquisitions. In November
1995, the Company acquired substantially all of the oil and gas assets of
Natural Gas Processing Company for a purchase price of approximately $33 million
and in December 1995, the Company acquired 24.6 Bcfe of proved reserves in the
northern and southern Niagaran Reef trend in Michigan for $31 million.
These developments have transformed the Company from an enterprise
dependent upon the Bob West Field and the Tennessee Gas Contract to a more
diversified enterprise focusing on the acquisition and development of oil and
gas assets located in three core operating areas -- the Gulf Coast region, the
Rocky Mountain region and the Mid-Continent region -- and on its VPP program.
NINE MONTHS ENDED SEPTEMBER 30, 1996 AND 1995
Results of Operations -- Consolidated
For the nine months ended September 30, 1996, net income was $14.8 million
($1.25 per share), compared to $15.7 million ($1.33 per share) for the same
period in 1995. Significantly higher oil and gas production, along with higher
oil and gas prices in the current year for non-Tennessee Gas Contract sales were
offset by lower production from properties covered by the Tennessee Gas
Contract, higher interest costs and a higher effective income tax rate.
24
<PAGE> 137
Results of Operations -- Business Segments
Segment information reflects volumes, revenues and expenses associated with
transactions involving affiliates which are eliminated in consolidation.
Oil and Gas Exploration and Production
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
--------------------------------
1995 1996
----------- -----------
(UNAUDITED, DOLLARS IN THOUSANDS
EXCEPT PER UNIT DATA)
<S> <C> <C>
Revenue........................................ $63,425 $79,051
Production (lifting) costs..................... 4,353 8,253
Depreciation, depletion and amortization....... 28,447 32,865
Other operating expenses....................... 1,816 2,877
------- -------
Operating income.......................... $28,809 $35,056
======= =======
Oil production (Mbbl).......................... 111 547
Natural gas production (MMcf):
Tennessee Gas Contract....................... 5,446 3,576
Other........................................ 7,858 15,346
------- -------
Total natural gas production.............. 13,304 18,922
======= =======
Average sales price:
Oil (per bbl)................................ $ 17.53 $ 19.72
Natural gas (per Mcf)........................ 4.60 3.61
Average equivalent sales price (per Mcfe).... 4.54 3.56
Average lifting cost (per Mcfe)................ 0.31 0.37
DD&A as a percent of revenue................... 44.9% 41.6%
</TABLE>
Oil and gas production increased 59% to 22,204 MMcfe for the nine months
ended September 30, 1996, compared to the corresponding period in 1995. The
increase in production during 1996 resulted from newly added properties and
reflected the Company's overall growth strategy to increase its percentage of
non-Tennessee Gas Contract production. Non-Tennessee Gas Contract production
accounted for 84% of total production during the 1996 period, up from 61% during
the 1995 period. Approximately 5,851 MMcfe of the increase in non-Tennessee Gas
Contract production was attributable to the Company's VPP program, with the
remainder attributable to increased exploitation and development drilling. For
the nine months ended September 30, 1996, sales to Tennessee Gas decreased to
3,576 MMcf, compared to 5,446 MMcf during 1995, when Tennessee Gas took
additional deliveries to offset earlier curtailments.
Average natural gas prices were $3.61 per Mcf for the nine months ended
September 30, 1996, compared to $4.60 per Mcf for the same period in 1995. This
decrease reflects the lower Tennessee Gas Contract production which offset the
significant increase in non-Tennessee Gas Contract production and higher average
spot market prices. Average non-Tennessee Gas Contract gas prices were $2.29
during the 1996 period, compared to $1.56 during the same period in 1995.
Natural gas sale prices under the Tennessee Gas contract, excluding severance
tax reimbursements, were $8.38 during the nine-month period ended September 30,
1996, compared to $7.84 during the same period in 1995.
The increases in costs and expenses were mainly attributable to the
increase in production volume.
25
<PAGE> 138
Natural Gas Transportation and Marketing
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
--------------------------------
1995 1996
------------ ------------
(UNAUDITED, DOLLARS IN THOUSANDS
EXCEPT PER UNIT DATA)
<S> <C> <C>
Revenue.......................................... $270,557 $238,254
Cost of natural gas sales........................ 265,213 231,343
-------- --------
Gross margin................................ 5,344 6,911
Depreciation..................................... 803 1,007
Other operating expenses......................... 5,825 6,183
-------- --------
Operating loss.............................. $ (1,284) $ (279)
======== ========
Transportation volume (Bcf)...................... 19.4 20.1
Transportation gross margin (per Mcf)............ $ 0.159 $ 0.186
Marketing volume (Bcf)........................... 167.1 87.2
Marketing gross margin (per Mcf)................. $ 0.014 $ 0.036
Marketing operating expense (per Mcf)............ 0.027 0.050
</TABLE>
The marketing operations had an operating loss of $1.3 million for the nine
months ended September 30, 1996, compared to a loss of $2.3 million for the same
period in 1995. The significant decline in marketed volumes and revenue during
the 1996 period reflect a strategic shift away from higher volume low margin
"gas trading" activities and toward an emphasis on the core retail customer
base. Coupled with higher natural gas prices in 1996, this resulted in the
increases in gross margin per Mcf of marketing volumes.
The natural gas transportation operations had operating income of $1.0
million in each of the nine-month periods ended September 30, 1996 and 1995. The
increases in transportation volumes and gross margin per Mcf were offset by
higher operating and maintenance expenses.
Interest and Other Income, Net
Interest income accrued on the Tennessee Gas Receivable was $4.7 million
for the nine months ended September 30, 1996, compared to $1.9 million during
the same period in 1995. See "-- Liquidity and Capital Resources."
Interest Expense
For the nine months ended September 30, 1996, interest expense was $13.9
million, compared to $4.9 million for the same period in 1995. The increase in
1996 was due to higher average borrowings, along with higher average interest
rates principally resulting from the sale of $150 million of the 11% Senior
Notes in January 1996. The Company did not collect the contract price from
Tennessee Gas throughout 1995 and therefore increased its borrowings to expand
its oil and gas exploration and production operations. These borrowings included
approximately $64 million for the Rocky Mountain and Michigan Acquisitions,
completed during the fourth quarter of 1995.
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
Results of Operations -- Consolidated
Net income was $21.3 million ($1.81 per share) in 1995, compared to $24.2
million ($2.05 per share) in 1994 and $18.6 million ($1.60 per share) in 1993.
Lower natural gas prices in 1995 affected each of the Company's operating
businesses, and combined with higher net interest costs incurred to fund the
growth of the Company's oil and gas exploration and production operations to
reduce 1995 earnings compared to 1994. Milder than normal winter weather
conditions and an oversupply of natural
26
<PAGE> 139
gas during the winter of 1994-1995 resulted in a 10% decline in average natural
gas prices for the Company's non-Tennessee Gas Contract production in 1995,
which reduced somewhat the benefits of significantly increased natural gas
production. The mild weather and lower natural gas prices particularly affected
the Company's natural gas marketing operations, which posted a significant
decline in operating income during 1995.
The increase in earnings in 1994 compared to 1993 was due mainly to
increased natural gas production, principally from the Company's acreage in the
Bob West Field dedicated under the Tennessee Gas Contract. See Note 7 to the
Consolidated Financial Statements for information regarding the Tennessee Gas
Contract.
Results of Operations -- Business Segments
Segment information reflects all volumes, revenue and expenses, including
those associated with transactions involving affiliates which are eliminated in
consolidation. Each of the Company's business segments was adversely affected by
low natural gas prices during most of 1995.
Oil and Gas Exploration and Production
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
1993 1994 1995
------- ------- -------
(DOLLARS IN THOUSANDS
EXCEPT PER UNIT DATA)
<S> <C> <C> <C>
Revenue.................................... $40,455 $66,215 $86,629
Production (lifting) costs................. 5,011 7,063 6,623
Depreciation, depletion and amortization... 7,004 18,538 37,988
Other operating expenses................... 1,785 2,671 2,373
------- ------- -------
Operating income...................... $26,655 $37,943 $39,645
======= ======= =======
Oil production (Mbbl)...................... 179 211 196
Natural gas production (MMcf):
Tennessee Gas Contract................... 4,472 6,851 6,924
Other.................................... 2,505 4,453 12,205
------- ------- -------
Total natural gas production.......... 6,977 11,304 19,129
======= ======= =======
Average sales price:
Oil (per bbl)............................ $ 17.57 $ 15.16 $ 17.28
Natural gas (per Mcf).................... 5.27 5.54 4.29
Average equivalent sales price (per
Mcfe)................................. 5.02 5.27 4.27
Average lifting cost (per Mcfe)............ 0.62 0.56 0.33
DD&A as a percent of revenue............... 17.3% 28.0% 43.9%
</TABLE>
The 69% increase in natural gas production in 1995 compared to 1994 was due
mainly to newly added properties not covered by the Tennessee Gas Contract.
Approximately 7.4 Bcf of the increase in non-Tennessee Gas Contract natural gas
production was attributable to the Company's VPP program, with the remainder
attributable to increased exploration and development drilling. Non-Tennessee
Gas Contract oil and gas production accounted for 66% of total production in
1995, compared to 45% in 1994 and 44% in 1993. The increase in non-Tennessee Gas
Contract production as a percentage of total production, while an integral part
of the Company's overall growth strategy during this period, made the Company
more sensitive to fluctuations in the market price of oil and gas. Accordingly,
while total production and revenue were up significantly in 1995, a 10% decline
in average non-Tennessee Gas Contract natural gas prices had a negative impact
on the overall profitability of this segment. Average non-Tennessee Gas Contract
natural gas prices were approximately $1.62 in 1995, compared to $1.81 in 1994
and $2.02 in 1993.
27
<PAGE> 140
Tennessee Gas Contract production increased slightly in 1995 compared to
1994 largely as a result of the continued development of the Bob West Field,
which was able to more than offset the normal production decline from existing
wells. With planned development of known producing horizons nearly completed,
the Company anticipates that, absent any new discoveries, it will not be able to
completely offset normal production declines and therefore 1996 production from
this field will be less than in 1995 and will continue to decline thereafter.
Average sales prices under the Tennessee Gas Contract, excluding severance tax
reimbursements, were $7.90 in 1995, $7.49 in 1994 and $7.09 in 1993. The
Tennessee Gas Contract was terminated effective January 1, 1997, and sales
prices beyond that date will be made at lower spot market prices. See Note 7 to
the Consolidated Financial Statements for information regarding the Tennessee
Gas Contract.
The increase in DD&A in 1995 reflected the increase in production, as well
as an increase in the DD&A rate. The DD&A rate reflects, among other things, the
higher average oil and gas property investment in 1995, lower natural gas prices
and an increase in the percentage of total proved reserves not covered by the
Tennessee Gas Contract. In addition, the increase in the Company's reserves
attributable to the VPP program (which bear no lease operating expenses) as a
percentage of total reserves, contributed to the increase in the DD&A rate. The
effect of the higher DD&A rate was partially offset by a 41% reduction in
average lifting costs to $0.33 per Mcfe.
The significant growth of revenue and operating income in 1994 compared to
1993 was largely attributable to increased natural gas production, principally
as a result of the development of the Bob West Field and as a result of
acquisitions and further development of other producing properties.
The increase in total costs and expenses in 1994 compared to 1993 reflected
the significant expansion of oil and gas operations. Production costs and DD&A
increased mainly due to higher natural gas production.
Natural Gas Transportation and Marketing
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1993 1994 1995
-------- -------- --------
(DOLLARS IN THOUSANDS
EXCEPT PER UNIT DATA)
<S> <C> <C> <C>
Revenue............................... $264,710 $279,155 $365,354
Cost of natural gas sales............. 254,029 267,959 357,523
-------- -------- --------
Gross margin..................... 10,681 11,196 7,831
Depreciation.......................... 998 1,178 1,157
Other operating expenses.............. 6,105 7,129 8,023
-------- -------- --------
Operating income (loss).......... $ 3,578 $ 2,889 $ (1,349)
======== ======== ========
Transportation volume (Bcf)........... 24.3 20.9 25.9
Transportation gross margin (per
Mcf)................................ $ 0.135 $ 0.176 $ 0.172
Marketing volume (Bcf)................ 122.9 153.1 226.3
Marketing gross margin (per Mcf)...... $ 0.060 $ 0.049 $ 0.015
Marketing operating expense (per
Mcf)................................ 0.040 0.036 0.027
</TABLE>
The combination of (i) lower natural gas prices, (ii) increased competitive
pressures within the industry and (iii) the absence of severe weather conditions
during the 1994-1995 winter heating season were the primary reasons for the
decrease in operating income in 1995 compared to 1994, offsetting the increase
in marketing and transportation volumes. Average natural gas sales prices for
this segment were approximately 15% lower in 1995 compared to 1994 and average
marketing gross margins per Mcf were approximately 69% lower.
The increase in other operating expenses in 1995 compared to 1994 was
primarily due to costs associated with the expanded activities of the marketing
operations, the expansion of the gathering
28
<PAGE> 141
system associated with the Company's Texas intrastate pipeline and the timing of
routine pipeline repairs and maintenance.
The increase in revenue in 1994 compared to 1993 was due in part to the
unusually cold 1993-1994 winter in the northeastern part of the United States.
During this period of high demand for natural gas, the Company successfully
obtained supply and transportation at competitive prices and sold a significant
portion of its natural gas in the northeastern markets at "peaking" rates. The
decrease in marketing gross margin per Mcf in 1994 reflected the sales to
higher-volume, lower-margin customers, while the increase in transportation
gross margin per Mcf in 1994 was due mainly to an increase in higher-margin
volumes from the Company's gathering systems, along with higher margins on sales
and transportation to certain high-priority, weather-sensitive customers during
the 1993-1994 peak winter heating season.
The increase in operating expenses in 1994 compared to 1993 reflected
higher personnel and marketing costs to support the significant growth in
operations.
Interest and Other Income, Net
Interest and other income was $3.7 million in 1995, compared to $1.0
million in 1994 and $0.7 million in 1993. Of the 1995 amount, $3.1 million was
interest income recorded on the Tennessee Gas Receivable. See "-- Liquidity and
Capital Resources." In addition, the Company had $0.6 million of income from
other investments. The 1994 increase over 1993 was primarily due to a one-time
receipt of $0.5 million for interest on funds that were previously held by the
operator of the jointly-owned wells covered by the Tennessee Gas Contract.
Interest Expense
Interest expense was $7.7 million in 1995, compared to $2.9 million in 1994
and $2.0 million in 1993. These increases were primarily due to higher average
borrowings used to expand the Company's oil and gas exploration and production
operations, including acquisitions under its VPP program which began in late
1994. In 1995, the increase in borrowings was largely the result of interim
agreements with Tennessee Gas, whereby the Company received only partial cash
payments from Tennessee Gas for sales of natural gas production under the
Tennessee Gas Contract. See "-- Liquidity and Capital Resources" and Note 7 to
the Consolidated Financial Statements. Until the Tennessee Gas Receivable was
paid, the Company was required to utilize its credit facilities to a greater
extent in order to finance its capital spending program. The increase in
interest expense in 1995 was partially offset by the increase in interest income
as previously discussed. Higher average interest rates were also a contributing
factor in the year to year increases.
Income Taxes
The income tax provision was $10.6 million in 1995, representing an
effective tax rate of 33.2%, compared to 34.2% and 29.8% in 1994 and 1993,
respectively. See Note 6 to Consolidated Financial Statements for the
reconciliation of the statutory federal income tax rate to the Company's
effective tax rates. A substantial portion of the income taxes provided for by
the Company during these periods is deferred to future years.
LIQUIDITY AND CAPITAL RESOURCES
Tennessee Gas Litigation
On August 16, 1996, the Texas Supreme Court denied Tennessee Gas' petition
for a rehearing of the Court's April 1996 decision in favor of the Company
regarding the validity and pricing provisions of the Tennessee Gas Contract, and
on September 30, 1996, Tennessee Gas paid the Company approximately $70 million,
representing the Tennessee Gas Receivable at that date.
29
<PAGE> 142
The Company had been accruing an accounts receivable amount (which included
interest as provided for in the contract) due from Tennessee Gas that included
the difference between the price that would have been paid for natural gas
pursuant to the terms of the Tennessee Gas Contract and the amount actually paid
for natural gas delivered from September 17, 1994 through April 30, 1996
pursuant to interim agreements whereby Tennessee Gas paid $3.00 per MMBtu for
all natural gas purchased during that period. Tennessee Gas paid the contract
price for natural gas deliveries subsequent to April 30, 1996 and through the
termination of the Tennessee Gas Contract effective January 1, 1997.
On December 23, 1996, the Company and Tennessee Gas entered into a
settlement covering all claims and litigation between them related to the
Tennessee Gas Contract. As part of the settlement, the Tennessee Gas Contract
was terminated effective January 1, 1997, approximately two years prior to its
expiration date. The parties also agreed to the dismissal of the contract
dispute that resulted in a November 1996 jury award to Tennessee Gas of $143.2
million (including $114 million in punitive damages). This settlement did not
affect the April 1996 decision of the Texas Supreme Court or the Company's prior
recovery of the Tennessee Gas Receivable. By resolving this major uncertainty
and avoiding any requirement to post a supersedeas bond of nearly $150 million
in order to appeal the verdict, the Company believes it is better positioned to
continue its strategic plan to grow and diversify its proved oil and gas
reserves and reduce its dependency on production from the Bob West Field.
Posting a supersedeas bond of such magnitude would have significantly and
adversely affected the amount of capital available for future investment,
therefore constraining the growth of the Company.
The early termination of the Tennessee Gas Contract with its above-market
pricing provisions resulted in downward revisions in the amounts of $59.5
million for estimated future net revenues before income taxes (based upon a
natural gas price of $2.10 per Mcf, the assumed realized spot market price on
June 30, 1996) and $51.4 million for PV-10, as compared to prior reserve reports
prepared as of June 30, 1996. Except for the revisions to future net revenues,
the Company's financial statements will not be directly affected as a result of
the settlement and early termination of the contract.
Cash Flow From Operating Activities
Net income adjusted for noncash charges was $54.2 million for the nine
months ended September 30, 1996, compared to $53.7 million during the same
period in 1995. Net cash provided by operating activities was $105.1 million
during the current year nine-month period, compared to $28.7 million in the
prior-year period. This increase resulted primarily from the receipt of the
Tennessee Gas Receivable on September 30, 1996 and, to a lesser extent, the
timing of cash receipts and payments. See Note 7 to the Consolidated Financial
Statements.
Net income adjusted for non-cash charges increased to $71.1 million in
1995, compared to $54.7 million in 1994. However, net cash provided by operating
activities declined from $50.1 million in 1994 to $30.1 million in 1995,
primarily as a result of interim agreements under which Tennessee Gas had been
paying $3.00 per MMBtu. This price was less than the contract price which
Tennessee Gas had been paying until September 1994.
Trade accounts receivable increased $11.7 million and accounts payable
increased $15.3 million in 1995 primarily due to the timing of cash receipts and
cash payments related to the high volume activity of the natural gas marketing
operations and, to a lesser extent, the timing of cash receipts and payments of
the oil and gas exploration and production operations.
Investing Activities
Capital expenditures in 1995 were $128.7 million, of which $121.3 million
was invested in oil and gas properties. Of the $121.3 million, $43.8 million was
for the purchase of oil and gas reserves under the Company's VPP program
(including the Michigan Acquisition), $33 million was for the Rocky Mountain
Acquisition and $19.4 million was for the development of the Bob West Field. The
remainder was largely for lease acquisitions, seismic evaluations and
exploratory drilling ($16.9 million) and development drilling ($7.5 million) on
non-Tennessee Gas Contract properties. The Company funded its capital
30
<PAGE> 143
expenditures through a combination of additional borrowings under its credit
facilities and internally generated cash.
Following the completion of two significant oil and gas property
acquisitions in late 1995, totaling $64 million, the Company established an
initial $70 million capital budget for 1996. Included in the total was $30
million for oil and gas property acquisitions, $22 million for development
drilling and $15 million for exploration. Capital expenditures under the program
for the nine months ended September 30, 1996 were $52.7 million, of which $50.6
million were invested in oil and gas operations. Of that total, $30.2 million
was for development drilling, $8.0 million for the purchase of proved reserves
under the Company's VPP program and $12.4 million for lease acquisitions,
seismic surveys and exploratory drilling. The expenditures were financed
principally with $16.4 million of proceeds from the sale of certain
non-strategic oil and gas properties and internally generated cash.
The 1996 capital budget was increased to $100 million in August, after the
Texas Supreme Court denied Tennessee Gas' petition for rehearing of the Court's
April 1996 decision in the Tennessee Gas Contract litigation. The additional
funds were allocated principally for development drilling in the Rocky Mountains
and for property acquisitions.
As of December 31, 1996, the Company completed the arrangements for the
purchase of Medallion. The Medallion Acquisition was funded by a cash payment of
$194.1 million (reflecting the $209.4 million cash purchase price reduced at the
January 2, 1997 closing by $15.3 million principally to reflect free cash flow
from Medallion's operations subsequent to the July 1, 1996 effective date) and
the issuance of warrants to purchase 435,000 shares of Common Stock. See
"Business and Properties -- Recent Acquisitions -- Medallion Acquisition." The
Company financed the cash portion of the purchase price by using its available
cash, borrowings under its existing Credit Facility and borrowings under the new
Revolving Credit Agreement secured by the assets acquired in the Medallion
Acquisition. See "-- Debt Financing." The net proceeds from the Offerings will
be used to reduce the amounts outstanding under the Bank Credit Facilities.
Giving effect to the Medallion Acquisition, the Company made gross
estimated capital expenditures of approximately $285 million in 1996. Of that
total, $199 million represents the Medallion Acquisition and the remaining $86
million was for exploration and development drilling on the Company's other
properties and for oil and gas property acquisitions. For 1997, the Company has
set a capital budget of $160 million. Of that total, $70 million has been
allocated to development and exploitation drilling, $25 million for exploration
and $65 million for oil and gas property acquisitions, including reserves
acquired under the VPP program. The Company believes that internally generated
cash, sales of certain non-strategic assets and borrowings under the Bank Credit
Facilities will be sufficient to fund its 1997 capital budget.
Debt Financing
On January 25, 1996, the Company completed the sale of $150 million
principal amount of 11% Senior Notes due 2003. The net proceeds of approximately
$145 million (after deducting expenses of the offering which were deferred and
are being amortized over the term of the Senior Notes) were utilized to reduce
the outstanding indebtedness under existing bank credit facilities and to repay
a note sold to a third party. Also during 1996, the Company consolidated its
existing bank credit facilities into one Credit Facility as described below and
entered into an additional Revolving Credit Agreement to fund a portion of the
purchase price for the Medallion Acquisition as described below.
Credit Facility
At June 30, 1996, the Company maintained three separate bank credit
facilities to support its operations. The Master Note Facility was utilized
primarily to support the expansion of the Company's exploration and production
and natural gas transportation businesses. The Company's natural gas marketing
subsidiary had two credit facilities, the Receivable Facility and the VPP
Facility, which were used primarily for working capital purposes and to support
the acquisition of oil and gas properties through volumetric production
payments.
31
<PAGE> 144
In July 1996, the Receivable Facility was paid in full and terminated. On
September 25, 1996, the Company consolidated the Master Note Facility and the
VPP Facility to create one revolving credit facility (the "Credit Facility"),
which will mature on September 30, 2000. The Credit Facility is secured by the
same collateral that was pledged to secure the Master Note and VPP facilities.
The borrowing base under the Credit Facility is a function of the lender's
determination of the value of the Company's oil and gas reserves, and as of
October 31, 1996, was limited to $75 million under the terms of the Indenture
governing the Senior Notes. The Credit Facility bears interest at a spread over
the prime rate or LIBOR, determined each quarter based on the Company's
consolidated debt-to-EBITDA ratio. As of December 31, 1996, $0.1 million was
outstanding under the Credit Facility and simultaneously with the Medallion
Acquisition, the Company borrowed an additional $55.5 million to fund a portion
of the Medallion Acquisition purchase price.
Revolving Credit Agreement for Medallion Acquisition
Simultaneously with the consummation of the Medallion Acquisition, the
Company entered into a new Revolving Credit Agreement with a group of banks. Of
the Revolving Credit Agreement's $135 million initial borrowing base, $30
million is structured as a term loan with a maturity of March 31, 1997; the
remaining $105 million revolving loan matures on September 30, 2000.
The Company's obligations under the Revolving Credit Agreement are secured
by substantially all of the oil and gas assets of Medallion and a pledge of
Medallion's common stock. The Revolving Credit Agreement permits the Company to
borrow at interest rates based upon the banks' prime rate or LIBOR. The
applicable spread over the prime rate or LIBOR is determined each quarter based
on the Company's consolidated debt-to-EBITDA ratio. Simultaneously with the
Medallion Acquisition, the Company borrowed $105 million under the Revolving
Credit Agreement to fund a portion of the purchase price of the Medallion
Acquisition.
Impact of Recently Issued Accounting Standards
The Financial Accounting Standards Board issued Statement of Financial
Accounting Standards ("SFAS") No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of." SFAS No. 121 is
effective for financial statements for fiscal years beginning after December 15,
1995. Adoption of SFAS No. 121 had no impact on the financial position or
results of operations of the Company.
32
<PAGE> 145
BUSINESS AND PROPERTIES
GENERAL
KCS is an independent oil and gas company primarily engaged in the
acquisition, exploitation, development and, to a lesser extent, exploration of
domestic oil and gas properties, and in the production and marketing of oil and
gas. Through its experienced management and geological and engineering staff,
the Company has successfully acquired and increased the value of its properties
through drilling and other exploitation techniques and has substantially
increased its reserves, production and cash flow. Over the five-year period
ended December 31, 1995, KCS replaced 400% of production and increased proved
oil and gas reserves 395% to 186.1 Bcfe at December 31, 1995. During the same
period, the Company increased its oil and gas production 392% to 20.3 Bcfe,
representing a compound annual growth rate of 49%. In addition, the Company
increased EBITDA from $7.1 million in 1991 to $75.1 million in 1995.
The Company's operations to date have focused primarily on properties in
the onshore Gulf Coast and Rocky Mountain regions. KCS augments its working
interest ownership of properties with the VPP program to acquire oil and gas
from properties which to date have been located primarily in the offshore Gulf
Coast region and in the Niagaran Reef trend in Michigan. As of December 31, 1996
the Company completed the arrangements for the acquisition of InterCoast Oil and
Gas Company (formerly Medallion Production Company and renamed KCS Medallion
Resources, Inc.) and certain of its affiliates, the Company's largest
acquisition to date. The Medallion Acquisition expanded the Company's operations
to include a third core operating area, the Mid-Continent region, encompassing
west Texas, the Texas Panhandle, northwest Oklahoma and north Louisiana. At June
30, 1996, on a pro forma basis reflecting the Medallion Acquisition, proved oil
and gas reserves were 369.4 Bcfe (84% proved developed), approximately double
the Company's historical proved reserves at December 31, 1995, and represented a
PV-10 value of $408.3 million. On a pro forma basis, the Company holds working
interests in 3,011 producing wells, 38% of which it operates. Approximately 63%
of the Company's reserves on a pro forma basis are attributable to wells it
operates.
Historically, the Company's most significant field was the Bob West Field
in south Texas, which accounted for approximately 16% (8% on a pro forma basis)
of the Company's production during the nine months ended September 30, 1996.
Most of the Company's natural gas sold from the Bob West Field was covered by
the Tennessee Gas Contract, which had been the subject of several lawsuits. On
December 23, 1996, the Company and Tennessee Gas entered into a settlement
covering all claims and litigation between them related to the Tennessee Gas
Contract. As part of the settlement, the Tennessee Gas Contract was terminated
effective January 1, 1997, approximately two years prior to its expiration date.
The parties also agreed to the dismissal of the contract dispute that resulted
in a November 1996 jury award to Tennessee Gas of $143.2 million (including
punitive damages of approximately $114 million). The December 1996 settlement
did not affect the Company's successful conclusion of litigation earlier in the
year relating to the validity and pricing provisions of the Tennessee Gas
Contract and its recovery of the Tennessee Gas Receivable.
The Company also operates a natural gas transportation business and a
natural gas marketing and services business, which together recorded a $0.3
million operating loss during the nine months ended September 30, 1996. The
Company's natural gas transportation business consists of a 150-mile intrastate
pipeline system and related gathering lines located between Houston and Dallas,
Texas and 17 natural gas gathering systems (including the Texas system acquired
in the Medallion Acquisition) totaling more than 300 miles in Texas, Montana and
Louisiana. Through its natural gas marketing and services business, the Company
buys and resells natural gas directly to industrial and commercial end users and
also offers energy supply and transportation consulting services.
BUSINESS STRATEGY
The Company has grown through a balanced strategy of reserve acquisitions
and development and exploratory drilling. The Company plans to continue to
broaden its reserve base and increase production
33
<PAGE> 146
and cash flow through (i) the acquisition of attractively priced oil and gas
companies and producing properties that provide additional development or
exploratory potential, (ii) the exploitation and development of its existing
asset base, (iii) the operation and ownership of a majority working interest in
a significant number of its properties to allow the Company greater control over
future development, drilling, completing and lifting costs and marketing of
production, (iv) the acquisition of oil and gas reserves through the VPP
program, (v) the pursuit of a balanced exploration program that includes a
number of high-potential opportunities, and (vi) the extensive use of advanced
technologies, most notably 3-D seismic, computer-enhanced basin analysis,
reservoir simulation and specialized drilling applications and stimulation
techniques to better delineate and produce reserves.
To implement its strategy, the Company intends to take advantage of several
key strengths, including (i) an experienced and capable team of oil and gas
industry professionals with a significant financial stake in the success of the
Company, (ii) a significant inventory of attractive development and exploratory
drilling opportunities within its existing property base and undeveloped acreage
position, (iii) established relationships with proven industry partners that
provide opportunities to participate in diverse exploration prospects, (iv) an
efficient administrative and operating structure that emphasizes an
entrepreneurial and opportunistic approach, and (v) a strong financial focus
which manifests itself not only in innovative transactions, but also in asset
risk management.
RECENT ACQUISITIONS
Medallion Acquisition
As of December 31, 1996, the Company completed the arrangements for the
acquisition of all of the outstanding stock of InterCoast Oil and Gas Company
(formerly Medallion Production Company and renamed KCS Medallion Resources,
Inc.), GED Energy Services, Inc. and InterCoast Gas Services Company, (renamed
Medallion Gas Services, Inc.), indirect wholly-owned subsidiaries of
MidAmerican, for a total price of approximately $214.4 million, consisting of
$209.4 million in cash and warrants to purchase 435,000 shares of Common Stock
at an exercise price of $45.00 per share. The Medallion Acquisition was closed
on January 2, 1997, and the cash portion of the purchase price was reduced by
$15.3 million at closing principally to reflect free cash flow from Medallion's
operations subsequent to the July 1, 1996 effective date.
The information included in this Prospectus regarding Medallion has been
provided by Medallion. No assurance can be given by the Company as to the
accuracy or completeness of such information. Due diligence has been conducted
by the Company only on those properties and other assets of Medallion that the
Company believes have the most significant value. The Company received certain
representations, warranties and indemnification agreements from the sellers in
connection with the Medallion Acquisition. These representations, warranties and
indemnification agreements will survive the closing of the transaction for
specified periods. MidAmerican Capital Company, a direct wholly-owned subsidiary
of MidAmerican, has agreed to guaranty certain obligations of the sellers under
the agreements relating to the Medallion Acquisition, including the sellers'
indemnification agreements.
Medallion's principal oil and gas assets were estimated as of June 30, 1996
by an independent reserve engineer to be 202.1 Bcfe of proved oil and gas
reserves, consisting of 161.3 Bcf of natural gas (80% of total proved reserves)
and 6.8 MMbbls of oil and condensate. These reserves are located primarily in
the Mid-Continent region encompassing west Texas, the Texas panhandle, northwest
Oklahoma and north Louisiana. Proved developed reserves account for 88% of
Medallion's total proved reserves and the average reserve life at year-end 1995
was 8.0 years. Medallion owns interests in 2,061 gross (675 net) wells, and
approximately 68% of reserves are attributable to wells it operates. The
Medallion Acquisition more than doubles the Company's reserve base and adds
substantial management and technical expertise, particularly in the new
Mid-Continent core operating area. Descriptions of the principal producing
properties acquired are set forth under "Principal Working Interest Oil and Gas
Properties -- Medallion Acquisition Properties."
34
<PAGE> 147
Over the three and a half-year period ended June 30, 1996, and giving
effect to the acquisition of its Sawyer Canyon properties in April 1996,
Medallion replaced 251% of its production and increased reserves 148% through
property acquisitions, its EID program, and, to a lesser extent, exploratory
drilling, all of which the Company expects to continue. Since its acquisition by
MidAmerican in April 1992, Medallion has acquired 188.7 Bcfe of proved reserves
through 31 acquisitions at an average acquisition cost of $0.67 per Mcfe.
Medallion's EID program targets drilling prospects that enhance the
economic recovery of oil and gas in producing areas and horizons to a level
greater than that previously achieved by the owners of the prevailing leasehold
by increasing the density of wells that penetrate known reservoirs. Typically,
development of EID prospects requires that Medallion obtain some or all of the
rights to drill on acreage that is held by production, thus providing the
opportunity to drill without making significant capital expenditures for
undeveloped leasehold acreage. The EID program has been implemented by members
of Medallion's current management team (who are expected to continue with the
Company following the Medallion Acquisition) since 1985. During the three-year
period ended December 31, 1995, Medallion developed 53.7 Bcfe of proved reserves
at an average finding cost of $0.75 per Mcfe through its EID program by
successfully completing 52 of 87 prospects. At September 30, 1996, Medallion had
identified more than 170 potential EID locations in its core operating areas and
has 41 proved undeveloped locations on its acreage. In September 1996, average
daily production from the Medallion properties was 3,453 bbls of oil and
condensate and 63,834 Mcf of natural gas, equivalent to 84,552 Mcfe. Medallion
also operates a 37-mile Texas gathering system and has natural gas marketing
operations based in Tulsa, Oklahoma, which had average sales volumes of 210,000
Mcf per day in September 1996.
Medallion has a demonstrated track record of consistent growth in reserves,
production, revenues and cash flow every year since its inception in 1992. It
utilizes a balanced approach to drilling and reserve acquisitions and has
assembled a high quality, entrepreneurial management and technical team
consisting of 72 employees at December 31, 1996, located principally in its
Tulsa, Oklahoma headquarters. KCS anticipates that substantially all of these
employees will remain with Medallion following the acquisition and that
Medallion will continue to pursue its current operational strategies.
Rocky Mountain Acquisition
In November 1995, the Company acquired substantially all of the oil and gas
assets of Natural Gas Processing Company for a purchase price of approximately
$33 million. The Company acquired interests in 531 gross (301 net) wells located
in over 30 different fields, principally in six producing basins located in
Wyoming, Colorado, Montana and North Dakota. Proved reserves attributable to the
acquired properties were estimated by independent reserve engineers at September
30, 1995 to be 66.7 Bcfe, consisting of 40.9 Bcf of natural gas and 4.3 MMbbls
of oil and representing an average acquisition cost of $0.49 per Mcfe. Since the
acquisition, the Company has undertaken an aggressive field development and
acreage acquisition program in the Rocky Mountain region which has resulted in
several recent drilling successes and prospective drilling opportunities,
primarily in the Manderson Field in north central Wyoming. As of June 30, 1996,
the Company's well count in the Rocky Mountain region had increased to 587
wells, of which 374 (or approximately 64%) are operated by the Company.
Approximately half of the natural gas production from the acquired properties is
subject to multi-year contracts with local utility companies at prices that
ranged from $1.70 to $2.00 per Mcf.
In addition, the Rocky Mountain Acquisition included approximately 197,000
gross (160,000 net) acres of largely underdeveloped properties. As the result of
additional property acquisitions, the Company has increased the lease holdings
in this area to approximately 240,000 gross (196,700 net) developed and
undeveloped acres as of September 30, 1996. The Company also acquired a
significant inventory of oil and gas equipment and supplies, vehicles, and
buildings as well as natural gas gathering systems consisting of approximately
200 miles of pipeline. Following the acquisition, the Company hired highly
experienced and technically competent exploration and operational personnel with
experience in the Rocky Mountain region who were formerly employed by the
seller, and following additional hiring, the Company's staff in the region
totaled 55 persons as of December 31, 1996.
35
<PAGE> 148
Michigan Acquisition
In December 1995, the Company acquired 24.6 Bcfe of proved reserves in the
northern and southern Niagaran Reef trends in Michigan for $31 million,
including a volumetric production payment covering certain reserves, escalating
working interests in related properties and participation rights and an
overriding royalty interest in an exploration program, representing an average
acquisition cost of $1.26 per Mcfe. The VPP provides for the delivery to the
Company of certain oil and gas reserves totaling 20.3 Bcfe scheduled to be
delivered from December 1995 through January 2006, without any burden of
development and lease operating expenses. The VPP reserves were estimated as of
September 30, 1995 to consist of 13.7 Bcf of natural gas and 1.1 MMbbls of oil.
Based on independent reserve reports as of September 30, 1995, the working
interests in related properties that were acquired in the Michigan Acquisition
separate from the VPP added 3.1 Bcf of natural gas and 219 Mbbls of oil to the
Company's proved reserves.
OIL AND GAS PRODUCTION AND EXPLORATION
All of the Company's production and exploration activities are located
within the United States.
Development and Production Activities
During the three-year period ended December 31, 1995, the Company
participated in the drilling of 61 development wells with a 98% success rate.
The majority of this development was in the Bob West Field, where the Company
drilled 38 wells and completed 38. During the first nine months of 1996, the
Company substantially increased its level of development drilling in other areas
and drilled 27 of 29 wells and completed 24 of 27 wells in areas other than the
Bob West Field. The Company's activities are now focused on the Manderson Field
in the Big Horn Basin of Wyoming, the Sweet Grass Arch area in Montana, the
Langham Creek Area and Glasscock Ranch Field in Texas and the Laurel Ridge Field
and the Tensas Parish Area in Louisiana. For 1996, the Company established an
initial development drilling budget of $22 million, which was subsequently
increased to $40 million in August 1996 as a result of the favorable decision of
the Texas Supreme Court on the Tennessee Gas Contract. For details on major
development activities on a field-by-field basis, see "-- Principal Working
Interest Oil and Gas Properties."
The Company has currently identified over 450 development drilling and
recompletion locations and 170 EID locations, representing approximately a
four-year inventory, and has initially budgeted $70 million for development
activities in 1997. The Company plans to drill, recomplete and workover as many
as 150 wells in 1997 and focus its development drilling program primarily on the
fields in the Rocky Mountain and onshore Gulf Coast regions discussed above and,
with the consummation of the Medallion Acquisition, on the Sawyer Canyon Field
and several of Medallion's prospects in the west Texas, ArkLaTex, Anadarko and
Arkoma areas located in the Mid-Continent region. See "Principal Working
Interest Oil and Gas Properties."
Exploration Activities
During the three-year period ended December 31, 1995, the Company
participated in the drilling of 58 exploratory wells with a 50% success rate.
Discoveries included wells in the Bob West Field, Langham Creek Area and Laurel
Ridge Field. During the first nine months of 1996, the Company participated in
the drilling of 11 exploratory wells and completed five wells, two of which it
operates. Of the 1996 exploration budget of $15 million, $12.4 million was spent
during the nine months ended September 30, 1996, which included expenditures for
lease acquisitions, seismic surveys and exploratory drilling. Discoveries in
1996 included the St. Jo prospect (now designated as the Aubrey and Wilsonia
Fields) located in Tensas Parish, Louisiana, where seven successful wells were
drilled and completed as of September 30, 1996.
The Company's policy is to commit no more than 25% of its operating cash
flow to exploration activities and generally no more than $750,000 for any
single well. The Company has established an initial budget of $25 million for
exploration in 1997 and intends to participate in drilling a wide variety of
36
<PAGE> 149
prospects, including both low-risk and high-risk, high-potential projects in
order to maintain a balanced program with the potential for significant reserve
additions.
During 1997, the Company plans to participate in the drilling of up to 50
exploration prospects and to continue 3-D and 2-D seismic data acquisition and
analysis. Exploration activities will focus primarily on properties located in
the onshore Gulf Coast regions of Texas and Louisiana and in the Rocky
Mountains. As of December 31, 1996, the Company had finalized negotiations on
two exploratory projects in the Rocky Mountain region and is negotiating a
third. The two exploratory projects on which negotiations are completed include
(i) three Lodgepole prospects, in which the Company owns a 30% working interest,
located near Conoco's Eland Field in Stark County, North Dakota (one of which
was drilled in 1996 and was non-productive) and (ii) a Wind River Basin project,
in which the Company has a 95% working interest, on 7,500 gross acres in central
Wyoming that targets the Lance, Shannon, Mesa Verde, Frontier and Muddy sand
formations. The Lodgepole prospects are based on a 109-square mile 3-D seismic
shoot covering approximately 68,530 gross (16,653 net) acres. The Company is
currently negotiating to acquire a 50% working interest in a third exploration
project on a 12,000 gross-acre Tyler sand prospect in central Montana. The
Company also intends to further analyze the undeveloped acreage it acquired in
the Medallion Acquisition for possible exploration prospects and continue its
participation in exploration projects in Michigan, where a 3-D seismic program
is currently under way.
Sale of Certain Properties
In early 1996, the Company sold several non-strategic properties located in
south Texas, including its interest in the San Salvador, Bloomberg and Birdie
Fields, for a total sale price of $16.4 million. As of December 31, 1995, the
properties had reserves attributable to them by an independent reserve engineer
of 9.4 Bcf of natural gas and 63,000 bbls of oil. Prior to their sale, the
properties contributed 232 Mcf of natural gas and 2,900 bbls of oil to the
Company's production in 1996.
37
<PAGE> 150
PRINCIPAL WORKING INTEREST OIL AND GAS PROPERTIES
Approximately 85% of the Company's PV-10 of proved reserves and 92% of its
total proved oil and gas reserves, after giving effect to the Medallion
Acquisition, are attributable to properties in which it has a working interest.
The Company is the operator of 1,139 wells, representing 64% of the PV-10 of
proved reserves attributable to its working interests (54% of PV-10 for all
proved reserves). The following table sets forth data as of June 30, 1996 (after
giving effect to the Medallion Acquisition and the termination of the Tennessee
Gas Contract effective on January 1, 1997) regarding the number of gross
producing wells, the estimated quantities of proved oil and gas reserves and the
PV-10 attributable to the Company's principal properties in which it owns
working interests.
The following table does not include reserves or PV-10 values attributable
to the Company's VPP program. See "-- Volumetric Production Payment Program and
Underlying Principal Properties."
<TABLE>
<CAPTION>
ESTIMATED PROVED RESERVES
GROSS ---------------------------------------------------
PRODUCING OIL NATURAL GAS TOTAL % OF PV-10
PROPERTY/AREA WELLS (MBBLS) (MMCF) (MMCFE) TOTAL ($000S)
------------- --------- ------- ----------- ------- ----- --------
<S> <C> <C> <C> <C> <C> <C>
Onshore Gulf Coast:
Bob West Field............. 50 -- 24,844 24,844 7% $ 36,108
Langham Creek Area......... 11 182 11,933 13,028 4 16,266
Laurel Ridge Field......... 2 232 3,629 5,019 1 11,342
Glasscock Ranch Field...... 11 84 3,117 3,622 1 2,557
Tensas Parish Area......... 3 105 1,781 2,409 1 3,224
Others..................... 256 1,701 12,309 22,512 7 18,325
----- ------ ------- ------- --- --------
Subtotal........... 333 2,304 57,613 71,434 21 87,822
Rocky Mountain:
Big Horn Basin
Manderson Field......... 17 2,134 10,560 23,364 7 18,748
Others.................. 207 1,475 4,896 13,748 4 11,008
San Juan Basin............. 49 -- 11,345 11,345 3 4,788
Wind River Basin........... 23 82 4,435 4,926 2 2,227
Sweet Grass Arch........... 208 567 1,176 4,577 1 4,486
Green River Basin.......... 82 34 3,680 3,882 1 2,047
Others..................... 1 15 6 96 -- 77
----- ------ ------- ------- --- --------
Subtotal........... 587 4,307 36,098 61,938 18 43,381
Michigan Niagaran Reef
Trend...................... 30 285 3,039 4,748 1 4,974
Medallion Acquisition:
Sawyer Canyon Field........ 345 69 54,646 55,062 16 54,659
ArkLaTex Area.............. 74 90 21,641 22,180 7 29,951
Anadarko Basin............. 216 177 19,699 20,762 6 20,272
Rocky Mountain............. 842 1,118 13,787 20,497 6 11,290
Gulf Coast and South
Texas................... 95 854 11,176 16,299 5 25,162
Offshore Gulf of Mexico.... 76 442 11,428 14,081 4 21,113
California................. 36 1,661 1,985 11,949 4 7,975
Others..................... 377 2,386 26,966 41,283 12 41,017
----- ------ ------- ------- --- --------
Subtotal........... 2,061 6,797 161,328 202,113 60 211,439
----- ------ ------- ------- --- --------
Total.............. 3,011 13,693 258,078 340,233 100% $347,616
===== ====== ======= ======= === ========
</TABLE>
Set forth below are descriptions of certain of the Company's significant
oil and gas producing properties and those targeted for significant drilling
activity in 1997.
38
<PAGE> 151
Onshore Gulf Coast Properties
Bob West Field. The Company has interests in approximately 863 gross (599
net) acres in this field located in Zapata and Starr Counties, Texas. The field
produces natural gas from a series of 20 different Upper Wilcox sands with
formation depths ranging from 9,500 to 13,500 feet that require stimulation by
hydraulic fracturing to effectively recover the reserves. Because the majority
of this field is situated under Lake Falcon on the Rio Grande River, most wells
must be drilled directionally under the lake from common lakeshore drill sites.
The Company owns interests in two principal areas in the Bob West Field. During
September 1996, the average combined rate of production attributable to the
Company's net revenue interest in these areas was approximately 12,000 Mcf of
natural gas per day. Prior to the termination of the Tennessee Gas Contract
effective January 1, 1997, substantially all of this natural gas production was
covered by the contract. See "-- Legal Proceedings -- Tennessee Gas Litigation,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources" and Note 7 to the Consolidated
Financial Statements.
With the termination of the Tennessee Gas Contract, the Company has the
equivalent of a 12.5% working interest in all production from the Guerra "A" and
Guerra "B" units. As of September 30, 1996, these units contained 32 producing
wells. The Company has the right to take all its production in kind, and during
September 1996, the average combined rate of production attributable to the
Company's non-operated net revenue interest was approximately 6,500 Mcf of
natural gas per day. One well is currently drilling and one has been permitted
on the Guerra "A" and Guerra "B" units.
The Company also owns a 100% working interest in and operates 511 acres
referred to as the Falcon/Bob West Field. During September 1996, the average
combined rate of production attributable to the Company's net revenue interest
was approximately 5,500 Mcf of natural gas per day. Substantially all of this
acreage was covered by the Tennessee Gas Contract and contains 18 producing
natural gas wells.
In September 1996, the Company began an extensive workover and recompletion
program on the acreage it operates. The Company is utilizing state-of-the-art
well log analysis, performance histories and bottom hole pressure analysis in an
effort to mitigate declines in gas production.
Langham Creek Area. This area is comprised of the Cypress, Cypress Deep and
Langham Creek Fields in western Harris County, Texas, where the Company has
non-operated interests in 7,349 gross (3,375 net) acres. Multiple horizons in
this area produce oil and gas from Eocene age sandstones in the Yegua formation
from 6,000 to 7,500 feet and in the Wilcox formation from 9,000 to 13,000 feet.
The Company owns working interests varying from 28% to 65% in 13 wells in
this area, representing an average net revenue interest of approximately 39%.
During September 1996, the nine producing wells in the Wilcox zone had an
average combined rate of production attributable to the Company's interest of
approximately 7,300 Mcf of natural gas and 82 bbls of oil per day. The
geological and geophysical evidence indicates the potential for as many as six
to nine additional drilling locations, with the upper Wilcox sands as the
primary target. The Company plans to continue active development in the area and
plans to drill as many as three additional wells in 1997.
Laurel Ridge Field. The Company is the operator of this field located in
Iberville Parish, Louisiana and has a 26% net revenue interest in 3,773 gross
(1,221 net) acres around two discovery wells. The #1 Claiborne Plantation was
completed in August 1995 in the Cibicides hazzardi (Frio) sand and the second
discovery, the #2 Claiborne Plantation, was completed in December 1995 in the
shallower Miogyp (Frio) formation. Based on the results of the first two
discovery wells and 2-D seismic surveys, the Company drilled two additional
step-out wells in July and October 1996 which were temporarily abandoned. The
Company has deferred future development of the subject Frio formation until the
completion of a 3-D seismic survey. A 3-D seismic program is scheduled to
commence in the first quarter of 1997 to identify additional locations and to
confirm the possible utilization of the wellbores of the two temporarily
abandoned wells for potential side-track completions. During September 1996, the
average
39
<PAGE> 152
production attributable to the Company's interest was 2,100 Mcf of natural gas
and 210 bbls of oil per day.
Glasscock Ranch Field. This field is located in Colorado County, Texas. The
Company and its partners leased approximately 2,800 acres and in 1994 drilled
and completed the #5 Glasscock well as a natural gas well in the upper portion
of the lower Wilcox sand section, a new reservoir for the field. The Company has
recently increased its working interest to approximately 85% and plans to
implement a development drilling program for 1997 which could include as many as
three additional wells.
Tensas Parish Area. The Company currently has leases or options covering
32,000 acres in this area and in mid-1996 initiated a major exploration and
development drilling program in its St. Jo (now referred to as the Aubrey and
Wilsonia Fields), Barfield and Chicago Mills prospects. The Company currently
owns a 100% working interest in these three prospects. Of the eight wells
drilled to date in the Aubrey and Wilsonia Fields, six were completed, one is in
the completion process and one was a dry hole. Five of the completed wells
targeted the lower Tuscaloosa at a depth of 8,300 feet and one well targeted the
Wilcox at a depth of 3,200 feet. The Company plans to drill as many as four
additional wells in these fields during the next six months. During September
1996, the average production attributable to the Company's interest in the
Aubrey and Wilsonia Fields was 1,600 Mcf of natural gas and 140 bbls of oil per
day. The Company expects this level of production to increase as a result of
further stimulation and operational enhancements commenced in October 1996.
The Company has 2,330 acres under lease in its Barfield prospect and has
completed a six square mile 3-D seismic survey on the prospect. Three recent
exploration wells were dry, but provided the Company with additional data on the
geology and geophysics of the prospect. A 12,500 foot well to test the James
Lime/Pettet Limestone reef is in the planning stage.
The Company has taken options on or leased approximately 26,700 acres in
its Chicago Mills Prospect. A 26-square mile 3-D seismic survey has been
completed on a portion of the optioned acreage and resulted in the leasing of
8,800 acres. The Company has staked five locations, one of which was abandoned,
to test seven different prospects delineated by the seismic data. The remainder
of the optioned acreage is scheduled for evaluation using 3-D seismic covering a
29-square mile area beginning in early 1997.
Rocky Mountain Properties
Big Horn Basin. This basin is located in north central Wyoming encompassing
parts of Washakie, Big Horn, Hot Springs, and Park counties. The Company
currently has lease holdings on 101,487 gross (86,264 net) acres. The Company
operates 106 wells and has additional interests in 124 non-operated wells in a
total of 18 fields. The major producing properties in the basin are the
Manderson Field that produces oil and gas at depths from 4,500 to 8,000 feet,
the Golden Eagle Field which produces oil and gas at depths from 3,200 to 10,000
feet, the 14-Mile Field that produces oil and gas at depths from 6,000 to 11,000
feet, the Grass Creek Field that produces oil and gas at depths from 2,400 to
7,000 feet and the Sellers Draw Field that produces natural gas at depths from
15,000 to 20,000 feet.
The Manderson Field is located on a northwest-southeast trending anticlinal
nose in the Big Horn Basin. The Company has expanded its holdings in the field
from approximately 7,500 acres obtained in the Rocky Mountain Acquisition to
more than 22,000 acres and owns a 100% working interest. The field has multiple
reservoirs that are producing or potentially productive: the Phosphoria
Dolomite, the Lakota sands, the Dakota sands, the Muddy sands, the Octh Louie
sands, and the Frontier sands.
The Manderson Field was discovered in 1951 and 16 wells targeting the
Phosphoria Dolomite were drilled primarily using 640-acre spacing from 1951 to
1954. Another well drilled in 1990 tested gas in the Phosphoria but was
recompleted to the Muddy sands as a natural gas producer due to the high
percentage of hydrogen sulphide present in the Phosphoria formation. To date,
the field has produced 8.2 Bcf of natural gas and more than 2.2 MMbbls of oil
from the Phosphoria, 32.4 Bcf of natural gas from the Muddy sands and lesser
amounts from the Frontier and Octh Louie sands.
40
<PAGE> 153
The Company is currently starting up an injection system and constructing
processing facilities to handle the sour natural gas produced from the
Phosphoria formation to allow for full field development. Since the drilling and
completion of its first well in April 1996, the Company has drilled and
completed 16 development wells, recompleted one previously existing well, is
currently completing seven wells and is drilling two wells in the Phosphoria
Dolomite, the deepest known productive reservoir in the Manderson Field. The
completed wells, in which the Company owns an 81% net revenue interest, have
tested at rates ranging from 200 to 1,900 bbls of oil per day and from 450 to
4,000 Mcf of natural gas per day.
Daily production in the Manderson Field has been constrained due to
limitations imposed by the State of Wyoming and the federal government on the
amount of sour gas that can be flared. In late December, the Company began
start-up of an injection well and associated compression facility. Completion of
the injection system should enable the Company to inject 8,000 Mcf of sour gas
per day and allow oil production to increase to approximately 5,000 bbls per
day. The sour gas will be injected into the Phosphoria reservoir for pressure
maintenance. Currently, six of the completed wells have been tied into the
injection system and are on production.
An amine treatment plant designed to treat the sour gas to marketable
specifications is scheduled for completion late in the first quarter of 1997.
Completion of the treatment facilities will allow the treated natural gas to be
marketed with the sour inert gas being reinjected into a disposal well. The
treatment facilities, together with the gas injection system, should provide for
sufficient gas-handling capacities for 16,000 Mcf of natural gas per day and
allow for the production of approximately 10,000 bbls of oil per day. There can
be no assurance that the Company will be able to produce oil and gas at rates
sufficient to fully utilize such capacities.
The Company drilled a total of 23 wells targeting the Phosphoria and two
other wells targeting shallower zones during 1996. It currently has three
drilling rigs active. Log data and tests from the new wells drilled to date have
suggested potential pays in the Lakota and the Dakota sands for oil and/or gas,
the Muddy sands for gas, the Octh Louie sands for oil, and the Frontier sands
for oil and/or gas. In 1997, the Company plans to drill an additional 27
Phosphoria wells and at least ten additional wells targeting the shallower
reservoirs. Drilling results to date, coupled with the acquisition of additional
seismic data indicate that the field may have significant prospective potential.
During September 1996, the average production attributable to the Company's
interest in the Manderson Field was 1,600 Mcf of natural gas and 790 bbls of oil
per day.
Sweet Grass Arch. The Company has an interest in 79,539 gross (57,904 net)
acres in this major producing area located in Toole County, Montana. The Company
currently operates 202 wells and has interests in six non-operated wells in the
area. The most important oil producing property in the area is the Homestake
Field, where the Company currently operates 67 wells. The Homestake Field
produces from the Sunburst sand at depths ranging from 1,400 to 1,700 feet.
Discovered in 1922, the field was actively developed during the 1936-1941 period
and again in the mid-1960s. During that latter period, a waterflood project was
initiated with little success due primarily to the lack of wellbore integrity.
During the late 1980s, two new wells were drilled in an attempt to revive the
field again with little success because of poor completion techniques. The
Company has begun an active development program designed to improve wellbore
integrity, utilize state-of-the-art completion techniques and redesign the
secondary recovery project. The Company initiated the program in September 1996
and has drilled and completed 16 wells. Eight of the completed wells have been
tied into facilities and together are currently producing in excess of 500 bbls
of oil per day and are still unloading after stimulation. Seven wells are
waiting for weather to allow completion of a pipeline connection and power line
installations prior to being put on production. Two additional wells are
currently being drilled to depths of 700 feet. The recent drilling activity is
believed to have substantially increased the productive area of the field. The
Company plans to drill an additional 15 wells in the Homestake Field in 1997.
41
<PAGE> 154
Medallion Acquisition Properties
Sawyer Canyon Field. Medallion's holdings in the Sawyer Canyon Field,
located in Sutton County, Texas, represented 16% of the Company's proved
reserves as of June 30, 1996 on a pro forma basis. Medallion purchased these
properties in April 1996 from Enron Oil & Gas Company. Medallion owns interests
in 345 gross (314 net) wells, of which it operates 322 gross (293 net) wells.
Medallion's average working interest in this field is 91%, and its leasehold
position consists of approximately 34,887 gross (34,053 net) acres. During
September 1996, the average combined rate of production attributable to its net
revenue interest was approximately 18,300 Mcf of natural gas per day.
The main producing formation in the Sawyer Canyon Field is the Canyon
sandstone at a depth of approximately 5,500 feet. Natural gas in the Canyon
formation is stratigraphically trapped in lenticular sandstone reservoirs. A
typical Sawyer Canyon Field well encounters multiple productive reservoirs
within the 800 to 1,400 foot thickness of the Canyon formation. These Canyon
reservoirs tend to be discontinuous and generally exhibit lower porosity and
permeability, characteristics which reduce the area that can be effectively
drained by a single well to units as small as 40 acres.
Medallion's 55.1 Bcfe of proved reserves attributable to the Sawyer Canyon
Field are 97% proved developed. The Company currently plans to drill up to seven
additional locations to exploit the remaining proved undeveloped reserves. The
Company also believes that additional proved reserves may ultimately be
attributed to many of the 30 or more 40-acre drilling locations remaining on the
property. The Company has also identified several recompletion projects in
existing wellbores into Canyon sand reservoirs not currently producing. In
addition to exploiting these Canyon sand development opportunities, the Company
currently intends to evaluate portions of the Sawyer Canyon Field for potential
in the shallower Wolfcamp and deeper Strawn formations which have been found to
be productive in the area.
ArkLaTex Area. Medallion's reserve holdings in the ArkLaTex Area,
representing approximately 7% of the Company's total proved reserves as of June
30, 1996 on a pro forma basis, are located primarily in Bossier, Claiborne,
Lincoln, and Union Parishes in north Louisiana. Medallion owns an interest in 74
gross (38 net) wells of which 42 gross (36 net) wells are operated by the
Company. Medallion's average working interest in its ArkLaTex Area operated
wells is approximately 86%. Average daily production from the ArkLaTex Area, net
to Medallion's interest, was approximately 8,100 Mcf of natural gas and 56 bbls
of oil during September 1996. Production in the ArkLaTex Area is primarily from
the Hosston, Cotton Valley and Haynesville formations of Cretaceous and Jurassic
age at depths of 5,500 to 10,000 feet. These formations are lower permeability
sandstones which were developed on 640-acre spacing and require EID and advanced
fracture stimulations to drain the reserves in place adequately. Medallion
drilled four wells and spudded four additional wells in the ArkLaTex Area in
1996.
Medallion's largest concentration of reserves in the ArkLaTex Area is in
the Elm Grove Field, Bossier Parish, Louisiana. At June 30, 1996, net proved
reserves were 19.1 Bcfe, of which 94% was proved developed. Production from the
Elm Grove Field is primarily natural gas from the Hosston and Cotton Valley
formations at depths of 7,000 to 9,600 feet. Medallion owns an interest in 42
gross (27 net) wells, of which 29 gross (27 net) wells are operated by
Medallion. Medallion's operated leasehold position consists of approximately
5,760 gross (5,649 net) acres. Average daily production from the Elm Grove
Field, net to Medallion's interest, was approximately 6,000 Mcf of natural gas
and 33 bbls of oil during September 1996.
Since Medallion acquired its first interest in the Elm Grove Field in 1994,
it has drilled 11 productive EID wells, recompleted several of the existing
wells to access behind pipe reserves and discovered a deeper productive zone not
previously produced in the field. Average gross natural gas production from the
field reached a rate of 13,200 Mcf per day at the beginning of 1996, up from an
average daily production level of 2,000 Mcf per day when Medallion assumed
operations in August 1994. Medallion has identified several behind-pipe zones
and three to five additional EID well locations.
Anadarko Basin Area. Medallion's Anadarko Basin properties are located in
northwest Oklahoma and the Texas panhandle. Medallion owns an interest in 216
gross (83 net) wells, of which it operates
42
<PAGE> 155
155 gross (60 net) wells. Average daily production from the area, net to
Medallion's interest, was approximately 10,300 Mcf of natural gas and 70 bbls of
oil during September 1996. Total net proved reserves, as of June 30, 1996, were
20.8 Bcfe with 98% categorized as proved developed.
The majority of the Medallion's properties in this area are located on the
Northern Shelf and predominantly produce natural gas from various formations of
Pennsylvanian and Pre-Pennsylvanian age at depths of 7,000 to 12,000 feet.
Medallion's Mills Ranch Field, operated by Chevron, is in the deeper part of the
basin with production from depths of 10,000 to 20,000 feet. Pre-Pennsylvanian
reservoirs include the Mississippi, Chester and Hunton formations and are
typically fractured carbonates. Pennsylvanian reservoirs include the Redfork,
Atoka and Morrow sandstones.
During the four-year period ended December 31, 1995, Medallion participated
in the drilling of 44 gross (37 net) EID wells in the Anadarko Basin Area.
Medallion drilled eight wells in this area in 1996. The Company plans to
continue to exploit areas of the Anadarko Basin that require EID wells for
adequate reserve drainage and intends to drill 16 locations in this area during
1997.
VOLUMETRIC PRODUCTION PAYMENT PROGRAM AND UNDERLYING PRINCIPAL PROPERTIES
The Company augments its working interest ownership of properties with a
volumetric production payment ("VPP") program, a method of acquiring oil and gas
reserves scheduled to be delivered in the future at a discount to the current
market price in exchange for an up-front cash payment. A volumetric production
payment is comparable to a term royalty interest in oil and gas properties and
entitles the Company to a priority right to a specified volume of oil and gas
reserves scheduled to be produced and delivered over a stated time period.
Although specific terms of the Company's volumetric production payments vary,
the Company is generally entitled to receive delivery of its scheduled oil and
gas volumes at agreed delivery points, free of drilling and lease operating
costs and, in certain cases, free of state severance taxes. The Company is not
the operator of any of the properties underlying its volumetric production
payments, and it does not bear any development or lease operating expenses.
After delivery of the oil and gas volumes, the Company arranges for further
downstream transportation and sells such volumes to available markets. The
Company believes that its VPP program diversifies its reserve base and achieves
attractive rates of return while minimizing the Company's exposure to certain
development, operating and reserve volume risks. Typically, the estimated proved
reserves of the properties underlying a volumetric production payment are
substantially greater than the specified reserve volumes required to be
delivered pursuant to the production payment.
Through June 30, 1996, the Company had invested $66.2 million under this
program, acquiring proved reserves of 38,841 MMcf of natural gas and 1,103 Mbbl
of oil, representing an average acquisition cost of $1.46 per Mcfe, without the
burden of development and lease operating expenses. As of June 30, 1996, the
Company had recovered $36.8 million from the sale of oil and gas received under
its VPP program. The VPP program accounted for approximately $60.6 million (15%)
of the Company's PV-10 of proved reserves, and 29,210 MMcfe (8%) of its total
proved oil and gas reserves as of June 30, 1996, after giving effect to the
Medallion Acquisition.
43
<PAGE> 156
The following table shows, as of June 30, 1996, the oil and gas deliveries
to the Company scheduled to be made pursuant to its VPP program over the period
from July 1, 1996 through December 31, 2006. Total future net cash flow to the
Company from the volumetric production payment deliveries scheduled below is
estimated to be $74.9 million, based on spot market prices in effect at June 30,
1996 ($2.38 per MMBtu and $18.83 per bbl, before adjustments for appropriate
basis differentials and Btu content).
<TABLE>
<CAPTION>
CUMULATIVE
NATURAL GAS OIL TOTAL TOTAL
PERIOD FROM TO (MMCF) (MBBLS) (MMCFE) (MMCFE)
----------- -- ----------- ------- ------- ----------
<S> <C> <C> <C> <C> <C>
July 1, 1996 September 30, 1996.............. 3,102 51 3,405 3,405
October 1, 1996 December 31, 1996............... 2,752 50 3,052 6,457
January 1, 1997 December 31, 1997............... 7,640 205 8,870 15,327
January 1, 1998 December 31, 1998............... 3,907 162 4,876 20,203
January 1, 1999 December 31, 1999............... 1,588 117 2,288 22,491
January 1, 2000 December 31, 2000............... 1,263 86 1,781 24,272
January 1, 2001 December 31, 2006............... 3,538 233 4,938 29,210
</TABLE>
The properties underlying the VPP program are principally located in two
major regions, the offshore Gulf Coast and the northern and southern Niagaran
Reef trend in Michigan.
Offshore Gulf Coast Properties
The Company's offshore Gulf Coast properties are located in six blocks off
the coast of Louisiana and four blocks off the coast of Alabama. The Company's
interests in the Louisiana blocks were all acquired through volumetric
production payment contracts with Hall-Houston Oil Company ("HHOC"), which is
the operator. The Louisiana blocks contain nine wells drilled during 1994, 1995,
and the first half of 1996 that are at depths ranging from 1,700 to 8,000 feet
in the shallow waters of the Gulf of Mexico. Production attributable to HHOC's
working interest during the month of September 1996 averaged 26,776 Mcf per day,
of which an average of 21,956 Mcf per day was delivered to the Company under the
VPP program. Proved reserves attributable to HHOC's interest, which support the
volumetric production payment, were estimated by an independent reserve engineer
to be 16,398 MMcf as of June 30, 1996. Pursuant to the HHOC volumetric
production payment, the Company received deliveries totaling 6,911 MMcf during
1995 and 5,104 MMcf during the six months ended June 30, 1996, was scheduled to
receive deliveries totaling 4,188 MMcf during the balance of 1996, and is
scheduled to receive deliveries totaling 4,788 MMcf in 1997, and 1,684 MMcf in
1998.
The Company's interests in the four offshore Alabama blocks were acquired
through two volumetric production payment agreements with The Offshore Group,
which operates five wells located on these properties. The Company received
deliveries of 260 MMcf in 1994, 552 MMcf in 1995, was scheduled to receive
deliveries totaling 1,287 MMcf during 1996 and is scheduled to receive
deliveries totaling 1,287 MMcf in 1997.
In addition, the Company is scheduled to receive volumes totaling 782 MMcfe
during the period from 1996 to 1998 from several smaller volumetric production
payments covering onshore Gulf Coast and Appalachian properties.
Niagaran Reef Trend Properties in Michigan
The Company's northern and southern Niagaran Reef trend properties, located
in Michigan, were acquired in December 1995. The VPP program reserves are
expected to be produced largely from an existing group of 89 wells located in 49
fields, primarily operated by a subsidiary of Hawkins Oil and Gas, Inc.
("Hawkins"). Additional reserves available to support the production payment may
be derived from a series of recompletions scheduled during 1996 and 1997 and
from certain reserves to be developed by Hawkins in an area of mutual interest
covering the Niagaran Reef trend pursuant to an exploration program with a third
party. The Niagaran Reef reservoirs are typically found at depths between 4,000
and 6,500 feet. Production rates from the property interests supporting the
production payment during
44
<PAGE> 157
September 1996 averaged 5,775 Mcf and 525 bbls per day. The Company estimated at
June 30, 1996 that 17,298 MMcf and 1,101 Mbbls were attributable to Hawkins'
interest in these properties to support the production payment, with
approximately 80% of the reserves attributable to 17 wells. Of the remaining
12,177 MMcf and 0.9 MMbbls to be delivered under the volumetric production
payment, the Company was scheduled to receive 1,117 MMcf and 100 Mbbls during
the last half of 1996, 2,476 MMcf and 205 Mbbls in 1997, with the balance to be
delivered between 1998 and 2006.
Recent Volumetric Production Payment Program Activities
Subsequent to June 30, 1996, KCS entered into four volumetric production
payments to acquire 11,886 MMcf of natural gas and 579 Mbbls of oil for $23.7
million, $8.9 million of which has not yet been paid and is expected to be
funded in the first half of 1997.
OIL AND GAS RESERVES
All information in this Prospectus relating to estimates of the Company's
proved reserves not associated with the VPP program or its working interest
reserves (approximately 1% of total proved reserves) in the Niagaran Reef trend
in Michigan is derived from reports prepared for the Company by Ryder Scott
Company (covering the Medallion Acquisition properties), H.J. Gruy and
Associates, Inc. (the Rocky Mountain properties) and R.A. Lenser and Associates,
Inc. (the onshore Gulf Coast properties), each in accordance with the rules and
regulations of the SEC. These independent reserve engineers' estimates were
based upon a review of production histories and other geologic, economic,
ownership and engineering data provided by the Company or third party operators.
Although reserve engineers' reports with respect to reserves underlying the
Company's VPP program are utilized by the Company to support its own analysis of
such reserves, the proved reserves, related future net revenues and PV-10 that
the Company reports with respect to volumetric production payments are taken
directly from the amounts contracted for pursuant to the agreements relating to
volumetric production payment (which amounts are less than the net interest
production reflected in the independent reserve engineers' reports).
The following table sets forth as of June 30, 1996, both historical and pro
forma (giving effect to the Medallion Acquisition) summary information with
respect to (i) the estimates made by the reserve engineers of the Company's
proved oil and gas reserves attributable to working interests and (ii) the
reserve amounts contracted for pursuant to the agreements relating to the
volumetric production payments. In addition, the table sets forth estimates of
future net revenues from these proved reserves and the present value thereof and
reflects the termination of the Tennessee Gas Contract effective January 1,
1997.
<TABLE>
<CAPTION>
JUNE 30, 1996
----------------------
HISTORICAL PRO FORMA
---------- ---------
<S> <C> <C>
PROVED RESERVES:
Oil (Mbbls)................................................. 7,798 14,595
Natural gas (MMcf).......................................... 120,542 281,873
Total (MMcfe).......................................... 167,330 369,443
Future net revenues ($000).................................. $288,024 $602,375
Present value of future net revenues before income taxes
($000).................................................... $196,826 $408,265
PROVED DEVELOPED RESERVES:
Oil (Mbbls)................................................. 4,377 10,856
Natural gas (MMcf).......................................... 105,709 244,120
Total (MMcfe).......................................... 131,971 309,256
Future net revenues ($000).................................. $234,718 $513,416
Present value of future net revenues before income taxes
($000).................................................... $168,384 $357,987
</TABLE>
45
<PAGE> 158
There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves and in projecting future rates of production and
future amounts and timing of development expenditures, including underground
accumulations of crude oil and gas that cannot be measured in an exact manner,
and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Estimates of proved undeveloped reserves are inherently less certain than
estimates of proved developed reserves. The quantities of oil and gas that are
ultimately recovered, production and operating costs, the amount and timing of
future development expenditures, geologic success and future oil and gas sales
prices may all differ from those assumed in these estimates. In addition, the
Company's reserves may be subject to downward or upward revision based upon
production history, purchases or sales of properties, results of future
development, prevailing oil and gas prices and other factors. Therefore, the
present value shown above should not be construed as the current market value of
the estimated oil and gas reserves attributable to the Company's properties.
In accordance with SEC guidelines, the estimates of future net revenues
from the Company's proved reserves and the present value thereof are made using
oil and gas sales prices in effect as of the dates of such estimates and are
held constant throughout the life of the properties except where such guidelines
permit alternate treatment, including, in the case of natural gas contracts, the
use of fixed and determinable contractual price escalations. The future net
revenues and present value thereof attributable to the Company's proved reserves
in the Bob West Field reflect the contract price to be paid by Tennessee Gas
through the termination of the Tennessee Gas Contract effective January 1, 1997.
See "-- Legal Proceedings -- Tennessee Gas Litigation." As of June 30, 1996,
spot market prices were $2.38 per MMBtu and $18.83 per bbl, before adjustments
for appropriate basis differentials and Btu content. The prices for natural gas
and, to a lesser extent, oil, are subject to substantial seasonal fluctuations,
and prices for each are subject to substantial fluctuations as a result of
numerous other factors. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations."
ACREAGE
The following table sets forth certain information with respect to
developed and undeveloped leased acreage of the Company, of Medallion and on a
pro forma combined basis as of September 30, 1996. The leases in which the
Company has an interest are for varying primary terms, and many require the
payment of delay rentals to continue the primary term. The leases may be
surrendered by the operator at any time by notice to the lessors, by the
cessation of production, fulfillment of commitments, or by failure to make
timely payments of delay rentals. Excluded from the table are the Company's
interests in the properties subject to volumetric production payments. See
"-- Volumetric Production Payment Program and Underlying Principal Properties."
<TABLE>
<CAPTION>
DEVELOPED ACRES UNDEVELOPED ACRES
----------------- -----------------
STATE GROSS NET GROSS NET
----- ------- ------- ------- -------
<S> <C> <C> <C> <C>
Company:
Texas..................................... 49,405 17,904 32,418 18,602
Wyoming................................... 67,574 60,239 77,019 71,304
Montana................................... 64,522 42,002 21,017 16,977
Colorado.................................. 10,990 6,510 -- --
Louisiana................................. 3,209 2,695 36,534 32,097
Other..................................... 1,636 410 5,213 1,303
------- ------- ------- -------
Total............................. 197,336 129,760 172,201 140,283
------- ------- ------- -------
Medallion:
Texas..................................... 73,120 50,597 3,680 1,049
Oklahoma.................................. 44,237 22,768 10,926 7,844
Louisiana................................. 103,804 16,782 4,688 3,756
Other..................................... 99,199 27,139 4,895 4,314
------- ------- ------- -------
Total............................. 320,360 117,286 24,189 16,963
------- ------- ------- -------
Pro Forma Total............................. 517,696 247,046 196,390 157,246
======= ======= ======= =======
</TABLE>
46
<PAGE> 159
TITLE TO OIL AND GAS PROPERTIES
Substantially all of the Company's property interests not the subject of
its VPP program are held pursuant to leases from third parties. A title opinion
is typically obtained prior to acquiring these properties. The Company or the
relevant operator routinely obtained title opinions on substantially all of the
properties that the Company has drilled or participated in drilling. With
respect to acquisitions of proved properties, the Company generally obtains
updated title opinions covering properties constituting at least 80% of the
value of the acquisition, and there are usually older, existing opinions
covering the remaining properties. The Company believes that it has satisfactory
title to its properties in accordance with standards generally accepted in the
oil and gas industry. In addition, the Company's properties are subject to
customary royalty interests, overriding royalty interests, liens for current
taxes, and other burdens that the Company believes do not materially interfere
with the use of or affect the value of such properties.
The Company typically takes the same approach to approving title for
volumetric production payments as it does in drilling its own wells or in
property acquisitions. The operator will generally have a drilling title opinion
or a division order title opinion (on producing wells) for the properties being
conveyed. In most cases, the Company will require that the operator update any
existing title opinions to reflect the current working interest and net revenue
interest subjected to the volumetric production payment conveyed to the Company.
By updating the title, any existing mortgages, liens, lawsuits and potential
encumbrances will be disclosed. Only when the Company believes that it has
satisfactory title to the properties in accordance with generally accepted
industry standards will the Company proceed with a volumetric production
payment.
NATURAL GAS TRANSPORTATION AND MARKETING OPERATIONS
For the nine months ended September 30, 1996, the natural gas
transportation and marketing businesses accounted for approximately 75% of the
Company's revenues and recorded a $0.3 million operating loss.
Natural Gas Transportation
The major asset related to the Company's natural gas transportation
operations is a 150-mile carbon steel intrastate pipeline system and related
gathering facilities located north of Houston, Texas. In addition, the Company
owns more than 300 miles of natural gas gathering lines generally associated
with its wells, which connect producing fields with various natural gas
transmission lines and local distribution companies. Of the 17 gathering
systems, including the Texas system acquired in the Medallion Acquisition, five
are located in the Sweet Grass Arch basin in Montana, eleven are located in
Texas and one is located in Louisiana.
Natural Gas Marketing Operations
The Company's natural gas marketing business currently has offices in
Houston, Texas; Edison, New Jersey; and Pittsburgh, Pennsylvania, and engages in
the direct marketing of natural gas to industrial and commercial end-users.
During 1996, the Company served approximately 300 customers in 34 states and
Canada, bought natural gas from over 160 domestic and Canadian suppliers and
shipped natural gas on over 90 different pipelines.
As part of the Medallion Acquisition, the Company acquired Medallion's
natural gas marketing operations located in Tulsa, Oklahoma. These operations
market Medallion's production, aggregate natural gas volumes from producers and
provide services (including nomination, pipeline balancing, royalty payment
administration, and other accounting and administrative services) to these
producers. As of September 30, 1996, Medallion's natural gas marketing
operations purchased natural gas from over 600 wells located primarily in
Oklahoma and the Texas panhandle. These volumes are aggregated with volumes
purchased from others and resold to natural gas distribution companies,
industrial end-users and other natural gas marketing companies.
47
<PAGE> 160
Marketing of Oil and Gas Production
The Company markets substantially all of the oil and gas production from
Company-operated wells and its volumetric production payment volumes to
pipelines, local distribution companies and third-party natural gas marketers.
The Company believes that its marketing activities add value by giving the
Company opportunities to obtain competitive prices for products, rapidly connect
new wells to pipelines, minimize pipeline and purchaser balancing problems,
maintain continuous sales of production and secure prompt payment.
Substantially all of the Company's natural gas is sold either under
short-term contracts (one year or less) providing for variable or market
sensitive prices or under various long-term contracts providing for fixed prices
which dedicate the natural gas to a single purchaser for an extended period of
time.
Approximately 8% of the Company's total production for the nine months
ended September 30, 1996, after giving effect to the Medallion Acquisition, was
subject to the Tennessee Gas Contract, which was terminated effective January 1,
1997. Average sales prices under the Tennessee Gas Contract, excluding severance
tax reimbursements, were $8.38 per Mcf for the nine months ended September 30,
1996, $7.90 per Mcf for the year ended December 31, 1995, $7.49 per Mcf in 1994,
and $7.09 per Mcf in 1993.
The Company sells its oil production in each of its producing regions
pursuant to contracts based on postings by major purchasers. Historically, the
Company has been able to achieve a premium to these postings, based on oil
quality and transportation differentials.
The price of non-contract natural gas is influenced by supply and demand
factors for natural gas in the United States, Mexico and Canada, as well as
prices of competing fuels. Average oil prices are reflective of the world oil
market during the periods. Market prices for oil and gas, which are volatile in
nature, have a significant impact on the Company's revenue, net income and cash
flow.
In connection with the marketing of its oil and gas production, the Company
engages in oil and gas price risk management activities primarily through the
use of oil and gas futures and options contracts and "fixed for floating" price
swap agreements. The Company utilizes oil and gas futures contracts for the
purpose of hedging the risks associated with fluctuating crude oil and gas
prices and accounts for such contracts in accordance with FASB Statement No. 80,
"Accounting for Futures Contracts." Since these contracts qualify as hedges and
correlate to market price movements of oil and gas, any gains or losses
resulting from market changes will be offset by losses or gains on corresponding
physical transactions. The swap agreements on notional volumes require payments
to (or the receipt of payments from) counterparties to such agreements based on
the differential between a fixed and variable price for the oil or gas. The
Company maintains coverage of such notional volumes with adequate physical
volume deliveries at the hub points used to price such arrangements. The Company
records these transactions under settlement accounting guidelines and,
accordingly, includes gains or losses in oil and gas revenues in the period of
the swapped production. The Company intends to continue to consider various risk
management arrangements to stabilize cash flow and earnings and reduce the
Company's susceptibility to volatility in oil and gas prices.
The Company has three separate natural gas price swaps in place as a result
of the Medallion Acquisition. Effective January 1, 1995, Medallion effectively
fixed the sales price for a portion of its natural gas production at a NYMEX
price of $1.905 per MMBtu for a five-year term. In September 1995, Medallion
effectively fixed the sales price for an additional portion of its natural gas
production at a NYMEX price of $2.055 per MMBtu for ten years. In May 1996,
Medallion effectively fixed the sales price for an additional portion of its
natural gas production at a weighted average NYMEX price of $2.23 per MMBtu for
a one-year term. For the calendar years 1996, 1997 and 1998, these transactions
cover 11.7 million MMBtu, 8.1 million MMBtu and 4.83 million MMBtu of natural
gas, respectively, and result in annual weighted average prices per MMBtu of
$2.0325, $1.9942 and $1.9832, respectively. In May 1996, Medallion also fixed a
basis component of the net wellhead sales price for a portion of its natural gas
production at the NYMEX price less $0.096 per MMBtu for a one-year term.
48
<PAGE> 161
SIGNIFICANT CUSTOMER
One customer, Tennessee Gas, accounted for approximately 78%, 82% and 72%
of the oil and gas exploration and production revenue and 10%, 16% and 14% of
the Company's consolidated revenue for the years ended December 31, 1993, 1994,
and 1995, respectively, and 42% of the oil and gas exploration and production
revenue and 10% of the Company's consolidated revenue for the nine months ended
September 30, 1996. No other single customer accounted for more than 10% of the
Company's consolidated revenue during these periods. Effective January 1, 1997,
the Company's contract with Tennessee Gas was terminated. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- Tennessee Gas Litigation."
REGULATION
General. The Company's business is affected by numerous governmental laws
and regulations, including energy, environmental, conservation, tax and other
laws and regulations relating to the energy industry. For example, state and
federal agencies have issued rules and regulations that require permits for the
drilling of wells, regulate the spacing and drilling of wells, prevent the waste
of oil and gas reserves through proration, and regulate oilfield and pipeline
environmental and safety matters. Changes in any of these laws and regulations
could have a material adverse effect on the Company's business. In view of the
many uncertainties with respect to current and future laws and regulations,
including their applicability to the Company, the Company cannot predict the
overall effect of such laws and regulations on its future operations.
The Company believes that its operations comply in all material respects
with all applicable laws and regulations and that the existence and enforcement
of such laws and regulations have no more restrictive effect on the Company's
method of operations than on other similar companies in the energy industry.
The following discussion contains summaries of certain laws and regulations
and is qualified in its entirety by the foregoing.
Regulation of the Sale and Transportation of Oil and Gas. Various aspects
of the Company's oil and gas operations are regulated by agencies of the federal
government. The FERC regulates the transportation of natural gas in interstate
commerce pursuant to the Natural Gas Act of 1938 (the "NGA") and the Natural Gas
Policy Act of 1978 (the "NGPA"). In the past, the federal government had
regulated the prices at which the Company's produced oil and gas could be sold.
Currently, "first sales" of natural gas by producers and marketers, and all
sales of crude oil, condensate and natural gas liquids, can be made at
uncontrolled market prices, but Congress could reenact price controls at any
time.
Deregulation of wellhead and other sales in the natural gas industry began
with the enactment of the NGPA in 1978. In 1989, Congress enacted the Natural
Gas Wellhead Decontrol Act which removed all NGA and NGPA price and nonprice
controls affecting wellhead sales of natural gas effective January 1, 1993. In
late 1992, the FERC issued its Order No. 547 which granted automatic and
flexible blanket certificate authority to all persons engaging in "sales for
resale" in interstate commerce which would otherwise be regulated as
jurisdictional sales under the NGA. Due to FERC's elimination in July 1994 of
certain regulations deemed to be unnecessary due to enactment of the Decontrol
Act, a portion of the Company's current natural gas sales to resellers that do
not qualify as "first sales" and involve natural gas which is not produced by
the Company are made pursuant to the blanket authority granted by Order No. 547.
Although the Company believes it unlikely that FERC will materially revise or
withdraw the blanket authority issued by Order No. 547, certain resales by the
Company could in the future be subject to greater federal oversight, including
the possibility that the FERC could prospectively impose more restrictive
conditions on such sales. In that event, the Company does not believe it would
be affected differently than other natural gas industry participants engaging in
interstate resales.
Commencing in April 1992, the FERC issued its Order No. 636 and related
clarifying orders ("Order No. 636"), which, among other things, purported to
restructure the interstate natural gas industry and to require interstate
pipelines to provide transportation services separate, or "unbundled," from the
49
<PAGE> 162
pipelines' sales of natural gas. Order No. 636 also required pipelines to
provide "open-access" transportation on a nondiscriminatory basis for all
natural gas shippers. Order No. 636 was implemented on a pipeline-by-pipeline
basis, principally through negotiated settlements in individual pipeline service
restructuring proceedings. In many instances, the interstate pipelines
themselves are no longer wholesalers or merchants of natural gas, but instead
provide only natural gas storage and transportation services. Order No. 636 and
certain related proceedings were the subject of an appeal to the United States
Court of Appeals for the District of Columbia Circuit. That court recently
issued its decision in the appeal of Order No. 636 and largely upheld the
fundamental tenets of the order. However, the court's decision is still subject
to further action, including potential applications for a writ of certiorari to
the United States Supreme Court. In addition, several appeals in individual
pipeline proceedings and related dockets remain pending. It is therefore not
possible for the Company to predict what effect, if any, the ultimate outcome of
these regulatory and judicial review proceedings will have on FERC's open-access
regulations or the Company's operations.
Although Order No. 636 does not directly regulate the Company's production
activities, the FERC has stated that it intends Order No. 636 to foster
increased competition within all phases of the natural gas industry. It is
unclear what impact, if any, increased competition within the natural gas
industry under Order No. 636 will have on the Company's activities. Although
Order No. 636, assuming it is upheld in its entirety, could provide the Company
with better access to markets and the ability to utilize new types of
transportation services, it could also subject the Company to more restrictive
pipeline imbalance tolerances and greater penalties for violation of those
tolerances. The Company believes that Order No. 636 has not had any significant
impact on the Company as a producer or on the Company's natural gas marketing
efforts.
The FERC has announced its intention to reexamine or revise certain of its
transportation-related policies, including the appropriate manner for setting
rates for new interstate pipeline construction, the manner in which interstate
pipeline shippers may release interstate pipeline capacity under Order No. 636
for resale in secondary markets, and the use of market-based rates for
interstate natural gas transmission services. In January 1996, the FERC issued a
statement of policy and request for comments concerning alternatives to its
traditional cost-of-service ratemaking methodology and set forth the criteria
that the FERC will use to evaluate proposals to charge market-based rates for
the transportation of natural gas. The FERC also requested comments on whether
it should allow pipelines the flexibility to negotiate the terms and conditions
of transportation service with prospective shippers. In another rulemaking, the
FERC is considering how to alter its regulations to promote the fair and
effective release and recontracting of pipeline capacity from one shipper to
another, and to what extent such transactions should be regulated where the
market is demonstrably competitive. While any resulting FERC action on the above
matters would affect the Company only indirectly, these inquiries are intended
to further enhance competition in natural gas markets.
The FERC has also issued various orders and policy statements which are
intended to foster competitive markets for natural gas by giving natural gas
purchasers access to multiple supply sources at market-driven prices. The FERC's
current rules and policy statements may also have the effect of enhancing
competition in natural gas markets by, among other things, facilitating
construction of natural gas supply laterals and encouraging non-producer natural
gas marketers to engage in certain purchase and sale transactions. The Company
cannot accurately predict whether the FERC's actions will achieve the goal of
increasing competition in markets in which the Company's natural gas is sold.
The FERC has also recently issued numerous orders confirming the sale and
abandonment of natural gas gathering facilities previously owned by interstate
pipelines and acknowledging that if the FERC does not have jurisdiction over
services provided thereon, then such facilities and services may be subject to
regulation by state authorities in accordance with state law. A number of states
have either enacted new laws or are considering inadequacy of existing laws
affecting gathering rates and/or services. Thus, natural gas gathering may
receive greater regulatory scrutiny by state agencies in the future. The
Company's gathering operations could be adversely affected should they be
subject in the future to increased state regulation of rates or services,
although the Company does not believe that it would be
50
<PAGE> 163
affected by such regulation any differently than other natural gas producers or
gatherers. In addition, FERC's approval of transfers of previously-regulated
gathering systems to independent or pipeline-affiliated gathering companies that
are not subject to FERC regulation may affect competition for gathering or
natural gas marketing services in areas served by those systems and thus may
affect both the costs and the nature of gathering services that will be
available to interested producers or shippers in the future. The effects, if
any, of FERC's gathering policies on the Company's operations are uncertain.
The Company's natural gas transportation and gathering operations are
generally subject to safety and operational regulations relating to the design,
installation, testing, construction, operation, replacement and management of
facilities and to state regulation of the rates of such service. To a more
limited degree, a portion of the Company's transportation services may be
subject to FERC oversight in accordance with the provisions of the NGPA.
Pipeline safety issues have recently become the subject of increasing focus in
various political and administrative arenas at both the state and federal
levels. At the federal level, in October 1996, the President signed the
Accountable Pipeline Safety and Partnership Act of 1996, which, among other
things, gives the public an opportunity to comment on pipeline risk management
programs, promotes communication regarding safety issues to residents along
pipeline right-of-ways, and encourages the examination of remote control valves
along pipelines. The Company believes its operations, to the extent they may be
subject to current natural gas pipeline safety requirements, comply in all
material respects with such requirements. The Company cannot predict what
effect, if any, the adoption of additional pipeline safety legislation might
have on its operations, but the natural gas industry could be required to incur
additional capital expenditures and increased costs depending upon future
legislative and regulatory changes.
Sales of crude oil, condensate and natural gas liquids by the Company are
not regulated and are made at market prices. The price the Company receives from
the sale of these products is affected by the cost of transporting the products
to market. Effective as of January 1, 1995, the FERC implemented regulations
establishing an indexing system for transportation rates for oil pipelines,
which would generally index such rates to inflation, subject to certain
conditions and limitations. These regulations are subject to pending petitions
for judicial review. The Company is not able to predict with certainty what
effect, if any, these regulations will have on it, but other factors being
equal, the regulations may tend to increase transportation costs or reduce
wellhead prices under certain conditions.
The Company also operates federal oil and gas leases, which are subject to
the regulation of the United States Minerals Management Service ("MMS"). MMS
recently issued a notice of proposed rulemaking in which it proposed to amend
its regulations governing the calculation of royalties and the valuation of
natural gas produced from federal leases. The principle feature in the
amendments, as proposed, would establish an alternative market-index based
method to calculate royalties on certain natural gas production sold to
affiliates or pursuant to non-arm's-length sales contracts. The MMS proposed
this rulemaking to facilitate royalty valuation in light of changes in the gas
marketing environment. The Company cannot predict at this stage what action the
MMS will take on these matters, nor can it predict at this stage of the
rulemaking proceeding how the Company might be affected by amendments to the
regulations.
Additional MMS proposals and proceedings that might affect the oil and gas
industry are pending before Congress, the FERC and the courts. The Company
cannot predict when or whether any such proposals may become effective. In the
past, the natural gas industry historically has been very heavily regulated.
There is no assurance that the current regulatory approach pursued by the FERC
will continue indefinitely into the future. Notwithstanding the foregoing, it is
not anticipated that compliance with existing federal, state and local laws,
rules and regulations will have a material or significantly adverse effect upon
the capital expenditures, earnings or competitive position of the Company.
Taxation. The operations of the Company, as is the case in the energy
industry generally, are significantly affected by federal tax laws, including
the Tax Reform Act of 1986. In addition, federal as well as state tax laws have
many provisions applicable to corporations in general which could affect the
potential tax liability of the Company.
51
<PAGE> 164
Operating Hazards and Environmental Matters. The oil and gas business
involves a variety of operating risks, including the risk of fire, explosions,
blow-outs, pipe failure, casing collapse, abnormally pressured formations and
environmental hazards such as oil spills, natural gas leaks, ruptures and
discharge of toxic gases, the occurrence of any of which could result in
substantial losses to the Company due to injury or loss of life, severe damage
to or destruction of property, natural resources and equipment, pollution or
other environmental damage, clean-up responsibilities, regulatory investigation
and penalties and suspension of operations. Such hazards may hinder or delay
drilling, development and on-line production operations.
Extensive federal, state and local laws and regulations govern oil and gas
operations regulating the discharge of materials into the environment or
otherwise relating to the protection of the environment. These laws and
regulations may require the acquisition of a permit before drilling commences,
restrict or prohibit the types, quantities and concentration of substances that
can be released into the environment or wastes that can be disposed of in
connection with drilling and production activities, prohibit drilling activities
on certain lands lying within wetlands or other protected areas and impose
substantial liabilities for pollution or releases of hazardous substances
resulting from drilling and production operations. Moreover, state and federal
environmental laws and regulations may become more stringent.
The Company owns, leases, or operates properties that have been used for
the exploration and production of oil and gas, and owns and operates a natural
gas pipeline and natural gas gathering systems. Hydrocarbons, mercury,
polychlorinated biphenyls ("PCBs") or other wastes may have been disposed of or
released on or under the properties owned, leased, or operated by the Company or
on or under other locations where such wastes have been or are taken for
disposal, although the Company has no knowledge of any such occurrences. The
Company's properties and any wastes that may have been disposed thereon may be
subject to federal or state environmental laws that could require the Company to
remove the wastes or remediate any contamination identified on the Company's
properties.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the original conduct, on certain classes of persons who are
considered to be responsible for the release of a "hazardous substance" into the
environment. These persons include the owner or operator of the disposal site or
sites where the release occurred and companies that disposed or arranged for the
disposal of the hazardous substances. Under CERCLA, such persons may be subject
to joint and several liability for the costs of cleaning up the hazardous
substances that have been released into the environment, for damages to natural
resources and for the costs of certain health studies, and it is not uncommon
for neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the release of hazardous
substances.
In addition, the U.S. Oil Pollution Act ("OPA") requires owners and
operators of facilities that could be the source of an oil spill into "waters of
the United States" (a term defined to include rivers, creeks, wetlands, and
coastal waters) to adopt and implement plans and procedures to prevent any spill
of oil into any waters of the United States. OPA also requires affected facility
owners and operators to demonstrate that they have at least $35 million in
financial resources to pay for the costs of cleaning up an oil spill and
compensating any parties damaged by an oil spill. Substantial civil and criminal
fines and penalties can be imposed for violations of OPA and other environmental
statutes.
In addition, the disposal of wastes containing naturally occurring
radioactive material which are commonly generated during oil and gas production
are 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.
52
<PAGE> 165
LEGAL PROCEEDINGS
Tennessee Gas Litigation
In April 1996, the Texas Supreme Court withdrew its previous opinion and
issued its final opinion with respect to the take-or-pay pricing and quantity
provisions of the Tennessee Gas Contract litigation and affirmed the Company's
position on all issues, including those involving both the volume and price
provisions of the contract. In August 1996, the Texas Supreme Court denied
Tennessee Gas' petition for a rehearing and on September 30, 1996, the Company
finally concluded these aspects of the litigation that had been ongoing since
1990 and received approximately $70 million from Tennessee Gas, representing the
Tennessee Gas Receivable at that date.
On December 23, 1996, the Company and Tennessee Gas entered into a
settlement covering all claims and litigation between them and agreed to
terminate the Tennessee Gas Contract effective January 1, 1997, approximately
two years prior to its expiration date. In the settlement, the parties agreed to
the dismissal of all of their respective claims concerning disputes with respect
to the obligations of the parties under the Tennessee Gas Contract. Included in
the settlement is the disposition of the lawsuit related to the November 1996
verdict of a jury in a trial in the District Court of Zapata County, Texas, in
which the jury awarded Tennessee Gas $143.2 million including approximately $114
million for punitive damages. The December 1996 settlement did not affect the
April 1996 decision of the Texas Supreme Court or the Company's prior recovery
of the Tennessee Gas Receivable. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and Note 7 to the Consolidated
Financial Statements.
Other Legal Proceedings
The Company is also a party to three lawsuits involving the holders of
royalty interests on the acreage that was covered by the Tennessee Gas Contract.
The Company is a co-plaintiff in the first of these lawsuits that was filed in
Dallas County, Texas, and is a defendant in the other subsequently filed suits
in Zapata County, Texas. The basis of these declaratory judgment actions is the
royalty holders' claim that their royalty payments should be based on the price
paid by Tennessee Gas for the natural gas purchased by it under the Tennessee
Gas Contract. The Company has been paying royalties for this natural gas based
upon the spot market price. Because the leases have market-value royalty
provisions, the Company believes it is in full compliance under the leases with
its royalty holders, and its position has been confirmed in the Dallas suit
where the trial judge has granted the co-plaintiffs' motions for summary
judgment on this issue. In addition, the trial judge has granted summary
judgment against the royalty owners with respect to their various counterclaims
against the co-plaintiffs as concerns the jointly-owned Guerra "A" and Guerra
"B" units. However, the royalty owners also separately counterclaimed against
the Company with respect to the Jesus Yzaguirre unit, alleging that the largest
lease contained therein had terminated in December 1975 and that certain of the
royalty owners were entitled to royalties based upon the Tennessee Gas Contract
price because of their execution of certain division orders in 1992 that
allegedly varied the market-value royalty provision of their lease. The trial
judge has not yet ruled on the parties' respective motions for summary judgment
concerning these issues, although he has granted the Company's motion for
summary judgment that the royalty holders' leases require that royalties be
based upon the market value of the natural gas at the lease when produced and
sold, not the price paid for the natural gas under the Tennessee Gas Contract.
While the Company believes its defenses are meritorious and that it should
prevail in the pending litigation, there can be no assurance as to the ultimate
outcome of these matters, which the royalty owners have indicated will be
appealed in due course to the Fifth District Court of Appeals in Dallas, Texas.
The Company and Medallion are also parties to various other lawsuits and
governmental proceedings, all arising in the ordinary course of business.
Although the outcome of these lawsuits cannot be predicted with certainty, the
Company and Medallion do not expect such matters to have a material adverse
effect, either singly or in the aggregate, on the financial position of the
Company.
53
<PAGE> 166
MANAGEMENT
EXECUTIVE OFFICERS, DIRECTORS AND CERTAIN KEY EMPLOYEES
The following table sets forth the name, age and present position with the
Company of each of the Company's executive officers, directors and certain other
key employees.
<TABLE>
<CAPTION>
NAME AGE POSITION WITH THE COMPANY
---- --- -------------------------
<S> <C> <C>
James W. Christmas................... 48 President, Chief Executive Officer and Director
C.R. Devine.......................... 50 Vice President, Oil and Gas Operations; President, KCS
Resources, Inc.
Henry A. Jurand...................... 47 Vice President, Chief Financial Officer and Secretary
Harry Lee Stout...................... 49 President, KCS Energy Marketing, Inc.; President, KCS
Pipeline Systems, Inc.; President, KCS Michigan
Resources, Inc.; President, KCS Energy Services, Inc.
William E. Warnock, Jr............... 43 President, KCS Medallion Resources, Inc., President,
GED Energy Services, Inc., and Vice Chairman, Medallion
Gas Services, Inc.
G. Stanton Geary..................... 62 Director
Stewart B. Kean...................... 62 Director and Chairman of the Board
James E. Murphy, Jr.................. 40 Director
Robert G. Raynolds................... 44 Director
Joel D. Siegel....................... 55 Director
Christopher A. Viggiano.............. 43 Director
</TABLE>
James W. Christmas has served as President and Chief Executive Officer and
as a director of the Company since 1988. Prior to joining the Company, Mr.
Christmas spent ten years with NUI Corporation, serving in a variety of officer
capacities and as President of several of its subsidiaries. While Mr. Christmas
was Vice President of Planning of NUI Corporation, he was in charge of the
spin-off of its non-regulated businesses that resulted in the formation of KCS
Energy, Inc. Mr. Christmas began his career with Arthur Andersen & Co.
C. R. Devine was named Vice President, Oil and Gas Operations of the
Company in December 1992 and President of KCS Resources, Inc., a subsidiary of
the Company engaged in oil and gas exploration and production, in December 1993.
He has served as principal operating officer of the Company's oil and gas
operations since 1988. He has been employed by the Company and its predecessor
companies since 1974.
Henry A. Jurand was appointed Chief Financial Officer on January 1, 1996.
He has served as Vice President of the Company since September 1990, as
Treasurer from March 1991 to December 1995, and as Secretary since February
1992. From 1988 to 1990, he was a Senior Vice President of Private Capital
Partners, Inc., in New York City. From 1977 to 1988, he was employed by
Baltimore Gas and Electric Company, holding management positions including Vice
President and Chief Financial Officer of Constellation Holdings, Inc., a
subsidiary, and President, Constellation Investments, Inc.
Harry Lee Stout has served as President of KCS Energy Marketing, Inc. and
KCS Pipeline Systems, Inc., the subsidiaries of the Company engaged in natural
gas marketing and transportation, since joining the Company in August 1991. In
October 1995, he was named President of KCS Michigan Resources, Inc. and in
September 1996, he was named President, KCS Energy Services, Inc. From 1990 to
1991, he was Vice President of Minerex Corporation in Houston, Texas. From 1978
to 1990, he was employed by Enron Corp. of Houston, Texas, holding various
management positions including Senior Vice President of Houston Pipe Line
Company and Executive Vice President, Enron Gas Marketing Company, both of which
are subsidiaries of Enron Corp.
54
<PAGE> 167
William E. Warnock, Jr. was named President, KCS Medallion Resources, Inc.
(formerly InterCoast Oil and Gas Company) President, GED Energy Services, Inc.,
and Vice Chairman, Medallion Gas Services, Inc. effective with the consummation
of the Medallion Acquisition. Mr. Warnock joined InterCoast in 1992 as its
President and Chief Operating Officer. Prior to joining InterCoast, he
co-founded Medallion Petroleum, Inc. in 1985 and served as its President.
G. Stanton Geary has served as a director of the Company since 1988. He is
proprietor of Gemini Associates, Pomfret, Connecticut, a venture capital
consulting firm, and business manager of the Rectory School, Pomfret,
Connecticut.
Stewart B. Kean has served as Chairman of the Board of Directors of the
Company since 1988. He was President of Utility Propane Company, a former
subsidiary of the Company, from 1965 to 1989. He is past President of the
National LP Gas Association and past President of the World LP Gas Forum. He
currently serves as a member of the Council of the World LP Gas Forum. Mr. Kean
is Robert G. Raynolds' uncle.
James E. Murphy, Jr. has served as a director of the Company since 1988.
Mr. Murphy heads his own political and governmental relations consulting firm
offering strategic planning and management consulting services to Republican
candidates nationwide, with extensive experience at the presidential, state and
congressional levels. Based in Gaithersburg, Maryland, he also advises
corporations and industry groups on strategic planning, governmental relations
and grassroots lobbying projects.
Robert G. Raynolds has served as a director of the Company since August
1995. He has been an independent consulting geologist for several major and
independent oil and gas companies from 1992 until the present and was a
geologist with Amoco Production Company from 1983 until 1992. Mr. Raynolds is
Stewart B. Kean's nephew.
Joel D. Siegel has served as a director of the Company since 1988. He is an
attorney-at-law and has been President of the law firm, Orloff, Lowenbach,
Stifelman & Siegel, P.A. of Roseland, New Jersey, since 1975. Orloff, Lowenbach,
Stifelman & Siegel, P.A. serves as outside legal counsel to the Company. Mr.
Siegel served as President and Chief Executive Officer of Constellation Bancorp,
Elizabeth, New Jersey, and Constellation Bank, Elizabeth, New Jersey, for the
period April 26, 1991 to December 6, 1991.
Christopher A. Viggiano has served as a director of the Company since 1988.
Mr. Viggiano has been President, Chairman of the Board and majority owner of
O'Bryan Glass Corp., Queens, New York, since December 1, 1991, and served as
Vice President and a member of the board of directors of O'Bryan Glass Corp.
from 1985 to December 1, 1991. He is a Certified Public Accountant.
55
<PAGE> 168
SECURITY OWNERSHIP BY CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
As of December 31, 1996, there were 11,587,422 shares of the Company's
Common Stock outstanding. These shares were held by 1,184 holders of record. The
following table sets forth information as to the number and percentage of shares
owned beneficially as of December 31, 1996 by each executive officer and
director of the Company, by all executive officers and directors as a group and
by each person known by the Company to be a beneficial owner of more than 5% of
the Company's Common Stock. For the purpose of the following table, a beneficial
owner of a security includes any person who, directly or indirectly, has or
shares voting power and/or investment power with respect to such security.
<TABLE>
<CAPTION>
SHARES OWNED PERCENT
BENEFICIALLY(1) OF CLASS
--------------- --------
<S> <C> <C>
James W. Christmas.......................................... 511,175(2)(3) 4.3%
C. R. Devine................................................ 91,804(2) *
Henry A. Jurand............................................. 43,032(2) *
Harry Lee Stout............................................. 36,238(2) *
William E. Warnock, Jr...................................... -- --
G. Stanton Geary............................................ 7,062(2) *
Stewart B. Kean............................................. 1,379,650(2)(4) 11.9%
James E. Murphy, Jr......................................... 14,177(2) *
Robert G. Raynolds.......................................... 1,963(2) *
Joel D. Siegel.............................................. 91,429(2)(5) *
Christopher A. Viggiano..................................... 27,829(2) *
Executive officers and directors as a group (11 persons).... 2,204,359(2) 18.5%
Metropolitan Life Insurance Company(6)...................... 1,302,500 11.2%
One Madison Avenue
New York, New York 10010
</TABLE>
- ---------------
* Less than 1%
(1) Unless otherwise indicated, beneficial owner has sole voting and investment
power.
(2) Includes shares that (i) may be purchased as a result of options granted
that are exercisable within 60 days of 260,000, 31,950, 25,850 and 22,500
for Messrs. Christmas, Devine, Jurand and Stout, respectively, 3,000 each
for Messrs. Geary, S.B. Kean, Murphy, Siegel and Viggiano and 1,000 for Mr.
Raynolds and (ii) are allocated to the beneficial owner's account under
401(k) plans.
(3) Includes 18,000 shares held in trusts established for the benefit of Mr.
Christmas' children, the beneficial ownership of which is disclaimed by Mr.
Christmas.
(4) Includes the following shares as to which Mr. Kean shares voting and
investment power: 413,812 shares held by Stewart B. Kean, John Kean and May
Raynolds as the three co-trustees under certain family trusts; 58,392 shares
held by Stewart B. Kean and John Kean as the two co-trustees under certain
family trusts; 40,620 shares held by Stewart B. Kean and John Kean, Jr. as
the two co-trustees under certain family trusts.
(5) Includes 8,000 shares held in trusts established for the benefit of Mr.
Siegel's children, the beneficial ownership of which is disclaimed by Mr.
Siegel.
(6) Includes 1,290,800 shares (or 11.1%) owned by an affiliate of Metropolitan
Life Insurance Company, State Street Research and Management Company, One
Financial Center, 30th Floor, Boston, Massachusetts 02111.
In December 1994, the Board of Directors adopted a policy requiring minimum
levels of ownership of the Company's Common Stock by its directors and by
executive officers of the Company and its subsidiaries. Within a four-year
period, directors are required to become beneficial owners of Common Stock with
a market value equivalent to four times their annual retainer. During such
period, the president
56
<PAGE> 169
and chief executive officer must become the owner of Common Stock with a market
value of four times his annual base salary. For vice presidents of the Company
and presidents of subsidiaries, the multiple of annual base salary is two and
one-half times and for vice presidents of subsidiaries it is one-half.
DESCRIPTION OF CAPITAL STOCK
The following summary of the Company's capital stock is qualified in its
entirety by reference to the Company's Certificate of Incorporation and Bylaws,
each of which is incorporated by reference into this Prospectus. See
"Incorporation of Certain Documents by Reference."
COMMON STOCK
The Company is authorized to issue 50,000,000 shares of Common Stock, $.01
par value per share. Following the Offerings, 14,587,422 shares of Common Stock
will be outstanding. In addition, the Company has granted options to purchase up
to 529,575 shares of Common Stock at an average exercise price of $10.91 per
share and has granted warrants to purchase up to 435,000 shares of Common Stock
at $45.00 per share in connection with the Medallion Acquisition. See
"Capitalization." Holders of Common Stock are entitled to one vote per share on
all matters on which the holders of Common Stock are entitled to vote. Because
holders of Common Stock do not have cumulative voting rights, holders of a
majority of the shares voting for the election of directors can elect all of the
members of the Board of Directors. A majority vote is also sufficient for other
actions that require the vote or concurrence of stockholders. The Common Stock
is not redeemable and has no conversion or preemptive rights. All of the
outstanding shares of Common Stock are, and all of the shares sold in this
offering will be, when issued and paid for, fully paid and non-assessable. In
the event of the liquidation or dissolution of the Company, subject to the
rights of the holders of any outstanding shares of the Company's Preferred
Stock, the holders of Common Stock are entitled to share pro rata in any balance
of the corporate assets available for distribution to them. The Company may pay
dividends if, when and as declared by the Board of Directors from funds legally
available therefor. Under the terms of the Indenture and Bank Credit Facilities,
however, the payment of dividends is limited to 50% of the Company's
consolidated net income commencing October 1, 1995. See "Dividend Policy."
PREFERRED STOCK
The Company is authorized to issue up to 5,000,000 shares of Preferred
Stock, $.01 par value per share. No shares of Preferred Stock are currently
outstanding. The Company's Board of Directors is authorized to issue the
Preferred Stock in series and, with respect to each series, to determine the
number of shares in any such series, and fix the designations, preferences,
qualifications, limitations, restrictions and special or relative rights of
shares of any series of Preferred Stock. The Board of Directors could, without
stockholder approval, issue Preferred Stock with voting rights and other rights
that could adversely affect the voting power of holders of Common Stock and
could be used to prevent a third party from acquiring control of the Company.
The Company has no present plans to issue any shares of Preferred Stock.
SPECIAL PROVISIONS OF THE CERTIFICATE OF INCORPORATION AND DELAWARE LAW
Limitation of Director Liability. Section 102(b)(7) of the Delaware General
Corporation Law ("Section 102(b)") authorizes corporations to limit or to
eliminate the personal liability of directors to corporations and their
stockholders for monetary damages for breach of directors' fiduciary duty of
care. Although Section 102(b) does not change directors' duty of care, it
enables corporations to limit available relief to equitable remedies such as
injunction or rescission. The Certificate of Incorporation limits the liability
of directors to the Company or its stockholders to the full extent permitted by
Section 102(b). Specifically, directors of the Company will not be personally
liable for monetary damages for breach of a director's fiduciary duty as a
director, except for liability: (i) for any breach of the director's duty of
loyalty to the Company or its stockholders, (ii) for acts or omissions not in
good faith or
57
<PAGE> 170
that involve intentional misconduct or a knowing violation of law, (iii) for
unlawful payments of dividends or unlawful stock repurchases or redemptions as
provided in Section 174 of the Delaware General Corporation Law, or (iv) for any
transaction from which the director derived an improper personal benefit.
Indemnification. To the maximum extent permitted by law, the Bylaws provide
for mandatory indemnification of directors and officers of the Company against
all expense, liability and loss to which they may become subject, or which they
may incur as a result of being or having been a director or officer of the
Company. In addition, the Company must advance or reimburse directors and
officers for expenses incurred by them in connection with indemnification
claims.
Delaware Anti-Takeover Law. Section 203 of the Delaware General Corporation
Law ("Section 203") generally provides that a person who, together with
affiliates and associates owns, or within three years did own, at least 15% but
less than 85% of the outstanding voting stock of a corporation subject to the
statute (an "Interested Stockholder") may not engage in certain business
combinations with the corporation for a period of three years after the date on
which the person became an Interested Stockholder unless (i) prior to such date,
the corporation's board of directors approved either the business combination or
the transaction in which the stockholder became an Interested Stockholder or
(ii) subsequent to such date, the business combination is approved by the
corporation's board of directors and authorized at a stockholders' meeting by a
vote of at least two-thirds of the corporation's outstanding voting stock not
owned by the Interested Stockholder. Section 203 defines the term "business
combination" to encompass a wide variety of transactions with or caused by an
Interested Stockholder, including mergers, asset sales, and other transactions
in which the Interested Stockholder receives or could receive a benefit on other
than a pro rata basis with other stockholders.
The provisions of Section 203, combined with the staggered election of
directors and the Board's authority to issue Preferred Stock without further
stockholder action, could delay or frustrate the removal of incumbent directors
or a change in control of the Company. The provisions also could discourage,
impede or prevent a merger, tender offer or proxy contest, even if such event
would be favorable to the interests of stockholders. The Company's stockholders,
by adopting an amendment to the Certificate of Incorporation, may elect not to
be governed by Section 203 which election would be effective 12 months after
such adoption. Neither the Certificate of Incorporation nor the Bylaws exclude
the Company from the restrictions imposed by Section 203.
REGISTRATION RIGHTS
The warrants to acquire 435,000 shares of Common Stock from the Company at
a price of $45.00 per share issued to MidAmerican Capital Company ("MidAmerican
Capital") in connection with the Medallion Acquisition carry certain rights with
respect to registration under the Securities Act of the shares of Common Stock
underlying such warrants. In general, MidAmerican Capital has one "demand"
registration under which the Company will be obligated to file, and use its best
efforts to cause to be declared effective, a registration statement with respect
to the resale by MidAmerican of shares of Common Stock acquired pursuant to the
warrants. In addition, MidAmerican Capital has rights to two "piggyback"
registrations in the event the Company proposes to register with the SEC an
underwritten public sale of any shares of Common Stock. These rights expire at
such time as MidAmerican Capital is able to sell its shares of Common Stock
without restriction under the Securities Act and are subject to certain
conditions and limitations, including the right of the underwriters of an
offering to limit the number of shares Medallion may include in a registration
pursuant to its piggyback rights. The Company is obligated to bear all expenses
in connection with the registration, except underwriting discount and
commissions with respect to the Common Stock being registered.
TRANSFER AGENT
The Company's transfer agent and registrar for the Common Stock is
Registrar and Transfer Company, Cranford, New Jersey.
58
<PAGE> 171
CERTAIN UNITED STATES TAX CONSEQUENCES TO
NON-UNITED STATES HOLDERS
The following is a discussion of certain anticipated United States income
and estate tax consequences of the ownership and disposition of the Common Stock
by a "Non-United States Holder." For the purpose of this discussion, a
"Non-United States Holder" is any person or entity that is, as to the United
States, a foreign corporation, a non-resident alien individual, a foreign
partnership or a non-resident fiduciary of a foreign estate or trust as such
terms are defined in the Code. This discussion does not deal with all aspects of
United States income and estate taxation and does not address foreign, state and
local tax consequences that may be relevant to Non-United States Holders in
light of their personal circumstances. Furthermore, the following discussion is
based on current provisions of the Code and administrative and judicial
interpretations as of the date hereof, all of which are subject to change.
Prospective foreign investors are urged to consult their tax advisors regarding
the United States federal, state, local and non-United States income and other
tax consequences of owning and disposing of Common Stock.
DIVIDENDS
Generally, any dividend paid to a Non-United States Holder of Common Stock
will be subject to United States withholding tax either at a rate of 30% of the
gross amount of the dividend or at a lesser applicable treaty rate. Under
current United States Treasury regulations, dividends paid to an address in a
country other than the United States are presumed to be paid to a resident of
such country for purposes of the withholding discussed above (unless the payor
had knowledge to the contrary) and, under the current interpretation of United
States Treasury regulations, for purposes of determining the applicability of a
tax treaty rate. However, under proposed United States Treasury regulations not
currently in effect, a Non-United States Holder of Common Stock who wishes to
claim the benefit of an applicable treaty rate would be required to satisfy
applicable certification and other requirements. Dividends received by a Non-
United States Holder that are effectively connected with a United States trade
or business conducted by such Non-United States Holder are exempt from such
withholding tax. However, such effectively connected dividends, net of certain
deductions and credits, are taxed at the same graduated rates applicable to
United States persons. A Non-United States Holder may claim exemption from
withholding under the effectively connected income exception by filing Form 4224
(Statement Claiming Exemption from Withholding of Tax on Income Effectively
Connected With the Conduct of Business in the United States) with the Company or
its paying agent.
In addition to the graduated tax described above, dividends received by a
corporate Non-United States Holder that are effectively connected with a United
States trade or business of the corporate Non-United States Holder may also be
subject to a branch profits tax at a rate of 30% or at a lesser applicable
treaty rate.
DISPOSITION OF COMMON STOCK
A Non-United States Holder generally will not be subject to United States
federal income tax on any gain realized upon the sale or other disposition of
Common Stock, provided that the Common Stock is and continues to be "regularly
traded on an established securities market" for tax purposes, unless (i) such
gain is effectively connected with a United States trade or business of the
Non-United States Holder, (ii) in the case of certain Non-United States Holders
who are non-resident alien individuals and hold the Common Stock as a capital
asset, such individuals are present in the United States for 183 or more days in
the taxable year of disposition and certain other conditions are met, or (iii)
the Non-United States Holder held, directly or indirectly, at any time, during
the five-year period ending on the date of disposition, more than 5% of the
outstanding Common Stock. Although the Company believes that the Common Stock
will be treated as "regularly traded on an established securities market," if
the Common Stock were not so treated, on a sale or other disposition of such
stock, the transferee of such stock would generally be required to withhold 10%
of the proceeds of such disposition. If a Non-United States Holder fails under
clause (i) or (iii) above, the holder will be taxed on the net gain derived from
the sale under
59
<PAGE> 172
regular graduated United States federal income tax rates (and, with respect to
corporate Non-United States Holders, may also be subject to the branch profits
tax described above). If an individual Non-United States Holder fails under
clause (ii) above, the holder generally will be subject to a 30% tax on the gain
derived from the sale, which gain may be offset by U.S. capital losses
recognized within the same taxable year of such sale.
BACKUP WITHHOLDING AND INFORMATION REPORTING
Generally, the Company must report to the U.S. Internal Revenue Service the
amount of dividends paid, the name and address of the recipient, and the amount,
if any, of tax withheld. A similar report is sent to the holder. Pursuant to tax
treaties or other agreements, the U.S. Internal Revenue Service may make its
reports available to tax authorities in the recipient's country of residence.
Dividends paid to a Non-United States Holder at an address within the
United States may be subject to backup withholding at a rate of 31% if the
Non-United States Holder fails to establish that it is entitled to an exemption
or to provide a correct taxpayer identification number and other information to
the payor.
The payment of the proceeds of the disposition of Common Stock to or
through the United States office of a broker is subject to information reporting
and backup withholding at a rate of 31% unless the holder certifies its
non-United States status under penalties of perjury or otherwise establishes an
exemption. Generally, U.S. information reporting and backup withholding will not
apply to a payment of disposition proceeds if the payment is made outside the
United States through a non-U.S. office of a non-U.S. broker. However,
information reporting requirements (but not backup withholding) will apply to a
payment of disposition proceeds outside the United States through an office
outside the United States of a broker that is (a) a United States person, (b) a
United States controlled foreign corporation or (c) a foreign person 50% or more
of whose gross income for certain periods is from a United States trade or
business unless such broker has documentary evidence in its files of the owner's
foreign status and has no actual knowledge to the contrary.
Backup withholding is not an additional tax. Rather, the tax liability of
persons subject to backup withholding will be reduced by the amount of tax
withheld. If withholding results in an overpayment of taxes, a refund may be
obtained provided that the required information is furnished to the U.S.
Internal Revenue Service.
UNITED STATES ESTATE TAX
An individual Non-United States Holder who owns Common Stock at the time of
his death or has made certain lifetime transfers of an interest in Common Stock
will be required to include the value of such Common Stock in his gross estate
for United States federal estate tax purposes, and thus may be subject to United
States federal estate tax, unless an applicable estate tax treaty provides
otherwise.
60
<PAGE> 173
UNDERWRITING
Subject to the terms and conditions set forth in the International
Underwriting Agreement among the Company and Salomon Brothers International
Limited, Donaldson, Lufkin & Jenrette Securities Corporation, Prudential-Bache
Securities (U.K.) Inc., Morgan Keegan & Company, Inc. and Southcoast Capital
Corporation, as representatives of the several underwriters (the "International
Representatives"), the Company has agreed to sell to the entities named below
(the "International Underwriters"), and each of the International Underwriters
has severally agreed to purchase from the Company, the aggregate number of
shares of Common Stock set forth opposite its name below.
<TABLE>
<CAPTION>
NUMBER
INTERNATIONAL UNDERWRITERS OF SHARES
-------------------------- ---------
<S> <C>
Salomon Brothers International Limited ..................... 180,000
Donaldson, Lufkin & Jenrette Securities Corporation......... 150,000
Prudential-Bache Securities (U.K.) Inc. .................... 150,000
Morgan Keegan & Company, Inc. .............................. 60,000
Southcoast Capital Corporation.............................. 60,000
---------
Total............................................. 600,000
=========
</TABLE>
The International Underwriting Agreement provides that the several
International Underwriters will be obligated to purchase all the shares of
Common Stock being offered (other than the shares covered by the over-allotment
option described below), if any are purchased.
The International Representatives have advised the Company that they
propose initially to offer the Common Stock directly to the public at the public
offering price set forth on the cover page of this Prospectus and to certain
dealers at such price less a concession not in excess of $1.08 per share. The
International Underwriters may allow, and such dealers may reallow, a concession
not in excess of $0.10 per share on sales to certain other dealers. After the
initial offering, the price to public and concessions to dealers may be changed.
The Company has entered into a U.S. Agreement with the U.S. Underwriters
named therein, for whom Salomon Brothers Inc, Donaldson, Lufkin & Jenrette
Securities Corporation, Prudential Securities Incorporated, Morgan Keegan &
Company, Inc. and Southcoast Capital Corporation are acting as representatives
(the "U.S. Representatives"), providing for the concurrent offer and sale of
2,400,000 shares of Common Stock in the United States and Canada.
The initial public offering price and underwriting discount per share for
the U.S. Offering and the International Offering will be identical. The closing
of the U.S. Offering is conditioned upon the closing of the International
Offering, and the closing of the International Offering is conditioned upon the
closing of the U.S. Offering.
Each International Underwriter has severally agreed that, as part of the
distribution of the International Offering, (i) it is not purchasing any shares
of Common Stock for the account of any United States or Canadian Person and
(ii) it has not offered or sold, and will not offer or sell, directly or
indirectly, any shares of Common Stock or distribute this Prospectus to any
person within the United States or Canada or to any United States or Canadian
Person. Each U.S. Underwriter has severally agreed that, as part of the
distribution of the U.S. Offering, (i) it is not purchasing any shares of Common
Stock for the account of anyone other than a United States or Canadian Person,
and (ii) it has not offered or sold, and will not offer or sell, directly or
indirectly, any shares of Common Stock or distribute any Prospectus related to
the U.S. Offering to any person outside the United States or Canada or to anyone
other than a United States or Canadian Person. The foregoing limitations do not
apply to stabilization transactions or to certain other transactions specified
in the Agreement Between U.S. Underwriters and International Underwriters.
"United States or Canadian Person" means any person who is a national citizen or
resident of the United States or Canada, any corporation, partnership or other
entity created or organized in or under the laws of the United States or Canada,
or any political subdivision thereof, any estate or trust the income of which
61
<PAGE> 174
is subject to United States or Canadian federal income taxation, regardless of
the source of its income (other than a foreign branch of any United States or
Canadian Person), and includes any United States or Canadian branch or a person
other than a United States or Canadian Person.
Each U.S. Underwriter that will offer or sell shares of Common Stock in
Canada as part of the distribution has severally agreed that such offers and
sales will be made only pursuant to an exemption from the prospectus
requirements in each jurisdiction in Canada in which such offers and sales are
made.
Pursuant to the Agreement Between U.S. Underwriters and International
Underwriters, sales may be made between the U.S. Underwriters and the
International Underwriters of such number of shares of Common Stock as may be
mutually agreed. The price of any shares of Common Stock so sold shall be the
initial public offering price, less an amount not greater than the concession to
securities dealers. To the extent that there are sales between U.S. Underwriters
and the International Underwriters pursuant to the Agreement Between U.S.
Underwriters and International Underwriters, the number of shares initially
available for sale by the U.S. Underwriters or by the International Underwriters
may be more or less than the amount appearing on the cover page of this
Prospectus.
The Company has granted to the U.S. Underwriters and the International
Underwriters options to purchase up to an additional aggregate of 360,000 and
90,000 shares of Common Stock, respectively, at the price to public less the
underwriting discount set forth on the cover page of this Prospectus, solely to
cover over-allotments, if any, incurred in the sale of shares of Common Stock
being offered hereby. Either or both options may be exercised at any time up to
30 days after the date of this Prospectus. To the extent that the U.S.
Underwriters and the International Underwriters exercise such options, each of
the U.S. Underwriters or International Underwriters, as the case may be, will be
obligated, subject to certain conditions, to purchase a number of option shares
proportionate to such U.S. Underwriter's or International Underwriter's initial
commitment.
The Company and each International Underwriter and U.S. Underwriter (a)
have not offered or sold, and, prior to the expiration of six months from the
closing of the International Offering, will not offer or sell any shares of
Common Stock in the United Kingdom other than to persons whose ordinary
activities involve them in acquiring, holding, managing or disposing of
investments, whether as principal or agent, for the purposes of their businesses
or otherwise in circumstances which have not resulted in and will not result in
an offer to the public within the meaning of the Public Offers of Securities
Regulations 1995, (b) have complied and will comply with all applicable
provisions of the Financial Services Act of 1986 with respect to anything done
by them in relation to the shares of Common Stock in, from or otherwise
involving the United Kingdom and (c) have only issued or passed on, and will
only issue or pass on in the United Kingdom, any document received by it in
connection with the issue of the shares of Common Stock to a person who is of a
kind described in Article 11(3) of the Financial Services Act 1986 (Investment
Advertisements) (Exemptions) Order 1996 or is a person to whom the document may
otherwise lawfully be issued or passed on.
The shares of Common Stock may not be offered or sold directly or
indirectly in Hong Kong by means of this document or any other offering material
or document other than to persons whose ordinary business it is to buy or sell
shares or debentures, whether as principal or as agent. Unless permitted to do
so by the securities laws of Hong Kong, no person may issue or cause to be
issued in Hong Kong this document or any amendment or supplement thereto or any
other information, advertisement or document relating to the shares of Common
Stock other than with respect to shares of Common Stock intended to be disposed
of to persons outside Hong Kong or to persons whose business involves the
acquisition, disposal or holding of securities, whether as principal or as
agent.
The shares of Common Stock have not been registered under the Securities
and Exchange Law of Japan and are not being offered and may not be offered or
sold directly or indirectly in Japan or to residents of Japan, except pursuant
to applicable Japanese laws and regulations.
62
<PAGE> 175
For a period of 90 days after the date of this Prospectus, the Company and
each director and executive officer of the Company have agreed not to offer,
sell, contract to sell or otherwise dispose of any shares of Common Stock, any
other capital stock of the Company or any security convertible into or
exercisable or exchangeable for Common Stock or any such other capital stock
without the prior written consent of Salomon Brothers Inc, except that (i) the
Company may issue securities pursuant to the Company's stock option or other
benefit or incentive plans maintained for its officers, directors or employees,
and (ii) the Company may issue up to 435,000 shares of Common Stock upon
exercise of warrants issued in the Medallion Acquisition.
The Company has agreed to indemnify the International Underwriters against
certain civil liabilities, including certain liabilities under the Securities
Act, or contribute to payments the International Underwriters may be required to
make in respect thereof.
Company in the offshore Gulf Coast region) includes all the reserves of each
field from which the Company's VPP interest is taken.
CERTAIN LEGAL MATTERS
The validity of the issuance of the shares of Common Stock offered hereby
will be passed upon for the Company by Mayor, Day, Caldwell & Keeton, L.L.P.,
Houston, Texas. Certain legal matters relating to the sale of such Common Stock
will be passed upon for the Underwriters by Vinson & Elkins L.L.P., Houston,
Texas.
ACCOUNTANTS
The audited Consolidated Financial Statements and schedules of the Company
included or incorporated by reference in this Prospectus and elsewhere in the
Registration Statement have been audited by Arthur Andersen LLP, independent
public accountants, as indicated in their reports with respect thereto, and are
included herein in reliance upon said firm as experts in giving said reports.
The audited Combined Financial Statements of the InterCoast Entities
included in this Prospectus and elsewhere in the Registration Statement have
been audited by Arthur Andersen LLP, independent public accountants, as
indicated in their report with respect thereto, and are included herein in
reliance upon said firm as experts in giving said report.
The audited Statement of Revenues and Direct Operating Expenses of the
Sawyer Canyon Properties included in this Prospectus and elsewhere in the
Registration Statement have been audited by Arthur Andersen LLP, independent
public accountants, as indicated in their report with respect thereto, and are
included herein in reliance upon said firm as experts in giving said report.
RESERVE ENGINEERS
Information set forth in this Prospectus relating to the Company's
estimated proved oil and gas reserves not attributable to its VPP program or its
working interest reserves in the Niagaran Reef trend in Michigan (approximately
1% of total proved reserves) at June 30, 1996, the related calculations of
future net production revenues and the net present value thereof have been
derived from independent reserve engineering reports prepared for the Company by
Ryder Scott Company (the Medallion Acquisition), H.J. Gruy and Associates, Inc.
(the Rocky Mountain Acquisition) and R.A. Lenser and Associates, Inc. (the
onshore Gulf Coast properties), and all such information has been included in
reliance on the authority of such firms as experts regarding the matters
contained in their reports.
Although reserve engineers' reports with respect to reserves underlying the
Company's VPP program are utilized by the Company to support its own analysis of
such reserves, the proved reserves, related future net revenues and PV-10 that
the Company reports with respect to volumetric production payments are not
derived from independent reserve engineers' report, but rather are taken
directly from the amounts contracted for, pursuant to the agreements relating to
each volumetric production payment
63
<PAGE> 176
(which amounts are less than the net interest production reflected in the
reserve reports). A report prepared for the Company by Ryder Scott Company
(covering the VPP program properties owned by the Company in the offshore Gulf
Coast region) includes all the reserves of each field from which the Company's
VPP interest is taken.
AVAILABLE INFORMATION
The Company has filed with the SEC a registration statement on Form S-3
(the "Registration Statement"), which term encompasses all amendments, exhibits,
annexes and schedules thereto under the Securities Act, with respect to the
Common Stock offered hereby. This Prospectus which constitutes a part of the
Registration Statement, does not contain all the information set forth in the
Registration Statement, to which reference is hereby made. Statements made in
this Prospectus as to the contents of any contract, agreement or other document
referred to are not necessarily complete. With respect to each such contract,
agreement or other document filed as an exhibit to the Registration Statement
and the exhibits thereto, reference is hereby made to the exhibit for a more
complete description of the matter involved, and each statement made herein
shall be deemed qualified in its entirety by such reference.
The Company is subject to the informational requirements of the Exchange
Act, and in accordance therewith files reports, proxy statements and other
information with the SEC. Such reports, proxy statements and other information
filed by the Company may be inspected and copied at the public reference
facilities maintained by the SEC, 450 Fifth Street, N.W., Judiciary Plaza,
Washington, D.C. 20549; and at the following regional offices of the SEC: 7
World Trade Center, Suite 1300, New York, New York 10048; and CitiCorp Center,
500 West Madison Street, Chicago, Illinois 60661. Copies of such material can
also be obtained from the Public Reference Section of the SEC at 450 Fifth
Street, N.W., Judiciary Plaza, Washington, D.C. 20549, at prescribed rates. The
SEC maintains an Internet web site that contains reports, proxy and information
statements and other information regarding registrants that file electronically
with the SEC (http:\\www.sec.gov). The Common Stock is traded on the New York
Stock Exchange. The Company's reports, proxy statements and other information
concerning the Company can be inspected and copied at the offices of the New
York Stock Exchange, 20 Broad Street, New York, New York 10005.
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
The Company's (i) Annual Report on Form 10-K for the year ended December
31, 1995, (ii) Quarterly Report on Form 10-Q for the three months ended March
31, 1996, (iii) Quarterly Report on Form 10-Q for the three months ended June
30, 1996, (iv) Quarterly Report on Form 10-Q for the three months ended
September 30, 1996, (v) Current Report on Form 8-K dated January 25, 1996 (filed
January 29, 1996), (vi) Current Report on Form 8-K dated April 18, 1996 (filed
on April 19, 1996), (vii) Current Report on Form 8-K dated August 16, 1996
(filed August 21, 1996) (viii) Current Report on Form 8-K dated October 17, 1996
(filed on November 5, 1996), (ix) Amendment No. 1 to Current Report on Form 8-K
dated October 17, 1996 (filed on November 15, 1996) (x) Current Report on Form
8-K dated November 25, 1996 (filed on November 25, 1996), (xi) Current Report on
Form 8-K dated December 24, 1996 (filed on December 26, 1996) and (xii)
Amendment No. 2 to Current Report on Form 8-K dated October 17, 1996 (filed
January 9, 1997) are incorporated into this Prospectus by reference.
Each document filed by the Company pursuant to Section 13(a), 13(c), 14 or
15(d) of the Exchange Act, subsequent to the date of this Prospectus and prior
to the termination of the offering of Common Stock made hereby shall be deemed
to be incorporated herein by reference and to be a part hereof from the date of
filing of such document. Any statement contained herein or in a document all or
a portion of which is incorporated or deemed to be incorporated by reference
herein shall be deemed to be modified or superseded for purposes of this
Prospectus to the extent that a statement contained herein or in any
subsequently filed document which also is or is deemed to be incorporated by
reference herein
64
<PAGE> 177
modifies or supersedes such statement. Any statement so modified or superseded
shall not be deemed, except as so modified or superseded, to constitute a part
of this Prospectus.
The Company will provide without charge to each person to whom a copy of
this Prospectus is delivered, on the request of any such person, a copy of any
or all of the foregoing documents incorporated herein by reference (other than
exhibits to such documents, unless such exhibits are specifically incorporated
by reference into such documents). Requests should be directed to the Company at
379 Thornall Street, Edison, New Jersey 08837, Attention: Corporate Secretary
(telephone: (908) 632-1770).
65
<PAGE> 178
GLOSSARY
The following are abbreviations and definitions of terms used throughout
this Prospectus.
Acquisition Cost. An amount per Mcfe equal to the total purchase price paid
divided by the estimated proved reserves acquired.
bbl. Barrel of 42 U.S. gallons of crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet.
Bcfe. Billion feet of natural gas equivalent.
Btu. British thermal unit, which is the quantity of heat required to raise
the temperature of one pound of water from 58.5 to 59.5 degrees Fahrenheit.
Completion. Installation of permanent equipment for the production of oil
or gas.
Condensate. Hydrocarbon mixture that becomes liquid and separates from
natural gas when the natural gas is produced. Similar to crude oil.
Development location. A location on which a development well can be
drilled.
Development well. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive in an
attempt to recover proved undeveloped reserves.
EBITDA. EBITDA represents income before depletion, depreciation,
amortization, interest expense, interest and other income and income taxes.
EBITDA is a financial measure commonly used in the Company's industry and should
not be considered in isolation or as a substitute for net income, cash flow
provided by operating activities or other income or cash flow data prepared in
accordance with generally accepted accounting principles or as a measure of a
company's profitability or liquidity.
Extensional Infill Drilling ("EID"). Drilling of a well to enhance the
economic recovery of oil and gas in producing areas to a level greater than that
previously achieved by the owners of the prevailing leasehold by increasing the
density of wells that penetrate known reservoirs. Typically, development of
these prospects requires rights to drill on acreage that is held by production.
Exploratory well. A well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field which contains other
productive oil or gas reservoirs.
Finding Cost. An amount per Mcfe equal to the sum of all costs incurred
relating to oil and gas property acquisition, exploration and development
activities divided by the sum of all additions and revisions to estimated proved
reserves, including reserve purchases.
Mcf equivalent ("Mcfe"). Mcf of natural gas equivalent, determined using
the ratio of one bbl of crude oil, condensate or natural gas liquids to six Mcf
of natural gas.
Gross acres or gross wells. An acre or well in which a working interest is
owned.
Mbbl. One thousand barrels of crude oil or other liquid hydrocarbons.
MMbbl. One million barrels of crude oil or other liquid hydrocarbons.
MBtu. One thousand Btus.
MMBtu. One million Btus.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet of natural gas equivalent.
MMcf. One million cubic feet.
MMcfe. One million cubic feet of natural gas equivalent.
66
<PAGE> 179
Net acres or net wells. The sum of the fractional working interests net to
the Company owned in gross acres or gross wells.
Net production. Production after royalties and production due others.
Overriding royalty interest. An interest in an oil and gas property
entitling the owner to a share of oil or gas production, free of costs of
production.
Pre-tax present value of estimated future net revenues ("PV-10"). Estimated
future net revenues before income taxes with no price or cost escalation or
deescalation, in accordance with guidelines promulgated by the SEC and
discounted using an annual discount rate of 10%.
Productive well. A well that is producing oil or gas or that is capable of
production.
Proved developed reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Proved reserves. 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.
Proved undeveloped reserves. 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.
Recompletion. The completion for production of an existing wellbore in
another formation from that in which the well has previously been completed.
Reserve life. Calculation derived by dividing year-end reserves by total
production in that year.
Reserve replacement. Calculation derived by dividing gross additions to
reserves in a year by total production in that year.
Section 29 tax credit. The Section 29 tax credit is an income tax credit
against regular federal income tax liability with respect to sales of natural
gas produced from tight gas sand formations, subject to a number of limitations.
Fuels qualifying for the Section 29 tax credit must be produced from a well
drilled or a facility placed in service after November 5, 1990 and before
January 1, 1993, and be sold before January 1, 2003.
Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas regardless of whether such acreage contains proved reserves.
Working interest. The operating interest which gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
the production.
Workover. Operations on a producing well to restore or increase production.
67
<PAGE> 180
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<S> <C>
KCS Energy, Inc. and Subsidiaries
Report of Independent Public Accountants............................................ F-2
Statements of Consolidated Income for the years ended December 31, 1993, 1994 and
1995 and for the nine months ended September 30, 1995 and 1996 (unaudited)....... F-3
Consolidated Balance Sheets at December 31, 1994 and 1995 and September 30, 1996
(unaudited)...................................................................... F-4
Statements of Consolidated Stockholders' Equity for the years ended December 31,
1993, 1994 and 1995 and for the nine months ended September 30, 1996
(unaudited)...................................................................... F-5
Statements of Consolidated Cash Flows for the years ended December 31, 1993, 1994
and 1995 and for the nine months ended September 30, 1995 and 1996 (unaudited)... F-6
Notes to Consolidated Financial Statements.......................................... F-7
InterCoast Entities (Medallion)
Report of Independent Public Accountants............................................ F-26
Combined Statements of Income for the years ended December 31, 1993, 1994 and 1995
and for the nine months ended September 30, 1995 and 1996 (unaudited)............ F-27
Combined Balance Sheets at December 31, 1994 and 1995 and September 30, 1996
(unaudited)...................................................................... F-28
Combined Statements of Stockholders' Equity for the years ended December 31, 1993,
1994 and 1995 and for the nine months ended September 30, 1996 (unaudited)....... F-29
Combined Statements of Cash Flows for the years ended December 31, 1993, 1994 and
1995 and for the nine months ended September 30, 1995 and 1996 (unaudited)....... F-30
Notes to Combined Financial Statements.............................................. F-31
Sawyer Canyon Properties
Report of Independent Public Accountants............................................ F-42
Statements of Revenues and Direct Operating Expenses for the years ended December
31, 1994 and 1995 and for the three months ended March 31, 1996 (unaudited)...... F-43
Notes to Statements of Revenues and Direct Operating Expenses....................... F-44
</TABLE>
F-1
<PAGE> 181
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To KCS Energy, Inc.:
We have audited the accompanying consolidated balance sheets of KCS Energy,
Inc. (a Delaware Corporation) and subsidiaries as of December 31, 1994 and 1995,
and the related statements of consolidated income, stockholders' equity and cash
flows for each of the three years in the period ended December 31, 1995. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. 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 financial position of KCS Energy, Inc. and
subsidiaries as of December 31, 1994 and 1995, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1995 in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
New York, New York
February 29, 1996
F-2
<PAGE> 182
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
FOR THE NINE MONTHS
ENDED,
FOR THE YEARS ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------------ -----------------------
1993 1994 1995 1995 1996
---------- ---------- ---------- ---------- ----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenue........................ $ 304,289 $ 341,713 $ 449,965 $ 332,274 $ 316,604
Operating costs and expenses
Cost of gas sales............ 253,435 265,076 356,186 264,097 231,063
Other operating and
administrative expenses... 15,018 18,285 18,669 12,950 19,427
Depreciation, depletion and
amortization.............. 8,036 19,740 39,209 29,299 33,933
---------- ---------- ---------- ---------- ----------
Operating costs and
expenses................ 276,489 303,101 414,064 306,346 284,423
---------- ---------- ---------- ---------- ----------
Operating income.......... 27,800 38,612 35,901 25,928 32,181
Interest and other income,
net.......................... 704 1,039 3,713 2,311 4,850
Interest expense............... (1,983) (2,938) (7,732) (4,912) (13,858)
---------- ---------- ---------- ---------- ----------
Income before income taxes..... 26,521 36,713 31,882 23,327 23,173
Federal and state income
taxes........................ 7,910 12,556 10,576 7,645 8,367
---------- ---------- ---------- ---------- ----------
Net income................ $ 18,611 $ 24,157 $ 21,306 $ 15,682 $ 14,806
========== ========== ========== ========== ==========
Earnings per share of common
stock and common stock
equivalents.................. $ 1.60 $ 2.05 $ 1.81 $ 1.33 $ 1.25
========== ========== ========== ========== ==========
Average shares of common stock
and common stock equivalents
outstanding.................. 11,658,370 11,804,989 11,760,701 11,766,011 11,886,434
========== ========== ========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-3
<PAGE> 183
KCS ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------
1994 1995
-------- -------- SEPTEMBER 30,
1996
------------
(UNAUDITED)
<S> <C> <C> <C>
ASSETS
Current assets
Cash and cash equivalents........................................ $ 988 $ 5,846 $ 53,597
Trade accounts receivable, less allowance for doubtful
accounts -- 1994, $305; 1995, $415 and September 30, 1996,
$858.......................................................... 46,380 58,052 39,146
Receivable from Tennessee Gas.................................... 13,569 56,437 --
Fuel inventories................................................. 2,509 782 884
Other current assets............................................. 4,148 3,374 5,055
------- ------- -------
Current assets................................................ 67,594 124,491 98,682
Property, plant and equipment
Oil and gas properties, full cost method, less accumulated
DD&A -- 1994, $49,077; 1995, $86,936 and September 30, 1996,
$119,775...................................................... 125,621 204,958 206,308
Natural gas transportation systems, at cost less accumulated
depreciation -- 1994, $3,480; 1995, $4,285 and September 30,
1996, $5,156.................................................. 17,315 22,345 22,296
Other property, plant and equipment, at cost less accumulated
depreciation -- 1994, $1,681; 1995, $1,472 and September 30,
1996, $1,866.................................................. 1,468 2,013 2,979
------- ------- -------
Property, plant and equipment, net................................. 144,404 229,316 231,583
Investments and other assets....................................... 2,425 6,802 10,887
------- ------- -------
$214,423 $360,609 $ 341,152
======= ======= =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Current maturities of long-term debt............................. $ 1,035 $ -- $ --
Accounts payable................................................. 44,172 59,475 34,680
Accrued liabilities.............................................. 6,172 4,926 7,032
------- ------- -------
Current liabilities.............................................. 51,379 64,401 41,712
Deferred credits and other liabilities
Deferred federal and state income taxes.......................... 17,069 26,172 30,367
Other............................................................ 3,337 2,931 2,931
------- ------- -------
Deferred credits and other liabilities............................. 20,406 29,103 33,298
Long-term debt..................................................... 61,970 165,529 149,830
Commitments and contingencies
Preferred stock, authorized 5,000,000 shares -- unissued........... -- -- --
Stockholders' equity
Common stock, par value $0.01 per share, authorized 50,000,000
shares issued 12,344,278 and 12,379,885, at December 31, 1994
and 1995, respectively, and 12,488,120 shares issued at
September 30, 1996............................................ 123 124 125
Additional paid-in capital....................................... 23,895 24,910 25,997
Retained earnings................................................ 59,885 79,814 93,578
Less treasury stock, 890,248 and 892,748 shares, at December 31,
1994 and 1995, respectively, and 900,748 at September 30,
1996.......................................................... (3,235) (3,272) (3,388)
------- ------- -------
Total stockholders' equity.................................... 80,668 101,576 116,312
------- ------- -------
$214,423 $360,609 $ 341,152
======= ======= =======
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-4
<PAGE> 184
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY
(DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
ADDITIONAL
COMMON PAID-IN RETAINED TREASURY STOCKHOLDERS'
STOCK CAPITAL EARNINGS STOCK EQUITY
------ ---------- -------- -------- -------------
<S> <C> <C> <C> <C> <C>
Balance at December 31, 1992.......... $116 $ 12,618 $18,825 $(1,326 ) $ 30,233
Stock issuances
-- option and benefit plans......... 4 1,019 -- -- 1,023
-- acquisitions..................... 3 6,176 -- -- 6,179
Tax benefit on stock option
exercises........................... -- 3,473 -- -- 3,473
Net income............................ -- -- 18,611 -- 18,611
Dividends ($0.06 per share)........... -- -- (675 ) -- (675)
---- ------- ------- ------- --------
Balance at December 31, 1993.......... 123 23,286 36,761 (1,326 ) 58,844
Stock issuances -- option and benefit
plans............................... -- 380 -- -- 380
Tax benefit on stock option
exercises........................... -- 229 -- -- 229
Net income............................ -- -- 24,157 -- 24,157
Dividends ($0.09 per share)........... -- -- (1,033 ) -- (1,033)
Purchase of treasury stock............ -- -- -- (1,909 ) (1,909)
---- ------- ------- ------- --------
Balance at December 31, 1994.......... 123 23,895 59,885 (3,235 ) 80,668
Stock issuances -- option and benefit
plans............................... 1 188 -- -- 189
Tax benefit on stock option
exercises........................... -- 201 -- -- 201
Stock warrants issued................. -- 626 -- -- 626
Net income............................ -- -- 21,306 -- 21,306
Dividends ($0.12 per share)........... -- -- (1,377 ) -- (1,377)
Purchase of treasury stock............ -- -- -- (37 ) (37)
---- ------- ------- ------- --------
Balance at December 31, 1995.......... 124 24,910 79,814 (3,272 ) 101,576
Stock issuances -- option and benefit
plans............................... 1 520 -- -- 521
Tax benefit on stock option
exercises........................... -- 567 -- -- 567
Net income............................ -- -- 14,806 -- 14,806
Dividends ($0.09 per share)........... -- -- (1,042 ) -- (1,042)
Purchase of treasury stock............ -- -- -- (116 ) (116)
---- ------- ------- ------- --------
Balance at September 30, 1996
(unaudited)......................... $125 $ 25,997 $93,578 $(3,388 ) $ 116,312
==== ======= ======= ======= ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-5
<PAGE> 185
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
FOR THE NINE MONTHS
FOR THE YEARS ENDED DECEMBER 31, ENDED SEPTEMBER 30,
----------------------------------- ---------------------
1993 1994 1995 1995 1996
-------- -------- --------- ------- ---------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Cash flows from operating activities:
Net income............................ $ 18,611 $ 24,157 $ 21,306 $15,682 $ 14,806
Non-cash charges (credits)
Depreciation, depletion and
amortization..................... 8,036 19,740 39,209 29,299 33,933
Deferred income taxes.............. 1,440 10,896 9,756 7,441 4,195
Other non-cash charges and credits,
net.............................. (559) (65) 820 1,315 1,248
-------- -------- --------- -------- ---------
27,528 54,728 71,091 53,737 54,182
Net changes is assets and liabilities:
Trade accounts receivable.......... (36,153) 19,107 (11,672) (714) 18,906
Receivable from Tennessee Gas...... -- (13,569) (42,868) (32,613) 56,437
Fuel inventories................... (417) (1,126) 1,727 1,303 (102)
Other current assets............... 138 (1,299) 490 (1,178) (1,681)
Accounts payable and accrued
liabilities...................... 29,023 (10,724) 14,163 6,735 (22,689)
Federal and state income taxes..... 1,615 (119) 178 (1,623) (1,419)
Other, net......................... (311) 3,118 (2,999) 3,014 1,493
-------- -------- --------- -------- ---------
Net cash provided by operating
activities............................ 21,423 50,116 30,110 28,661 105,127
Cash flows from investing activities:
Investment in oil and gas
properties......................... (36,420) (73,682) (121,265) (52,953) (50,552)
Proceeds from the sale of oil and gas
properties......................... -- -- 4,069 5,524 16,384
Investment in natural gas
transportation systems............. (1,512) (700) (5,969) (3,681) (843)
Investment in other property, plant
and equipment...................... (344) (571) (1,465) (821) (1,340)
-------- -------- --------- -------- ---------
Net cash used in investing activities... (38,276) (74,953) (124,630) (51,931) (36,351)
Cash flows from financing activities:
Proceeds from long-term debt.......... 18,000 49,431 141,298 51,369 165,145
Repayments of long-term debt.......... (3,956) (26,247) (38,774) (23,574) (180,900)
Issuance of common stock.............. 1,023 380 189 222 521
Issuance of stock warrants............ -- -- 626 -- --
Tax benefit on stock option
exercises.......................... 3,473 229 201 124 567
Purchase of treasury stock............ -- (1,909) (37) (37) (116)
Dividends paid........................ (554) (919) (1,377) (1,033) (1,042)
Deferred financing costs and other,
net................................ (56) (509) (2,748) (602) (5,200)
-------- -------- --------- -------- ---------
Net cash provided by (used in) financing
activities............................ 17,930 20,456 99,378 26,469 (21,025)
-------- -------- --------- -------- ---------
Increase (decrease) in cash and cash
equivalents........................... 1,077 (4,381) 4,858 3,199 47,751
Cash and cash equivalents at beginning
of year............................... 4,292 5,369 988 988 5,846
-------- -------- --------- -------- ---------
Cash and cash equivalents at end of
year.................................. $ 5,369 $ 988 $ 5,846 $ 4,187 $ 53,597
======== ======== ========= ======== =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-6
<PAGE> 186
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
KCS Energy, Inc. is principally engaged in the acquisition, exploration,
development and production of natural gas and crude oil. The Company also
operates natural gas transportation and energy marketing and services
businesses.
Recapitalization (Quasi-reorganization)
At September 30, 1988, prior to the start of the Company's first full year
of operations as a separate legal entity with independent management, an amount
equal to the cumulative retained earnings deficit of the KCS subsidiaries
($25,109,000) was eliminated against additional paid-in capital in connection
with a quasi-reorganization.
Basis of Presentation
The consolidated financial statements include the accounts of KCS Energy,
Inc. and its wholly owned subsidiaries ("KCS" or "Company"). All significant
intercompany accounts and transactions have been eliminated in consolidation.
Certain previously reported amounts have been reclassified to conform to current
year presentations.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates. The most
significant estimates and assumptions impacting the Company's consolidated
financial statements relate to the Tennessee Gas contract. See Note 7. The
condensed interim financial statements included herein have been prepared by KCS
Energy, Inc., without audit, pursuant to the rules and regulations of the
Securities and Exchange Commission ("SEC") and reflect all adjustments which are
of a normal recurring nature and which, in the opinion of management, are
necessary for a fair statement of the results for interim periods. Certain
information and footnote disclosures have been condensed or omitted pursuant to
such rules and regulations. The results of operations for the interim periods
presented are not necessarily indicative of the results to be expected for the
full year.
Cash Equivalents
The Company considers all highly liquid investments with a maturity of
three months or less when purchased to be cash equivalents.
Futures Contracts
The Company utilizes oil and natural gas futures contracts for the purpose
of hedging the risks associated with fluctuating crude oil and natural gas
prices and accounts for such contracts in accordance with FASB Statement No. 80,
"Accounting for Futures Contracts." These contracts permit settlement by
delivery of commodities and, therefore, are not financial instruments, as
defined by FASB Statement Nos. 107 and 119. At December 31, 1994, the Company's
hedging activities consisted of 760 long contracts at an average price of $1.93
per Mcf and 305 short contracts at an average price of $1.95 per Mcf maturing
through 1995 and 1996, covering 10,650 MMcf of natural gas. At December 31,
1995, the Company's hedging activities consisted of 700 long contracts at an
average price of $1.82 per Mcf and 587 short contracts at an average price of
$1.95 per Mcf maturing through 1996, covering 12,870 MMcf of natural gas. Since
these contracts qualify as hedges and correlate to market price movements of
natural gas, any gains or losses resulting from market changes will be offset by
losses or gains on
F-7
<PAGE> 187
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
corresponding physical transactions. Deferred gains, net of deferred losses,
were $1.4 million at December 31, 1994. Deferred losses, net of deferred gains,
were $0.1 million at December 31, 1995.
Imbalances
The Company follows the entitlements method of accounting for production
imbalances, where revenues are recognized based on its interest in oil and gas
production from a well. Imbalances arise when a purchaser takes delivery of more
or less from a well than the Company's actual interest in the production from
that well. The difference between cash received and revenue recorded is a
receivable or payable. Such imbalances are reduced either by subsequent
balancing of over and under deliveries or by cash settlement, as required by
applicable contracts. Such imbalances were not material at December 31, 1994 or
1995.
Property, Plant and Equipment
The Company follows the full cost method of accounting, under which all
productive and nonproductive costs associated with its exploration, development
and production activities are capitalized in a country-wide cost center. Such
costs include lease acquisitions, geological and geophysical services, drilling,
completion, equipment and certain general and administrative costs directly
associated with acquisition, exploration and development activities. General and
administrative costs related to production and general overhead are expensed as
incurred. The Company provides for depreciation, depletion and amortization of
evaluated costs using the future gross revenue method based on recoverable
reserves valued at current prices. Under accounting procedures prescribed by the
Securities and Exchange Commission capitalized costs may not exceed the present
value of future net revenues from production of proved oil and gas reserves. To
the extent that the capitalized costs exceed the estimated present value of
future net revenues at the end of any fiscal quarter, such excess costs are
written down with a corresponding charge to income.
Depreciation of other property, plant and equipment is provided on a
straight-line basis over the useful lives of the assets, except for certain
natural gas gathering pipelines which are depreciated based on the estimated
lives of the gas wells served. Repairs of all property, plant and equipment and
replacements and renewals of minor items of property are charged to expense, as
incurred.
Income Taxes
The Company accounts for income taxes in accordance with FASB Statement No.
109, "Accounting for Income Taxes." Deferred income taxes reflect the future tax
consequences of differences between the tax bases of assets and liabilities and
their financial reporting amounts at each year end.
For income tax purposes, the Company deducts the difference between market
value and exercise price arising from the exercise of stock options. The tax
effect of this deduction which, for financial reporting purposes, is accounted
for as an increase to additional paid-in capital, amounted to $3,473,000,
$229,000 and $201,000 in 1993, 1994 and 1995, respectively.
Earnings Per Share
Earnings per share have been computed by dividing net earnings by the
weighted average number of common shares outstanding during the periods,
adjusted for the dilutive effects of stock options and warrants.
F-8
<PAGE> 188
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Supplemental Cash Flow Disclosures
The Company acquired certain producing properties during 1993. The related
non-cash investing and financing activities are summarized as follows:
<TABLE>
<CAPTION>
DOLLARS IN
THOUSANDS
----------
<S> <C>
Investment in oil and gas properties..................................... $ (10,179)
Subordinated note payable assumed........................................ 4,000
Issuance of common stock................................................. 6,179
</TABLE>
2. RETIREMENT BENEFIT PLANS
The Company has a trusteed, non-contributory Retirement Plan ("Plan"). The
Plan was amended to freeze the accrual of future benefits as of October 31,
1991. Prior to October 1991, the Plan covered substantially all full-time
employees of KCS and its participating subsidiaries. The Company's funding
policy for the Plan is to make annual contributions that meet the minimum
funding requirements of the Employee Retirement Income Security Act of 1974. The
required contribution was $49,924 in 1993. No contributions were required in
1994 and 1995.
Net periodic pension costs consisted of the following components:
<TABLE>
<CAPTION>
1993 1994 1995
----- ----- ----
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Service cost -- benefits earned during the period......... $ -- $ -- $ --
Interest cost on projected benefit obligation............. 75 66 69
Actual return on plan assets.............................. (360) 78 (4)
Net amortization and deferral............................. 340 (153) (64)
----- ----- ----
Net periodic pension cost (income)........................ $ 55 $ (9) $ 1
===== ===== ====
</TABLE>
The following table sets forth the funded status and amounts recognized in
the consolidated balance sheets at December 31, 1994 and 1995 for the Plan:
<TABLE>
<CAPTION>
1994 1995
------ ------
(DOLLARS IN
THOUSANDS)
<S> <C> <C>
Actuarial present value of benefit obligations:
Vested benefits.............................................. $ 980 $ 969
Non-vested benefits.......................................... 18 --
Accumulated benefit obligation............................... 998 969
Projected benefit obligation................................... 998 969
Market value of plan assets.................................... 1,272 1,157
Excess of plan assets over projected benefit obligation........ 274 188
Unrecognized net loss.......................................... 143 199
Unrecognized net asset at January 1............................ (100) (82)
------ ------
Pension prepayment in the balance sheet........................ $ 317 $ 305
====== ======
</TABLE>
Assumptions used for the 1994 and 1995 actuarial calculations were 7% for
the discount rate and expected long-term return on assets. As a result of the
October 31, 1991 freeze of future benefits, no service costs accrued during the
periods. During 1995, the Company made lump-sum cash payments to
F-9
<PAGE> 189
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
terminated participants which represented a settlement of projected benefit
obligations. Plan assets at December 31, 1995 are invested in both cash
equivalents and KCS Energy, Inc. common stock.
The Board of Directors took action to terminate the Plan effective
September 30, 1995. The Company has filed all required standard termination
applications with both the Internal Revenue Service and the Pension Benefit
Guaranty Corporation. A complete settlement of the Plan's projected benefit
obligations is expected to occur during 1996.
The Company sponsors a Savings and Investment Plan ("Savings Plan") under
Section 401(k) of the Internal Revenue Code. Eligible employees may contribute
up to 16% of their base salary to the Savings Plan subject to certain IRS
limitations. The Company may make matching contributions, which have been set by
the Board of Directors at 50% of the employee's contribution (up to 6% of annual
base compensation) since the inception of the Savings Plan in June 1988. The
Savings Plan also contains a profit-sharing component whereby the Board of
Directors may declare annual discretionary profit-sharing contributions.
Profit-sharing contributions are allocated to each eligible employee. Employee
and profit-sharing contributions 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 fair market value. Company matching contributions are invested in shares of
KCS common stock. Eligible employees vest in both the Company matching and
discretionary profit-sharing contributions over a four-year period based upon
their years of service with the Company. Company contributions to the Savings
Plan were $282,232 in 1993, $293,622 in 1994 and $253,666 in 1995.
SUBSEQUENT INFORMATION (UNAUDITED)
In July 1996, the Company completed the termination of its non-contributory
Retirement Plan and satisfied all obligations thereunder.
3. STOCK OPTION AND INCENTIVE PLANS
The Company has two employee stock option and incentive plans, the 1988
Stock Plan and the 1992 Stock Plan (the "Employee Incentive Plans"). Under the
Employee Incentive Plans, stock options, stock appreciation rights and
restricted stock may be granted to employees of KCS. The 1992 Stock Plan also
provides that bonus stock may be granted to employees.
The 1994 Directors' Stock Plan provides that each non-employee director be
granted stock options for 1,000 shares annually. This plan also provides that in
lieu of cash, each non-employee director be issued KCS stock with a fair market
value equal to 50% of their annual retainer.
Each plan provides that the option price of shares issued be equal to the
market price on the date of grant. All options expire 10 years after the date of
grant. At December 31, 1995, options for 405,500 shares were exercisable.
F-10
<PAGE> 190
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Transactions during the last three years involving stock options under the
above plans are summarized as follows:
<TABLE>
<CAPTION>
NUMBER OF OPTION PRICE
SHARES PER SHARE
--------- -------------
<S> <C> <C>
Options outstanding, December 31, 1992.................. 792,200 $1.21-$ 6.25
1993 -- Granted......................................... 106,700 $22.88
-- Exercised....................................... (419,200) $1.21-$ 6.25
1994 -- Granted......................................... 106,000 $14.50-$26.88
-- Exercised....................................... (32,200) $1.33-$ 6.25
1995 -- Granted......................................... 105,000 $13.00-$16.31
-- Exercised....................................... (22,600) $1.33-$ 1.98
-- Forfeited....................................... (3,100) $22.88-$26.88
------- ------------
Options outstanding, December 31, 1995.................. 632,800 $1.50-$26.88
======= ============
</TABLE>
Restricted shares awarded under the Employee Incentive Plans have a fixed
restriction period during which ownership of the shares cannot be transferred
and the shares are subject to forfeiture if employment terminates. Restricted
stock has the same dividend and voting rights as other common stock and is
considered to be currently issued and outstanding. The cost of the awards,
determined as the fair market value of the shares at the date of grant, is
expensed ratably over the period the restrictions lapse. This cost was
immaterial during the three years ended December 31, 1995. Restricted stock
totaling 11,200 shares was outstanding under the Employee Incentive Plans at
December 31, 1995.
Bonus stock awards under the 1992 Stock Plan convert to shares of
restricted stock if certain three-year performance goals are met. The restricted
stock then vests over a two-year period. The cost of the awards is expensed
ratably based on the current market price of the Company's common stock and the
extent to which the performance goals are being met. This cost amounted to
$200,000 in 1993 and was immaterial in 1994 and 1995. Bonus stock grants
totaling 48,800 shares were outstanding at December 31, 1995.
At December 31, 1995, 49,402 shares were available for future grants
(including bonus stock awards) under the Employee Incentive Plans.
Under the 1988 KCS Energy, Inc. Employee Stock Purchase Program (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 per share
determined by the closing price on the date of purchase. The minimum purchase is
25 shares. The maximum annual purchase is the number of shares costing no more
than 10% of the eligible employee's annual base salary, and for directors, 3,000
shares. The number of shares issued in connection with the Program was 26,845,
7,438 and 6,897 during 1993, 1994 and 1995, respectively. At December 31, 1995,
there were 443,695 shares available for issuance under the Program.
F-11
<PAGE> 191
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
4. LONG-TERM DEBT
Long-term debt consists of the following:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------- SEPTEMBER 30,
Dollars in thousands 1994 1995 1996
------- -------- --------
<S> <C> <C> <C>
(UNAUDITED)
Credit Facility.......................................... $ -- $ -- $ 100
Master Note Facility..................................... 46,400 76,255 --
Receivables Facility..................................... -- 26,900 --
VPP Facility............................................. -- 38,000 --
Note Financing........................................... -- 24,374 --
Revolving credit agreement............................... 15,431 -- --
Subordinated Note Payable................................ 910 -- --
Senior Notes............................................. -- -- 149,434
Other.................................................... -- -- 296
Installment note payable to bank due in equal monthly
installments, with interest at 10.5%................... 264 -- --
------- --------
63,005 165,529 149,830
Less current maturities.................................. 1,035 -- --
------- -------- --------
Long-term debt........................................... $61,970 $165,529 $149,830
======= ======== ========
</TABLE>
SENIOR NOTES
On January 25, 1996, subsequent to the year ended December 31, 1995, KCS
Energy, Inc. (the "Parent") completed a private offering of $150 million senior
notes at an interest rate of 11% due January 15, 2003 (the "Senior Notes"). The
Senior Notes are noncallable for four years and are unsecured obligations of the
Parent. Prior to January 15, 1999, the Parent may use proceeds from a public
equity offering to redeem up to $35 million of the Senior Notes. The
subsidiaries of the Parent have guaranteed the Senior Notes on a senior
unsecured basis. The net proceeds of approximately $145 million were used to
reduce the amounts outstanding under certain of the agreements discussed below.
The Senior Notes contain certain restrictive covenants which, among other
things, limit the Company's ability to incur additional indebtedness, require
the repurchase of the Senior Notes upon a change of control and restrict the
aggregate cash dividends paid to 50% of the Company's cumulative net income
during the period beginning October 1, 1995. Additionally, the Master Note
Facility, Receivables Facility and VPP Facility agreements summarized below were
amended to permit the borrowers under the agreements to guarantee the Senior
Notes and to remove restrictions on subsidiary dividends to the Parent.
On May 8, 1996, the Company commenced an offer (the "Exchange Offer") of up
to $150 million senior notes (the "Exchange Notes") in exchange for the
outstanding Senior Notes, pursuant to a registration statement declared
effective by the Securities and Exchange Commission on May 7. The Exchange Notes
are identical in all material respects to the form and terms of the Senior Notes
except for certain transfer restrictions and registration rights applicable to
the Senior Notes. The Exchange Notes evidenced the same debt, and were issued
under and entitled to the benefits of the same Indenture, as the Senior Notes.
At June 30, 1996, the Company maintained three separate bank credit
facilities to support its operations. The Master Note Facility was utilized
primarily to support the expansion of the Company's exploration and production
and natural gas transportation businesses. The Company's natural gas marketing
subsidiary had two credit facilities, the Receivable Facility and VPP Facility,
which were used
F-12
<PAGE> 192
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
primarily for working capital purposes and to support the acquisition of oil and
gas properties through volumetric production payments.
SUBSEQUENT INFORMATION (UNAUDITED)
In July 1996, the Receivable Facility was paid in full and terminated. On
September 25, 1996, the Company consolidated the Master Note Facility and the
VPP Facility to create one Revolving Credit Facility (the "Credit Facility"),
which will mature on September 30, 2000. The Credit Facility is secured by the
same collateral that was pledged to secure the Master Note and VPP facilities.
The borrowing base under the Credit Facility is a function of the lender's
determination of the value of the Company's oil and gas reserves, and is
currently limited to $75 million under the terms of the Indenture. As of
December 31, 1996, $0.1 million was outstanding under the Credit Facility. The
Credit Facility bears interest at a spread over the prime rate or LIBOR,
determined each quarter based on the Company's consolidated debt-to-EBITDA
ratio. As of January 29, 1997, following the Medallion Acquisition, $74.5
million was outstanding under the Credit Facility.
In October 1996, the Company exercised its option to purchase the Warrant
issued in connection with the Note financing.
Simultaneous with the Medallion Acquisition, the Company entered into a new
revolving credit agreement ("Revolving Credit Agreement") with a group of banks.
Of the Revolving Credit Agreement's $135 million initial borrowing base, $30
million is structured as a term loan with a maturity of March 31, 1997; the
remaining $105 million revolving loan matures on September 30, 2000. The
Company's obligations under the Revolving Credit Agreement are secured by
substantially all of the oil and gas assets of Medallion and a pledge of
Medallion's common stock. The Revolving Credit Agreement permits the Company to
borrow at interest rates based upon the banks' prime rate or LIBOR. The
applicable spread over the prime rate or LIBOR is determined each quarter based
on the Company's consolidated debt-to-EBITDA ratio. As of January 29, 1997,
following the Medallion Acquisition, $90.2 million was outstanding under the
Revolving Credit Agreement.
MASTER NOTE FACILITY
The Master Note Facility ("Facility"), which matures on October 1, 1998, is
used primarily for the expansion of the Company's exploration and production and
natural gas transportation businesses. As such, borrowings under the Facility
are limited to certain KCS subsidiaries ("Borrowers") which are engaged in those
activities. The borrowing base, or actual availability under the Facility,
increased from $64 million at December 31, 1994 to $100 million at December 31,
1995. As of December 31, 1995, $76.3 million was outstanding under the facility
and $11.1 million was reserved pursuant to the existing letters of credit. The
borrowing base is reviewed at least semiannually and may be adjusted based on
the lenders' valuation of the Borrowers' oil and gas reserves, pipeline assets
and other factors. Substantially all of the Borrower's oil and gas reserves
(excluding those acquired through volumetric production payments) and pipeline
assets have been pledged to secure the Facility.
The Facility permits the Borrowers to choose interest rate options based on
the bank's prime rate or LIBOR and from maturities ranging up to three months. A
commitment fee of one-half of one percent is paid on the unused portion of the
borrowing base. The weighted average effective interest rate was 6.13% in 1994
and 7.98% in 1995. As of December 31, 1995, the weighted average effective
interest rate on the borrowings was 8.66%.
Immediately following the sale of the Senior Notes, the Facility was
amended to decrease the borrowing base to $20 million and the amount outstanding
under the Facility was reduced to $2 million and $11.1 million was reserved
pursuant to existing letters of credit.
F-13
<PAGE> 193
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
REVOLVING CREDIT FACILITIES
Revolving Credit Agreement
During 1994, the Company's natural gas marketing subsidiary had a revolving
credit agreement ("Agreement") that was used primarily for working capital
purposes and the purchase of oil and gas reserves through volumetric production
payments and was secured by that subsidiary's trade accounts receivable and
other assets.
The Agreement was replaced with two new revolving credit facilities, the
Receivables Facility and the VPP Facility. At December 31, 1994, $15.4 million
was reflected as outstanding under the Agreement. On January 12, 1995, the
Company paid in full all outstanding balances and terminated the Agreement. The
weighted average effective interest rate was 7.97% in 1994 and 8.87% in 1995.
Receivables Facility
The Receivables Facility matures in June 1997 and is secured by the natural
gas marketing subsidiary's accounts receivables and other assets (excluding
those pledged under the VPP Facility) and a pledge of the natural gas marketing
subsidiary's stock. In August 1995, the maximum credit limit under the
Receivables Facility was increased from the initial $25 million to $35 million.
Under the terms of the Receivables Facility, the subsidiary may borrow the
lesser of the credit limit or the borrowing base supported by Eligible
Receivables, as defined by the lender. The borrowing base is reviewed on a
monthly basis. As of December 31, 1995, the borrowing base and outstanding
balance was $26.9 million.
The Company may choose to borrow funds based on either the lender's "Base
Rate" or the 30-day LIBOR. A commitment fee of one-half of one percent is paid
on the average daily unused portion of the credit limit. The weighted average
effective interest rate was 7.64% in 1995. On December 31, 1995, the weighted
average effective interest rate on outstanding borrowings was 7.60%.
Proceeds from the sale of the Senior Notes were used to decrease the amount
outstanding under the Receivables Facility to $23.4 million. The borrowing base
of the Receivables Facility was unaffected by the sale of the Senior Notes.
VPP Facility
The VPP Facility matures in January 1999 and is secured by all of the oil
and gas reserves purchased through volumetric production payments. The initial
maximum credit commitment under this facility of $25 million was increased in
December 1995 to $50 million and the borrowing base was increased to $38
million. The borrowing base is reviewed at least semiannually and may be subject
to change based upon the lenders' evaluation of the oil and gas reserves and
other factors. The outstanding balance under the VPP Facility was $38 million on
December 31, 1995.
Under the VPP Facility, the Company can request advances based upon either
the prime rate, certificates of deposit rate or LIBOR with maturities ranging up
to three months. A commitment fee of one-half of one percent is paid on the
average daily unused portion of the borrowing base. The weighted average
effective interest rate was 8.17% in 1995. As of December 31, 1995, the weighted
average effective interest rate on outstanding borrowings was 8.11%.
Proceeds from the sale of the Senior Notes were used to decrease the amount
outstanding under the VPP Facility to $1.0 million. The VPP Facility's borrowing
base was unaffected by the sale of the Senior Notes.
F-14
<PAGE> 194
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE FINANCING
On November 17, 1995, the Parent entered into a $25 million Note Financing
Agreement ("Note Financing"), secured by all of the assets of the Parent other
than the capital stock of its marketing subsidiary. The proceeds from the Note
Financing were used to fund the Company's oil and gas property acquisitions and
for general corporate purposes.
The Note Financing, which was paid in full with the proceeds of the Senior
Notes, accrued interest at the rate of 12% per annum.
The Parent also issued to the purchaser under the Note Financing (with an
option to buy back at 150% of the exercise price within 12 months and 175%
between 12 and 24 months) a warrant to purchase 114,683 shares of the Parent's
common stock exercisable at a price of $11.65 per share, subject to adjustment
to prevent dilution. In October 1996, the Company exercised its option to
purchase the warrant issued in connection with the Note financing.
OTHER INFORMATION
KCS Energy, Inc. has guaranteed the obligations of its subsidiaries under
the above agreements. The agreements contain certain restrictive covenants
which, among other things, require the Company to maintain minimum levels of
working capital, cash flow and tangible net worth, as defined in the agreements.
In addition, the Company is restricted from incurring secured indebtedness under
designated credit facilities in an amount which is the greater of $75 million or
15% of adjusted consolidated net tangible assets (as defined in the Indenture).
This restriction does not apply to purchase money indebtedness. The Company's
ability to pay cash dividends is limited by the Indenture and existing credit
facilities.
The Company had a subordinated short-term note payable, which was issued in
conjunction with a 1993 acquisition of producing properties. The balance was
paid in full during fiscal year 1995. This note, payable in monthly
installments, accrued interest at prime plus one percent.
Long-term debt is carried at an amount approximating fair value because its
interest rates are based on current market rates.
Long-term debt due during the fiscal years ending December 31, 1996 to
2000, is as follows: $-0- in 1996, $51,900,000 in 1997, $76,255,000 in 1998,
$38,000,000 in 1999 and $-0- in 2000. Reflecting the issuance of the Senior
Notes on January 25, 1996 and the repayment of amounts outstanding on the Master
Note Facility, the Receivables Facility and the VPP Facility, long-term debt due
during the fiscal years ending December 31, 1996 to 2000, is as follows: $-0- in
1996, $23.4 million in 1997, $2 million in 1998, $1 million in 1999 and $-0-
million in 2000. Interest payments were $1,819,000 in 1993, $2,088,000 in 1994
and $6,757,000 in 1995. Interest payments were $4,406,000 and $10,793,000 for
the nine months ended September 30, 1995 and September 30, 1996, respectively.
5. LEASES
Future minimum lease payments under non-cancelable operating leases are as
follows: $558,000 in 1996, $548,000 in 1997, $537,000 in 1998, $421,000 in 1999
and $337,000 in 2000.
Lease payments charged to operating expenses amounted to $579,000, $598,000
and $466,000 during 1993, 1994 and 1995, respectively.
F-15
<PAGE> 195
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
6. INCOME TAXES
Federal and state income tax expense includes the following components:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER
31,
-------------------------------
1993 1994 1995
------- ------- -------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Currently payable........................................... $ 6,316 $ 1,039 $ 1,216
Deferred provision, net..................................... 1,428 10,692 8,296
Amortization of investment tax credits...................... (73) -- --
------- ------- -------
Federal income tax expense.................................. 7,671 11,731 9,512
State income taxes (deferred provision $12 in 1993, $204 in
1994 and $1,460 in 1995).................................. 239 825 1,064
------- ------- -------
$ 7,910 $12,556 $10,576
======= ======= =======
Sources of deferred federal and state income taxes:
Intangible drilling costs................................. $ 3,708 $10,278 $12,619
Revenue recognition deferred.............................. -- 2,343 1,854
Depreciation, depletion and amortization.................. (814) (1,883) (5,579)
Tax credit carry forwards and other, net.................. (1,454) 158 862
------- ------- -------
$ 1,440 $10,896 $ 9,756
======= ======= =======
Reconciliation of federal income tax expense at statutory
rate to provision for income taxes:
Income before income taxes................................ $26,521 $36,713 $31,882
Tax provision at 35% statutory rate....................... 9,282 12,850 11,159
State income tax, net of federal income tax benefit....... 151 537 692
Statutory depletion....................................... (620) (696) (676)
Section 29 credits........................................ (537) (388) (425)
Other, net................................................ (366) 253 (174)
------- ------- -------
$ 7,910 $12,556 $10,576
======= ======= =======
</TABLE>
The primary differences giving rise to the Company's deferred tax assets
and liabilities are as follows:
<TABLE>
<CAPTION>
DECEMBER 31, 1995
----------------------
ASSETS LIABILITIES
------ -----------
(DOLLARS IN THOUSANDS)
<S> <C> <C>
Income tax effects of:
Accelerated DD&A and other property related items..................... -- $ 24,261
Alternative minimum tax credit carry forwards......................... $3,175 --
Deferred revenue...................................................... -- 4,197
Other, net............................................................ -- 889
------ -------
$3,175 $ 29,347
====== =======
</TABLE>
Income tax payments were $1,729,500 in 1993 and $1,302,000 in 1994. No
income tax payments were made in 1995. The Company received federal incone tax
refunds of $233,000 and $58,000 in 1993 and 1994, respectively, related to
fiscal year 1992 and 1993 overpayments. No income tax payments
F-16
<PAGE> 196
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
were made during the nine months ended September 30, 1995. Income tax payments
were $4,545,000 during the nine months ended September 30, 1996.
The alternative minimum tax credit carryforwards of $3,175,000, which can
be carried forward indefinitely, are available to reduce the Company's future
federal income tax liabilities.
7. CONTINGENCIES
Tennessee Gas Litigation -- Recent Events (unaudited)
Most of the Company's natural gas sold from the Bob West Field in south
Texas was covered by an above-market, take-or-pay contract (the "Tennessee Gas
Contract") with Tennessee Gas Pipeline Company ("Tennessee Gas"), which had been
the subject of several lawsuits. On December 23, 1996, the Company and Tennessee
Gas entered into a settlement covering all claims and litigation between them
related to the Tennessee Gas Contract. As part of the settlement, the Tennessee
Gas Contract was terminated effective January 1, 1997, approximately two years
prior to its expiration date. The parties also agreed to the dismissal of the
contract dispute that resulted in a November 1996 jury award to Tennessee Gas of
$143.2 million (including $114 million in punitive damages). The early
termination of the Tennessee Gas Contract with its above-market pricing
provisions resulted in downward revisions in the amounts of $59.5 million for
estimated future net revenues before income taxes (based upon a natural gas
price of $2.10 per Mcf, the assumed realized spot market price on June 30, 1996)
and $51.4 million for PV-10, as compared to prior reserve reports prepared as of
June 30, 1996. Except for the revisions to future net revenues, the Company's
financial statements will not be directly affected as a result of the settlement
and early termination of the contract.
The December 1996 settlement did not affect the Company's successful
conclusion of litigation earlier in the year relating to the validity and
pricing provisions of the Tennessee Gas Contract and its recovery of past
underpayments (including interest and net of severance taxes and other payables
related to the contract) that had accrued under the contract. On September 30,
1996, Tennessee Gas paid the Company approximately $70 million, representing the
amount of the Tennessee Gas Receivable at that date.
On April 18, 1996 the Texas Supreme Court granted the petitioners' request
for a rehearing, withdrew its August 1, 1995 opinion and issued a new opinion on
the previously disclosed litigation relating to the Tennessee Gas Contract. In
its April 18, 1996 opinion, the Texas Supreme Court affirmed the Company's
position on all issues, stating that the price payable by Tennessee Gas
escalates monthly in accordance with Section 102(b)(2) of the Natural Gas Policy
Act of 1978 ("NGPA") ($8.53 per MMBtu in September 1996 plus reimbursement of
severance taxes); that KCS has the right to pool the leases; that Tennessee Gas
has no legal or contractual right to question or determine whether certain
leases are no longer committed to the Tennessee Gas Contract; and the Tennessee
Gas Contract is not an output contract governed by Section 2.306 of the Texas
Uniform Commercial Code. Tennessee Gas filed a motion requesting another
rehearing on June 3, 1996 and on August 16, 1996 the Texas Supreme Court denied
Tennessee Gas' motion. On September 30, 1996 the Company recovered approximately
$70 million that Tennessee Gas previously withheld under a series of interim
agreements, which was the balance of the purchase price for production taken by
Tennessee Gas from September 17, 1994 through April 30, 1996, plus interest as
provided for in the Tennessee Gas Contract. The terms of the Tennessee Gas
Contract, in accordance with judicial rulings in the case, governed performance
by each of the parties through the termination of the contract effective January
1, 1997.
F-17
<PAGE> 197
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Tennessee Gas Litigation -- Background
In August 1990, in the District Court of Bexar County, Texas ("District
Court"), Tennessee Gas filed suit against the Company and its co-sellers
claiming among other things that the price of natural gas under the Tennessee
Gas Contract should be determined under Section 101 of the NGPA rather than
Section 102(b)(2), that certain leases were no longer subject to the contract,
that for purposes of the contract the acreage subject to the contract could not
be pooled with other properties and that the contract was governed by Section
2.306 of the Texas Uniform Commercial Code ("Section 2.306"). In July 1992, the
District Court ruled in favor of the Company on all of these issues and awarded
damages for past underpayments and legal fees. The District Court's judgment was
partially affirmed by the Court of Appeals, which held that the price of natural
gas under the contract was to be determined in accordance with Section
102(b)(2), that all leases were subject to the contract, and that pooling of the
property with a pro rata acreage allocation of production to the contract was in
accordance with the contract. However, the Court of Appeals reversed the
District Court's summary judgment holding that the Tennessee Gas Contract was
not an output contract subject to Section 2.306. Under the Court of Appeals
decision, new wells could be drilled and production increased, but any
production increase had to have complied with certain good faith and
reasonableness standards mandated by Section 2.306. The Court of Appeals also
set aside the District Court's awards to the Company of legal fees and past
underpayments pending the outcome of the trial on the Section 2.306 issue.
On August 1, 1995, the Texas Supreme Court affirmed the ruling of the Court
of Appeals, including its decision that Section 2.306 was applicable to the
Tennessee Gas Contract. The Texas Supreme Court remanded to the District Court
for plenary trial the question of whether, as required by Section 2.306, natural
gas volumes taken by Tennessee Gas under the contract were produced and
delivered in good faith and were not unreasonably disproportionate to a normal
or otherwise comparable prior output or the expectation of the parties. The
Company filed a request on September 15, 1995 for a rehearing in the Texas
Supreme Court of the Section 2.306 issue.
In connection with a District Court judgment, since September 1994
Tennessee Gas has posted supersedeas bonds totaling $206 million and executed
interim agreements with the Company and its co-sellers under which it pays $3.00
per MMBtu, currently, for natural gas delivered, and has agreed to take monthly
no less than 85% of the delivery capacity, if available, of the wells covered by
the Tennessee Gas Contract for the term of the interim agreement, or until
mandate issues. The excess of $3.00 per MMBtu over the market price for natural
gas delivered since August 1, 1995 (but not for the earlier deliveries) is
refundable to Tennessee Gas to the extent required by a final judgment against
the Company. The acceptance of the $3.00 per MMBtu does not constitute any
waiver by the Company to its claim for the full contract price for all natural
gas taken by Tennessee Gas. The last interim agreement, remained in effect until
April 30, 1996.
Prior to September 17, 1994, Tennessee Gas had been paying a price for
natural gas production from the dedicated leases based on Section 102(b)(2) of
the NGPA, plus reimbursement for severance taxes, subject to the right to
recover any excess price if ultimately successful in the litigation. As of
December 31, 1995, the Company had recorded cumulative revenue of approximately
$155 million for natural gas sold under the Tennessee Gas Contract based on the
prices as defined in the contract, of which approximately $112 million
(approximately $61 million of which has been received by the Company) is at
issue in the litigation. The Company continues to accrue an accounts receivable
amount due from Tennessee Gas that reflects the difference between the amount
paid for natural gas under the interim agreements between the parties and the
price that would have been paid pursuant to the terms of the Tennessee Gas
Contract. At December 31, 1995, such receivable (which includes accrued interest
as provided for in the contract and is net of deferred severance taxes and other
payables) was $56.4 million.
F-18
<PAGE> 198
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
SUBSEQUENT INFORMATION (UNAUDITED)
Royalty Suits -- Background
The Company is a party to three lawsuits involving the holders of royalty
interests on the acreage that was covered by the Tennessee Gas Contract. The
Company is a co-plaintiff in the first of these lawsuits that was filed in
Dallas County, Texas, and is a defendant in the other subsequently filed suits
in Zapata County, Texas. The basis of these declaratory judgment actions is the
royalty holders' claim that their royalty payments should be based on the price
paid by Tennessee Gas for the natural gas purchased by it under the Tennessee
Gas Contract. The Company has been paying royalties for this natural gas based
upon the spot market price. Because the leases have market-value royalty
provisions, the Company believes it is in full compliance under the leases with
its royalty holders. The amount at issue in these cases cannot be determined at
this time as it is a function of the quantity of natural gas for which Tennessee
Gas ultimately is obligated to pay at the contract price at the resolution of
the Tennessee Gas litigation described above. As of December 31, 1995, the
amount of natural gas taken by Tennessee Gas attributable to these royalty
interests was approximately 3.1 Bcf, for which royalties have been paid by the
Company at the average spot price of approximately $1.71 per Mcf, net of
severance tax, compared to the average contract price of approximately $7.50 per
Mcf, net of severance tax. Consequently, if the Company prevails in its
litigation with Tennessee Gas, but loses in its litigation with these royalty
interest owners, the Company faces a maximum liability in this litigation of
approximately $17.9 million.
Royalty Suits -- Recent Events (unaudited)
The Company's position has recently been confirmed in the Dallas suit where
the trial judge has granted the co-plaintiffs' motions for summary judgment on
this issue. In addition, the trial judge has granted summary judgment against
the royalty owners with respect to their various counterclaims against the
co-plaintiffs as concerns the jointly-owned Guerra "A" and Guerra "B" units.
However, the royalty owners also separately counterclaimed against the Company
with respect to the Jesus Yzaguirre unit, asserting that the largest lease
contained therein had terminated in December, 1975 and that certain of the
royalty owners were entitled to the Tennessee Gas Contract price because of
their execution of certain division orders in 1992 that allegedly varied the
market-value royalty provision of their lease. The trial judge has not yet ruled
on the parties' motions for summary judgment concerning these issues, although
he has granted the Company's motion for summary judgment that the royalty
holders' leases require that royalties be based upon the market value of the
natural gas at the lease when produced and sold, not the price paid for the
natural gas under the Tennessee Gas Contract.
Other Legal Proceedings
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 cannot be predicted with certainty, management does
not expect such matters to have a material adverse effect, either singly or in
the aggregate, on the financial position of the Company.
F-19
<PAGE> 199
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
8. QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
FISCAL QUARTERS
-----------------------------------------------
FIRST SECOND THIRD FOURTH
-------- -------- -------- --------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
1994
Revenue..................................... $ 85,173 $ 84,491 $ 80,743 $ 91,306
Operating Income............................ 9,380 11,135 6,076 12,021
Net Income.................................. 6,170 6,915 3,977 7,095
Earnings Per Common Share................... $ 0.52 $ 0.58 $ 0.34 $ 0.60
1995
Revenue..................................... $ 96,039 $126,556 $109,679 $117,691
Operating Income............................ 10,184 9,306 6,438 9,973
Net Income.................................. 6,219 5,377 4,086 5,624
Earnings Per Common Share................... $ 0.53 $ 0.46 $ 0.35 $ 0.48
1996
Revenue..................................... $146,557 $ 96,487 $ 73,560 --
Operating Income............................ 12,373 10,751 9,057 --
Net Income.................................. 5,855 4,987 3,964 --
Earnings Per Common Share................... $ 0.50 $ 0.42 $ 0.33 --
</TABLE>
F-20
<PAGE> 200
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. FINANCIAL INFORMATION BY BUSINESS SEGMENT
The following financial information has been provided for the business
segments of the Company:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
----------------------------------
1993 1994 1995
-------- -------- --------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Revenue
Oil and Gas Exploration and Production................ $ 40,455 $ 66,215 $ 86,629
Natural Gas Transportation and Marketing.............. 264,710 279,155 365,354
Intercompany.......................................... (876) (3,657) (2,018)
------- -------- --------
$304,289 $341,713 $449,965
======= ======== ========
Operating Income
Oil and Gas Exploration and Production................ $ 26,655 $ 37,943 $ 39,645
Natural Gas Transportation and Marketing.............. 3,578 2,889 (1,349)
------- -------- --------
30,233 40,832 38,296
Corporate Expenses.................................... (2,433) (2,220) (2,395)
Interest and Other Income, net........................ 704 1,039 3,713
Interest Expense...................................... (1,983) (2,938) (7,732)
------- -------- --------
Income Before Income Taxes............................ $ 26,521 $ 36,713 $ 31,882
======= ======== ========
Identifiable Assets
Oil and Gas Exploration and Production................ $ 94,266 $151,571 $274,474
Natural Gas Transportation and Marketing.............. 68,406 60,573 78,331
Corporate and Other................................... 3,318 2,279 7,804
------- -------- --------
$165,990 $214,423 $360,609
======= ======== ========
Depreciation, Depletion and Amortization
Oil and Gas Exploration and Production................ $ 7,004 $ 18,538 $ 37,988
Natural Gas Transportation and Marketing.............. 998 1,178 1,157
Other................................................. 34 24 64
------- -------- --------
$ 8,036 $ 19,740 $ 39,209
======= ======== ========
Capital Expenditures
Oil and Gas Exploration and Production................ $ 46,667 $ 73,870 $122,554
Natural Gas Transportation and Marketing.............. 1,773 942 6,085
Other................................................. 15 141 60
------- -------- --------
$ 48,455 $ 74,953 $128,699
======= ======== ========
</TABLE>
10. OIL AND GAS PRODUCING OPERATIONS
The following data is presented pursuant to FASB Statement No. 69 with
respect to oil and gas acquisition, exploration, development and producing
activities, which is based on estimates of year-end oil and gas reserve
quantities and forecasts of future development costs and production schedules.
These estimates and forecasts are inherently imprecise and subject to
substantial revision as a result of changes in estimates of remaining volumes,
prices, costs, and production rates.
F-21
<PAGE> 201
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Except where otherwise provided by contractual agreement, future cash
inflows are estimated using year-end prices. Oil and gas prices at December 31,
1995 are not necessarily reflective of the prices the Company expects to receive
in the future.
Volumetric production payment volumes represent oil and gas reserves
purchased from third parties which entitle the Company to a specified volume of
oil and gas to be delivered over a stated time period. The related volumes
stated herein reflect scheduled amounts of oil and gas to be delivered to the
Company at agreed delivery points, and are stated at year-end prices. The
Company does not bear any development or lease operating expenses associated
with the volumetric production payments.
PRODUCTION REVENUES AND COSTS
Information with respect to production revenues and costs related to oil
and gas producing activities is as follows:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
-------------------------------------
1993 1994 1995
--------- --------- ---------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Revenue.............................................. $ 39,918 $ 65,773 $ 85,424
Production (lifting) costs........................... 5,011 7,063 6,623
Technical support and other.......................... 1,785 2,671 2,373
Depreciation, depletion and amortization............. 6,944 18,538 37,859
------- ------- -------
Total expenses............................. 13,740 28,272 46,855
------- ------- -------
Pretax income from producing activities.............. 26,178 37,501 38,569
Income taxes......................................... 8,005 12,041 12,549
------- ------- -------
Results of oil and gas producing activities
(excluding corporate overhead and interest)........ $ 18,173 $ 25,460 $ 26,020
======= ======= =======
Capitalized costs incurred:
Property acquisition............................... $ 18,563 $ 27,772 $ 77,515
Exploration........................................ 3,787 12,599 16,891
Development........................................ 24,249 33,311 26,859
------- ------- -------
Total capitalized costs incurred................ $ 46,599 $ 73,682 $ 121,265
======= ======= =======
Capitalized costs at year-end:
Proved properties.................................. $ 98,369 $ 169,624 $ 284,597
Unproved properties................................ 2,647 5,074 7,297
------- ------- -------
101,016 174,698 291,894
Accumulated depreciation, depletion and
amortization....................................... (30,539) (49,077) (86,936)
------- ------- -------
Net investment in oil and gas producing properties... $ 70,477 $ 125,621 $ 204,958
======= ======= =======
</TABLE>
DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)
The following information relating to discounted future net cash flows has
been prepared on the basis of the Company's estimated net proved oil and gas
reserves in accordance with FASB Statement No. 69. A significant portion of the
discounted future net cash flows presented below is attributable to the Bob West
Field where gas is committed under the Tennessee Gas Contract, which was
terminated effective January 1, 1997 (see Note 7).
F-22
<PAGE> 202
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------
1994 1995
-------- ---------
(DOLLARS IN
THOUSANDS)
<S> <C> <C>
Future cash inflows................................................... $371,323 $ 521,914
Future costs:
Production.......................................................... (44,795) (94,880)
Development......................................................... (18,995) (21,985)
Discount -- 10% annually............................................ (65,828) (113,964)
------- --------
Present value of future net revenues................................ 241,705 291,085
Future income taxes, discounted at 10%.............................. (62,045) (59,322)
------- --------
Standardized measure of discounted future net cash flows.............. $179,660 $ 231,763
======= ========
</TABLE>
CHANGES IN DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVE QUANTITIES
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
----------------------------------
1993 1994 1995
-------- -------- --------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Balance, beginning of year.............................. $106,993 $160,884 $179,660
Increases (decreases)
Sales, net of production costs........................ (34,907) (58,710) (78,801)
Net change in prices, net of production costs......... (7,648) (11,180) 9,593
Discoveries and extensions, net of future production
and development costs.............................. 75,365 26,930 22,417
Changes in estimated future development costs......... (1,862) (9,622) (862)
Change due to acquisition of reserves in place........ 23,665 26,038 108,798
Development costs incurred during the period.......... 3,371 13,924 9,672
Revisions of quantity estimates....................... (15,791) 1,532 (19,256)
Accretion of discount................................. 14,600 21,017 24,033
Net change in income taxes............................ (10,279) (12,060) 2,021
Sales of reserves in place............................ -- -- (1,931)
Changes in production rates (timing) and other........ 7,377 20,907 (23,581)
-------- -------- --------
Net increase.......................................... 53,891 18,776 52,103
-------- -------- --------
Balance, end of year.................................... $160,884 $179,660 $231,763
======== ======== ========
</TABLE>
RESERVE INFORMATION (UNAUDITED)
The following information with respect to the Company's estimated net
proved oil and gas reserves are estimates based on reports prepared by
independent reserve engineers (principally R.A. Lenser and Associates, Inc. and
H.J. Gruy and Associates, Inc.). Proved developed reserves represent only those
reserves expected to be recovered through existing wells using equipment
currently in place. Proved undeveloped reserves represent proved reserves
expected to be recovered from new wells or from existing wells after material
recompletion expenditures. All of the Company's reserves are located within the
United States.
F-23
<PAGE> 203
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
1993 1994 1995
----------------- ----------------- -----------------
GAS OIL GAS OIL GAS OIL
MMCF MBBL MMCF MBBL MMCF MBBL
------ ------ ------- ----- ------- -----
<S> <C> <C> <C> <C> <C> <C>
Proved developed and undeveloped
reserves
Balance, beginning of year....... 52,029 1,333 69,740 2,578 89,184 2,319
Production....................... (6,977) (179) (11,304) (211) (19,129) (196)
Discoveries, extensions, etc..... 14,066 972 10,924 33 10,399 202
Acquisition of reserves in
place.......................... 10,043 1,684 18,206 148 71,560 5,449
Sales of reserves in place....... -- -- -- -- (3,751) (3)
Revisions of estimates........... 579 (1,232) 1,618 (229) (7,300) (254)
------ ------ ------- ----- ------- -----
Balance, end of year............. 69,740 2,578 89,184 2,319 140,963 7,517
====== ====== ======= ===== ======= =====
Proved developed reserves
Balance, beginning of year..... 39,140 1,095 61,016 1,579 74,215 1,336
------ ------ ------- ----- ------- -----
Balance, end of year........... 61,016 1,579 74,215 1,336 121,987 3,808
====== ====== ======= ===== ======= =====
</TABLE>
Proved gas reserves at December 31, 1995 include 31.7 Bcf (including 28.7
Bcf proved, developed) attributable to the Bob West Field, where gas is
committed under the Tennessee Gas Contract. The Tennessee Gas Contract was
terminated effective January 1, 1997 (see Note 7).
11. RECENT ACQUISITIONS
On November 8, 1995, the Company acquired substantially all of the oil and
gas assets of Natural Gas Processing Company (the "Rocky Mountain Acquisition")
for $33 million, subject to adjustments for a July 1, 1995 effective date. The
purchase was financed principally through the Master Note Facility. The Company
also acquired a significant inventory of oil and gas equipment and supplies,
vehicles and buildings as well as natural gas gathering systems consisting of
approximately 200 miles of pipeline.
On December 7, 1995, the Company acquired reserves in the northern and
southern Niagaran Reef trend in Michigan for $31 million, including a volumetric
production payment covering certain reserves, escalating working interests in
related properties and participation rights and an overriding royalty interest
in an exploration program (collectively, the "Michigan Acquisition"). The
volumetric production payment provides for the delivery to the Company of
certain oil and gas reserves totaling 20.3 Bcfe through January 31, 2006 without
any burden of operating costs. The Michigan Acquisition was financed through the
VPP Facility and the Note Financing.
These acquisitions were accounted for using the purchase method. The
results of operations for the acquired entities are included in the Company's
consolidated results of operations from the dates of acquisition.
F-24
<PAGE> 204
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following is the unaudited pro forma revenue, net income and earnings
per share giving effect to the Rocky Mountain and Michigan Acquisitions for the
years ended December 31, 1995 and 1994, as if such transactions had occurred at
the beginning of such years. The unaudited pro forma financial data do not
purport to be indicative of the financial position or results of operations that
would actually have occurred if the transactions had occurred as presented or
that may be obtained in the future.
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
---------------------
1994 1995
-------- --------
(DOLLARS IN
THOUSANDS,
EXCEPT PER SHARE
DATA)
<S> <C> <C>
Revenue...................................................... $356,748 $465,000
Net income................................................... $ 24,512 $ 21,661
Earnings per common share.................................... $ 2.08 $ 1.84
</TABLE>
12. SUBSEQUENT EVENT (UNAUDITED)
Medallion Acquisition
As of December 31, 1996, the Company completed the arrangements for the
acquisition of all of the outstanding stock of the Medallion entities, indirect
wholly-owned subsidiaries of MidAmerican Energy Holdings Company
("MidAmerican"), for a purchase price of approximately $214.4 million,
consisting of a cash payment of $209.4 million (reduced at the January 2, 1997
closing by $15.3 million principally to reflect free cash flow from the
Medallion entities' operations subsequent to July 1, 1996 effective date) and
warrants to purchase 435,000 shares of Common Stock.
Medallion's principal assets are 202.1 Bcfe proved oil and gas reserves
estimated as of June 30, 1996 by an independent reserve engineer, Ryder Scott
Company, consisting of 161.3 Bcf of natural gas (80% of total proved reserves)
and 6.8 MMbbls of oil and condensate. These reserves are located primarily in
the Mid-Continent region encompassing west Texas, the Texas panhandle, northwest
Oklahoma and north Louisiana. Proved developed reserves account for 88% of
Medallion's total proved reserves and the average reserve life at year-end 1995
was 8.0 years. The Medallion Acquisition will more than double the Company's
reserve base and add substantial management and technical expertise,
particularly in the new Mid-Continent core operating area.
F-25
<PAGE> 205
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and Boards of Directors of InterCoast
Oil and Gas Company, InterCoast Gas Services
Company and GED Energy Services, Inc.:
We have audited the accompanying combined balance sheets of the InterCoast
Entities (see Note 1) as of December 31, 1994 and 1995, and the related combined
statements of income, changes in stockholders' equity and cash flows for each of
the three years in the period ended December 31, 1995. These combined financial
statements are the responsibility of the InterCoast Entities' management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. 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 financial position of the InterCoast Entities as
of December 31, 1994 and 1995, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 1995, in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Tulsa, Oklahoma
October 30, 1996
F-26
<PAGE> 206
THE INTERCOAST ENTITIES
COMBINED STATEMENTS OF INCOME
(IN THOUSANDS)
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------- --------------------
1993 1994 1995 1995 1996
------- ------- ------- ------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenue
Gas and oil revenues.............. $37,359 $44,466 $48,109 $34,624 $ 51,229
Natural gas sales revenues........ 16,715 13,700 25,351 6,561 108,635
Gathering system revenues......... -- -- -- -- 644
------- ------- ------- ------- --------
54,074 58,166 73,460 41,185 160,508
------- ------- ------- ------- --------
Operating costs and expenses
Gas and oil operating expenses.... 9,616 15,016 14,552 10,920 12,367
Cost of gas sold.................. 16,216 13,142 24,361 6,139 106,546
Gathering system expenses......... -- -- -- -- 109
Other operating and administrative
expenses....................... 2,268 2,713 2,658 1,679 3,407
Depreciation, depletion and
amortization................... 13,672 18,782 21,705 15,953 20,360
------- ------- ------- ------- --------
41,772 49,653 63,276 34,691 142,789
------- ------- ------- ------- --------
Interest expense.................... -- -- -- -- 992
Income before income taxes.......... 12,302 8,513 10,184 6,494 16,727
Provision for income taxes.......... 5,383 3,202 3,638 2,319 5,973
------- ------- ------- ------- --------
Net income..................... $ 6,919 $ 5,311 $ 6,546 $ 4,175 $ 10,754
======= ======= ======= ======= ========
</TABLE>
The accompanying notes to combined financial statements are an integral part of
these statements.
F-27
<PAGE> 207
THE INTERCOAST ENTITIES
COMBINED BALANCE SHEETS
(IN THOUSANDS EXCEPT SHARE AND PER SHARE AMOUNTS)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------- SEPTEMBER 30,
1994 1995 1996
-------- -------- -------------
(UNAUDITED)
<S> <C> <C> <C>
Current assets
Cash and cash equivalents.............................. $ 5,124 $ 8,323 $ 3,542
Trade accounts receivable.............................. 6,586 24,101 29,740
Other.................................................. 2,311 1,383 2,332
-------- -------- --------
Total current assets........................... 14,021 33,807 35,614
Gas and oil properties, net.............................. 141,070 158,597 199,427
Gas gathering system..................................... -- -- 2,950
Other property, net...................................... 754 872 1,174
Intangible and other assets, net......................... 1,840 3,511 5,066
-------- -------- --------
Total assets................................... $157,685 $196,787 $ 244,231
======== ======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable....................................... $ 3,104 $ 18,702 $ 21,461
Other current liabilities.............................. 993 3,625 4,187
-------- -------- --------
Total current liabilities...................... 4,097 22,327 25,648
-------- -------- --------
Accumulated deferred income taxes, net................... 13,541 25,088 31,866
-------- -------- --------
Long-term debt due to MidAmerican Capital................ -- -- 52,402
Stockholders' equity, per accompanying statements
Common stock, InterCoast Oil and Gas Company ($1 par
value, 1,000 shares authorized, issued and
outstanding)........................................ 1 1 1
Common stock, InterCoast Gas Services Company ($1 par
value, 1,000 shares authorized, issued and
outstanding)........................................ 1 1 1
Common stock, GED Energy Services, Inc. ($1 par value,
0, 1,000 and 1,000 shares authorized, issued and
outstanding at December 31, 1994 and 1995 and
September 30, 1996)................................. -- 1 1
Additional paid-in capital............................. 123,802 126,580 100,769
Retained earnings...................................... 16,243 22,789 33,543
-------- -------- --------
Total stockholders' equity..................... 140,047 149,372 134,315
-------- -------- --------
Total liabilities and stockholders' equity..... $157,685 $196,787 $ 244,231
======== ======== ========
</TABLE>
The accompanying notes to combined financial statements are an integral part of
these statements.
F-28
<PAGE> 208
THE INTERCOAST ENTITIES
COMBINED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMMON STOCK
--------------------------------------------------
INTERCOAST OIL ADDITIONAL COMBINED
AND INTERCOAST GAS GED ENERGY PAID-IN RETAINED STOCKHOLDERS'
GAS COMPANY SERVICES COMPANY SERVICES, INC. CAPITAL EARNINGS EQUITY
-------------- ---------------- -------------- ---------- --------- -------------
<S> <C> <C> <C> <C> <C> <C>
Balance at December 31,
1992...................... $ 1 $ 1 $ -- $ 57,683 $ 4,013 $ 61,698
Net income.................. -- -- -- -- 6,919 6,919
Contributions from parent... -- -- -- 49,467 -- 49,467
-- -- --
-------- ------- --------
Balance at December 31,
1993...................... 1 1 -- 107,150 10,932 118,084
Net income.................. -- -- -- -- 5,311 5,311
Contributions from parent... -- -- -- 16,652 -- 16,652
-- -- --
-------- ------- --------
Balance at December 31,
1994...................... 1 1 -- 123,802 16,243 140,047
Formation of GED Energy
Services, Inc. ........... -- -- 1 -- -- 1
Net income.................. -- -- -- -- 6,546 6,546
Contributions from parent... -- -- -- 2,778 -- 2,778
-- -- --
-------- ------- --------
Balance at December 31,
1995...................... 1 1 1 126,580 22,789 149,372
Net income (unaudited)...... -- -- -- -- 10,754 10,754
Dividend to parent
(unaudited)............... -- -- -- (25,811) -- (25,811)
-- -- --
-------- ------- --------
Balance at September 30,
1996 (unaudited).......... $ 1 $ 1 $ 1 $ 100,769 $ 33,543 $ 134,315
==== ==== ==== ========= ======== =========
</TABLE>
The accompanying notes to combined financial statements are an integral part of
these statements.
F-29
<PAGE> 209
THE INTERCOAST ENTITIES
COMBINED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
---------------------------------- ---------------------
1993 1994 1995 1995 1996
-------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Cash flows from operating activities
Net income............................. $ 6,919 $ 5,311 $ 6,546 $ 4,175 $ 10,754
Adjustments to reconcile net income to
net cash from operating activities:
Deferred income taxes, net.......... 4,020 2,502 11,547 3,608 6,778
Provision for depreciation,
depletion and amortization........ 13,672 18,782 21,705 15,953 20,360
Change in working capital items:
Accounts receivable............... (2,791) 3,309 (17,515) (2,981) (5,639)
Other current assets.............. 296 (1,032) 928 (297) (949)
Accounts payable.................. 2,869 (2,782) 15,598 2,758 2,759
Other current liabilities......... 1,773 (1,840) 2,632 (291) 562
-------- -------- -------- -------- --------
Net cash from operating
activities................... 26,758 24,250 41,441 22,925 34,625
-------- -------- -------- -------- --------
Cash flows from investing activities
Investments in:
Gas and oil properties.............. (74,984) (42,849) (40,845) (30,059) (61,979)
Other............................... (460) (26) (2,004) (149) (4,173)
Proceeds from sale of gas and oil
properties........................ 1,495 3,465 1,829 1,829 155
-------- -------- -------- -------- --------
Net cash from investing
activities................... (73,949) (39,410) (41,020) (28,379) (65,997)
-------- -------- -------- -------- --------
Cash flows from financing activities
Borrowings from MidAmerican Capital.... -- -- -- -- 52,402
-------- -------- -------- -------- --------
Contributions from (dividends to)
parent.............................. 49,467 16,652 2,778 5,949 (25,811)
-------- -------- -------- -------- --------
Net cash from financing activities....... 49,467 16,652 2,778 5,949 26,591
-------- -------- -------- -------- --------
Net increase (decrease) in cash and cash
equivalents............................ 2,276 1,492 3,199 495 (4,781)
Cash and cash equivalents at beginning of
period................................. 1,356 3,632 5,124 5,124 8,323
-------- -------- -------- -------- --------
Cash and cash equivalents at end of
period................................. $ 3,632 $ 5,124 $ 8,323 $ 5,619 $ 3,542
======== ======== ======== ======== ========
Supplemental cash flow information
Cash paid (received) during the period
for:
Income taxes........................... $ 1,363 $ 700 $ (7,909) $ (1,233) $ (641)
======== ======== ======== ======== ========
</TABLE>
The accompanying notes to combined financial statements are an integral part of
these statements.
F-30
<PAGE> 210
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS
1. ACCOUNTING POLICIES
Corporate Structure
InterCoast Oil and Gas Company (InterCoast Oil and Gas, formerly Medallion
Production Company), a Delaware corporation, and InterCoast Gas Services
Company, a Delaware corporation, (InterCoast Gas Services -- Delaware) are
wholly-owned subsidiaries of InterCoast Energy Company (InterCoast Energy).
InterCoast Gas Services Company, an Oklahoma corporation, (InterCoast Gas
Services -- Oklahoma) and GED Energy Services, Inc., a Delaware corporation,
(GED) are wholly-owned subsidiaries of InterCoast Gas Services -- Delaware.
InterCoast Energy is a wholly-owned subsidiary of MidAmerican Capital Company
(MidAmerican Capital), which is wholly-owned by MidAmerican Energy Company
(MidAmerican Energy).
InterCoast Oil and Gas is primarily engaged in the acquisition,
development, exploration and production of natural gas and oil. InterCoast Gas
Services -- Oklahoma and GED are primarily engaged in the marketing of natural
gas.
Basis of Presentation
The accompanying financial statements reflect the combined operations of
InterCoast Oil and Gas, InterCoast Gas Services -- Oklahoma and GED
(collectively, the InterCoast Entities). The financial statements are presented
on a combined historical cost basis because the InterCoast Entities are under
common control and because InterCoast Energy and its wholly-owned subsidiary,
InterCoast Gas Services -- Delaware, have signed letters of intent to sell the
stock of the InterCoast Entities to KCS Energy, Inc. (see Note 10).
InterCoast Gas Services -- Delaware formed GED and acquired the assets of
GED Gas Services, L.L.C. effective November 1, 1995. The accompanying combined
financial statements include the results of GED for the period since the date of
such acquisition.
Intercompany and affiliated company accounts and transactions have been
eliminated in the combination. Since there is no parent-subsidiary relationship
between the InterCoast Entities, there is no basis for eliminating the equity
accounts of any of the entities.
The preparation of the financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reported period. Actual
results may differ from those estimates.
Oil and Gas Properties
The InterCoast Entities account for their gas and oil properties using the
full cost method of accounting which provides for the capitalization of all
acquisition, exploration and development costs incurred for the purpose of
finding natural gas and oil reserves. The unamortized cost of gas and oil
properties, including estimated future development and abandonment costs, is
amortized using the unit-of-production method based on the ratio of volumes
produced to proved reserves.
Unevaluated properties and associated costs not currently being amortized
and included in oil and gas properties were $1.5 million, $1.6 million and $2.1
million at December 31, 1993, 1994 and 1995, respectively and $3.3 million at
September 30, 1996. Such costs relate to projects which were at such dates
undergoing exploration or development activities or in which the InterCoast
Entities intend to commence such activities in the future. The InterCoast
Entities will begin to amortize these costs when proved reserves are established
or impairment is determined.
F-31
<PAGE> 211
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
The InterCoast Entities' unamortized costs of gas and oil properties are
limited to the sum of the future net revenues attributable to proved oil and gas
reserves discounted at ten percent plus the cost of any unproved properties. If
the InterCoast Entities' unamortized costs in oil and gas properties exceed this
ceiling amount, a provision for additional depreciation, depletion and
amortization is required. At December 31, 1993, 1994 and 1995 and September 30,
1996, the InterCoast Entities' unamortized costs of oil and gas properties did
not exceed such ceiling amount.
Proceeds from the sale of oil and gas properties are applied to reduce the
costs in the full cost pool unless the sale involves a significant quantity of
reserves in relation to the cost center, in which case a gain or loss would be
recognized.
The InterCoast Entities conduct certain of their drilling activities
(Programs), on a joint venture basis, together with working interest
participants. The agreements under which these investors participate provide the
InterCoast Entities with certain reversionary interests in the properties in the
Programs and current reimbursement of proportionate amounts of overhead and
seismic costs. Overhead reimbursements are included in the Combined Statements
of Income as a reduction of general and administrative expenses. The amounts of
such reimbursements were $872,000, $1,520,000 and $2,047,000 for the years ended
December 31, 1993, 1994 and 1995, respectively, and were $2,022,000 and
$2,653,000 for the nine months ended September 30, 1995 and 1996, respectively.
Production Imbalances
Joint interest owners may take more or less than their ownership interest
of natural gas volumes from jointly owned reservoirs. The InterCoast Entities
follow the sales method of accounting for imbalances, whereby they recognize
revenues based on the actual volumes of natural gas sold to purchasers. The
InterCoast Entities record a liability if sales of natural gas volumes in excess
of their entitlements from a jointly owned reservoir exceed their interest in
the remaining estimated natural gas reserves of such reservoir. Volumetric
production is monitored to minimize imbalances, and such imbalances were not
significant at December 31, 1993, 1994 and 1995 and September 30, 1996.
Amortization of Goodwill
Goodwill was recognized with the acquisition of operating rights, certain
other assets and personnel of Medallion Petroleum, Inc. in 1992 by InterCoast
Oil and Gas and with the acquisition of certain assets and personnel of GED Gas
Services, L.L.C. in 1995 by GED. Goodwill is amortized over the expected period
of benefit of forty years using the straight line method. The unamortized
balance of goodwill included on the Combined Balance Sheets as Intangible and
Other Assets at December 31, 1994 and 1995 and September 30, 1996 is $1,829,000,
$3,486,000 and $3,417,000, respectively.
Long-Lived Assets
In March 1995, the Financial Accounting Standards Board (FASB) issued SFAS
No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of." This statement, which the InterCoast Entities adopted
on January 1, 1996, requires the InterCoast Entities to review long-lived assets
for impairment whenever circumstances indicate that the carrying amount of an
asset may not be recoverable. Adoption of SFAS No. 121 had no impact on the
InterCoast Entities' results of operations or financial position at the time of
adoption.
Stock-Based Compensation Plans
In October 1995, the FASB issued SFAS No. 123 "Accounting for Stock-Based
Compensation" regarding accounting for stock-based compensation plans. This
statement, which is effective for
F-32
<PAGE> 212
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
reporting periods beginning January 1, 1996, allows for alternative methods of
adoption. The InterCoast Entities do not expect the accounting provisions or the
alternative disclosure provisions of SFAS No. 123 to have a material impact on
the InterCoast Entities' compensation costs.
Accounting for Commodity Price Risk Management
The InterCoast Entities engage in price risk management activities to
minimize the impact of market fluctuations on assets, liabilities, production or
other contractual commitments. Changes in the market value of these transactions
are deferred until the gain or loss on the underlying item is recognized. See
Note 6 for further discussion of the InterCoast Entities' price risk management
activities.
Combined Statements of Cash Flows
For purposes of the Combined Balance Sheets and Combined Statements of Cash
Flows, the InterCoast Entities consider all highly liquid debt instruments
purchased with a remaining maturity of three months or less to be cash
equivalents. There were no material non-cash investing or financing activities
in the years ended December 31, 1993, 1994 or 1995 or in the nine months ended
September 30, 1995 and 1996.
2. OIL AND GAS PROPERTIES, NET
<TABLE>
<CAPTION>
DECEMBER 31, SEPTEMBER
--------------------- 30,
1994 1995 1996
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Oil and gas properties........................... $186,131 $225,147 $286,116
Accumulated depreciation, depletion and
amortization................................... (45,061) (66,550) (86,689)
-------- -------- --------
Oil and gas properties, net...................... $141,070 $158,597 $199,427
======== ======== ========
</TABLE>
The provision for depreciation, depletion and amortization of the
InterCoast Entities' oil and gas properties was recorded at the rate of $0.80,
$0.86 and $0.90, per equivalent thousand cubic feet of natural gas production
for the years ended December 31, 1993, 1994 and 1995, respectively, and at the
rate of $0.83 and $0.88 for the nine months ended September 30, 1995 and 1996,
respectively.
3. INCOME TAXES
The InterCoast Entities are included in the consolidated federal and, where
appropriate, state income tax returns of MidAmerican Energy. The consolidated
income tax currently payable (or receivable) has been allocated among the
InterCoast Entities and other members of the affiliated income tax reporting
group (Group) based on the respective contributions to the consolidated taxable
income and tax credits of the Group. The InterCoast Entities have received (or
made) payments for the income tax reductions (or increases) contributed to the
Group.
The components of the provision for income taxes are shown below:
<TABLE>
<CAPTION>
1993 1994 1995
------ ------ -------
(IN THOUSANDS)
<S> <C> <C> <C>
Current -- Federal................................... $1,136 $ 560 $(7,143)
-- State.................................... 227 140 (766)
Deferred -- Federal................................... 3,135 1,772 10,382
-- State.................................... 885 730 1,165
------ ------ ------
Total....................................... $5,383 $3,202 $ 3,638
====== ====== ======
</TABLE>
F-33
<PAGE> 213
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
A reconciliation of the statutory federal income tax rate to the overall
effective income tax rate follows:
<TABLE>
<CAPTION>
1993 1994 1995
---- ---- ----
<S> <C> <C> <C>
Statutory federal income tax rate......................... 35.0% 35.0% 35.0%
State income taxes, net of federal income tax benefit..... 2.0 2.5 2.1
State tax true-ups........................................ 1.7 -- --
Other items, net.......................................... 5.1 0.1 (1.4)
---- ---- ----
Overall effective income tax rate......................... 43.8% 37.6% 35.7%
==== ==== ====
</TABLE>
The components of the net deferred tax liability are as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------
1994 1995
------- --------
(IN THOUSANDS)
<S> <C> <C>
Accelerated depreciation/depletion methods.................... $(4,271) $(13,940)
Intangible drilling costs..................................... 17,062 38,278
Other......................................................... 750 750
------- --------
Accumulated deferred income taxes............................. $13,541 $ 25,088
======= ========
</TABLE>
4. RELATED PARTY TRANSACTIONS
The InterCoast Entities receive general and administrative services from
InterCoast Energy, MidAmerican Capital and MidAmerican Energy. The costs of such
services received, including overhead costs, are assigned (and billed) to the
InterCoast Entities. Wages and salaries of the corporate staff and personnel of
InterCoast Energy, MidAmerican Capital and MidAmerican Energy are assigned based
upon an estimate of the time spent by staff and personnel benefitting the
InterCoast Entities. The estimate is reviewed and updated annually. Such wages
and salaries are billed to the InterCoast Entities, along with associated
payroll taxes and the costs of benefits. In addition, certain directly assigned
expenses paid by MidAmerican Capital are billed to the InterCoast Entities.
The InterCoast Entities are parties to guarantee agreements between
InterCoast Energy and its primary lender.
MidAmerican Capital and InterCoast Energy have entered into letters of
credit and financial guarantees on behalf of the InterCoast Entities to support
certain well costs and the natural gas purchases. Letters of credit and
financial guarantees are conditional commitments issued by MidAmerican Capital
InterCoast Energy to guarantee performance to a third party.
The InterCoast Entities have letters of credit totaling $1,914,000 and
$1,103,000 and financial guarantees amounting to $2,750,000 and $0 which were
not reflected on the Combined Balance Sheets as of December 31, 1995 and 1994,
respectively.
The fair value of the letters of credit was $14,000 and $8,000 at December
31, 1995 and 1994, respectively, estimated based on fees currently charged for
similar agreements. The fair value of the financial guarantees is not
determinable based on the specific characteristics of the guarantees.
5. EMPLOYEE BENEFITS
The InterCoast Entities' employees participate in MidAmerican Energy's
noncontributory defined benefit retirement income plan. Benefits under the plan
are based on participants' compensation, years of service and age at retirement.
Funding is based on the actuarially determined costs of the plan and the
requirements of the Internal Revenue Code and the Employee Retirement Income
Security Act.
F-34
<PAGE> 214
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
As of December 31, 1993, 1994 and 1995, the InterCoast Entities have not
been required to contribute to the plan. Pension costs are allocated to the
InterCoast Entities based on participants' compensation. The amount the
InterCoast Entities expensed during 1995, 1994 and 1993 was $12,000, $44,000 and
$0, respectively. The InterCoast Entities' pension accrual included in the
Combined Balance Sheets as Other Current Liabilities was $56,000 at December 31,
1994 and 1995.
6. FINANCIAL INSTRUMENTS WITH OFF-BALANCE SHEET RISK
Price Risk Management
The InterCoast Entities have entered into swaps, futures and options to
manage risks associated with fluctuations in the price of natural gas production
and marketing activities.
Commodity Price Swaps. Commodity price swap agreements require the
InterCoast Entities to make payments to (or entitle it to receive payments from)
the counterparties based upon the differential between a specified fixed and
variable price. The InterCoast Entities account for these transactions on a
settlement basis and, accordingly, gains or losses are included in oil and gas
revenues in the period in which the underlying natural gas is produced. These
agreements do not impose cash margin requirements on the InterCoast Entities or
provide for collateral to the InterCoast Entities. At December 31, 1995,
InterCoast Oil and Gas was party to commodity price swap agreements covering
approximately 8.0 million MMBtu, 6.3 million MMBtu and 23.2 million MMBtu of
natural gas for the years 1996 and 1997 and for the period 1998 through 2005,
respectively.
Futures and Options Contracts. Natural gas futures require the InterCoast
Entities to buy or sell natural gas at a fixed price. Natural gas options held
to hedge price risk only provide the right, not the requirement, to buy or sell
natural gas at a fixed price. The InterCoast Entities use futures to manage
margins on offsetting fixed-price purchase or sale commitments for physical
quantities of natural gas. The InterCoast Entities use options to limit overall
price risk exposure. Futures contracts mandate initial margin requirements. The
InterCoast Entities maintain such margin accounts and funds in cash any daily
settlement requirements relating to futures contracts.
At December 31, 1995, the InterCoast Entities had futures contracts to
purchase natural gas for approximately 10.1 million MMBtu and to sell natural
gas for approximately 4.9 million MMBtu. The associated unrecognized gain on
futures contracts was $486,000.
Basis Swaps. Basis swap agreements require the InterCoast Entities to make
payments to (or entitle it to receive payments from) the counterparties based
upon the differential between the variable costs associated with the delivery of
natural gas production to specific delivery points and a contractually specified
fixed cost. At December 31, 1995, InterCoast Oil and Gas had basis swap
arrangements relating to a total of approximately 2.1 million MMbtu during 1996.
Credit Risk
Credit risk relates to the risk of loss that the InterCoast Entities would
incur as a result of the nonperformance by counterparties pursuant to the terms
of their contractual obligations. The InterCoast Entities' overall exposure to
credit risk may be affected positively or negatively in that the counterparties
may be similarly affected by changes in economic, regulatory or other
conditions. The InterCoast Entities maintain credit policies with regard to
counterparties that management believes minimize overall credit risk. With
regard to commodity price and basis swaps, these policies include an evaluation
of potential counterparties' financial condition (including credit rating),
collateral agreements under certain circumstances and the use of standardized
agreements. With regard to futures and options contracts, the InterCoast
Entities utilize New York Mercantile Exchange (NYMEX) contracts. Such contracts
are guaranteed by the NYMEX and, accordingly, have nominal credit risk. As a
result, the InterCoast Entities'
F-35
<PAGE> 215
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
risk is limited to the initial purchase price of the options and to changes in
the market value of the futures contracts. Accordingly, the InterCoast Entities
do not anticipate any material impact on their financial position or results of
operations as a result of nonperformance by counterparties to the financial
instruments related to natural gas production and marketing activities.
7. CONCENTRATION OF CREDIT RISK
Although credit risk is inherent to the foregoing types of financial
instruments and the InterCoast Entities are exposed to losses in the event of
nonperformance by the counterparties, the InterCoast Entities believe that the
aggregate credit risk associated with present swap and hedge arrangements is not
significant due to the nature of the contracts and the counterparties thereto.
The InterCoast Entities' gas and oil production purchasers consist
primarily of independent marketers and major natural gas pipeline companies. The
InterCoast Entities perform credit evaluations of their customers' financial
condition and obtain credit support if the InterCoast Entities believe it is
warranted. The InterCoast Entities have not experienced any significant losses
from uncollectible accounts.
8. COMMITMENTS AND CONTINGENCIES
The InterCoast Entities are lessees in several agreements to lease office
space at various locations. The lease agreements expire in 1999 through 2001,
with various options for renewal. The following is a schedule by year of
estimated future rent expense on such leases as of December 31, 1995:
<TABLE>
<CAPTION>
YEAR ENDING
DECEMBER 31,
------------
<S> <C>
1996................................................................... $ 218,000
1997................................................................... 205,000
1998................................................................... 204,000
1999................................................................... 205,000
2000................................................................... 204,000
Thereafter............................................................. 205,000
----------
Total........................................................ $1,241,000
==========
</TABLE>
On June 19, 1996, an action was brought by Nab Nat. Resources, L.L.C.
against several defendants, including InterCoast Oil and Gas, in the Second
Judicial District Court, Claiborne Parish, State of Louisiana, seeking a
declaration of the court that certain leases and a unit agreement had lapsed by
reason of a cessation of production of oil or gas in paying quantities that
allegedly occurred in the mid 1980s. The plaintiff also seeks, among other
things, an accounting of the production of oil, natural gas and other minerals
from the properties since the alleged lapse of the leases, damages of not less
than $5,000,000 for restoration and clean up of the lands covered by the leases
and certain other damages for trespass and mental anguish. InterCoast Oil and
Gas is in the preliminary stages of investigating the facts on which the lawsuit
appear to be based. Based on InterCoast Oil and Gas' preliminary investigations,
the claim of damages for restoration and clean up of certain lands appears to
relate to properties which the InterCoast Oil and Gas does not own. InterCoast
Oil and Gas currently intends to continue its investigation of the lawsuit and
to defend the action vigorously.
9. SIGNIFICANT ACQUISITION
In April 1996, InterCoast Oil and Gas acquired the interests of Enron Oil &
Gas Company in certain gas and oil properties (the Sawyer Canyon Properties),
associated natural gas gathering lines and other well equipment located in
Texas. The net purchase price at closing was approximately $53.2 million.
F-36
<PAGE> 216
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
InterCoast Oil and Gas concurrently conveyed certain interests in particular
wells to InterCoast Global Management, Inc., a wholly-owned subsidiary of
MidAmerican Capital. InterCoast Oil and Gas retained a production payment on 100
percent of the net proceeds of production from such wells until approximately 80
percent of the estimated proved developed natural gas reserves attributable to
the wells is produced. In consideration, InterCoast Oil and Gas received from
InterCoast Global Management, Inc. $5.6 million in cash and a promissory note in
the amount of $2.3 million, which is payable in 48 monthly installments over
four years and bears interest at the prime rate. The total adjusted purchase
price was $45.2 million. InterCoast Oil and Gas recorded no gain or loss related
to this transaction. The proved reserves associated with the production payment
are included in the InterCoast Entities' estimated net quantities of oil and gas
reserves presented in Note 12.
InterCoast Oil and Gas funded the net purchase price of $45.2 million under
a promissory note due to MidAmerican Capital. This promissory note was due on or
before April 12, 1997, with interest payable quarterly at a floating rate based
on LIBOR plus 55 basis points. The promissory note was repaid in full in July
1996.
The following unaudited pro forma revenues, and net income for the years
ended December 31, 1994 and 1995 and for the three months ended March 31, 1996,
presented below have been prepared assuming the acquisition described above had
been consummated as of January 1, 1994. However, such pro forma information is
not necessarily indicative of what actually would have occurred had the
transaction occurred on such date.
<TABLE>
<CAPTION>
YEAR ENDED YEAR ENDED NINE MONTHS ENDED
DECEMBER 31, DECEMBER 31, SEPTEMBER 30,
1994 1995 1996
------------ ------------ -----------------
<S> <C> <C> <C>
Revenues (in thousands)............... $ 80,860 $ 88,138 $ 164,248
Net income (in thousands)............. 9,980 7,866 11,370
------- ------- ------
</TABLE>
10. SUBSEQUENT EVENT
On November 14, 1996, InterCoast Energy and its wholly-owned subsidiary,
InterCoast Gas Services -- Delaware, signed definitive agreements to sell the
stock of the InterCoast Entities to KCS Energy, Inc. Under the terms of these
agreements, KCS Energy, Inc. will pay approximately $219 million in cash and
deliver warrants to acquire 435,000 shares of KCS Energy, Inc. common stock at a
price of $45 per share.
11. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The combined results of operations by quarter for the years ended December
31, 1994 and 1995 are as follows (in thousands):
<TABLE>
<CAPTION>
1994 QUARTER ENDED
-----------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------
<S> <C> <C> <C> <C>
Total revenues.......................... $ 15,460 $15,459 $ 14,125 $13,122
Income before income taxes.............. $ 2,391 $ 2,930 $ 2,035 $ 1,157
Net income.............................. $ 1,492 $ 1,828 $ 1,269 $ 722
</TABLE>
<TABLE>
<CAPTION>
1995 QUARTER ENDED
-----------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------
<S> <C> <C> <C> <C>
Total revenues.......................... $ 12,990 $14,182 $ 14,012 $32,276
Income before income taxes.............. $ 1,641 $ 2,652 $ 2,201 $ 3,690
Net income.............................. $ 1,055 $ 1,705 $ 1,415 $ 2,371
</TABLE>
F-37
<PAGE> 217
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
In the fourth quarter of 1994, the InterCoast Entities experienced a
significant decline in realized natural gas price causing reductions in oil and
gas revenues and income before income taxes as compared to the prior three
quarters of 1994.
In the fourth quarter of 1995, InterCoast Energy acquired certain assets of
GED Gas Services, L.L.C. The acquisition generated natural gas sales revenues of
$15.4 million in such quarter. Additionally, in the fourth quarter of 1995, the
InterCoast Entities' natural gas production volumes and realized natural gas
prices increased resulting in higher oil and gas revenues and income before
income taxes as compared to the prior three quarters of 1995.
12. SUPPLEMENTARY OIL AND GAS DISCLOSURES
Users of the following information should be aware that the process of
estimating quantities of proved and proved developed oil and gas reserves is
very complex, requiring significant subjective decisions in the evaluation of
all available geological, engineering and economic data for each reservoir. The
data for a given reservoir may also change substantially over time as a result
of numerous factors including, but not limited to, additional development
activity, evolving production history and continual reassessment of the
viability of production under varying economic conditions. Consequently,
material revisions to existing reserve estimates occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessment possible, the significance of
the subjective decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other estimates
presented in connection with financial statement disclosures.
Proved reserves are estimated quantities of natural gas, crude oil and
condensate that geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known reservoirs under
economic and operating conditions existing at the time the estimates were made.
Proved developed reserves are proved reserves that can be expected to be
recovered through wells and equipment in place and under operating methods being
utilized at the time the estimates were made.
Capitalized costs for oil and gas producing activities consist of the
following:
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------------
1993 1994 1995
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Proved properties............................... $146,422 $184,502 $223,088
Unproved properties............................. 1,487 1,629 2,059
Accumulated depletion, depreciation and
amortization.................................. (26,459) (45,061) (66,550)
-------- -------- --------
Net capitalized costs................. $121,450 $141,070 $158,597
======== ======== ========
</TABLE>
Costs incurred for oil and gas property acquisition, exploration and
development activities are as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------
1993 1994 1995
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Development......................................... $12,749 $22,000 $34,639
Property acquisitions............................... 59,913 18,705 2,726
Exploration......................................... 2,322 2,144 3,480
------- ------- -------
Net capitalized costs..................... $74,984 $42,849 $40,845
======= ======= =======
</TABLE>
F-38
<PAGE> 218
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Estimated Net Quantities of Oil and Gas Reserves--(Unaudited)
The following table sets forth the InterCoast Entities' net proved
reserves, including the changes therein, and proved developed reserves (all
within the United States) at the end of each of the three years in the period
ended December 31, 1995:
<TABLE>
<CAPTION>
NATURAL OIL AND
GAS LIQUIDS TOTAL
(MMCF) (MBBL) (MMCFE)
--------- -------- ---------
<S> <C> <C> <C>
Net proved reserves at December 31, 1992........ 64,806.5 3,111.0 83,472.5
Revisions of previous estimates............... (6,649.3) 441.8 (3,998.5)
Extensions, discoveries and other additions... 14,911.6 288.4 16,642.0
Purchases of reserves in place................ 55,740.1 5,840.3 90,781.9
Production.................................... (12,741.8) (690.8) (16,886.6)
Sales of reserves in place.................... (4,043.7) (35.6) (4,257.3)
--------- -------- ---------
Net proved reserves at December 31, 1993........ 112,023.4 8,955.1 165,754.0
Revisions of previous estimates............... (10,931.0) (1,089.0) (17,465.0)
Extensions, discoveries and other additions... 39,713.5 375.0 41,963.5
Purchases of reserves in place................ 23,804.9 1,489.6 32,742.5
Production.................................... (15,590.9) (1,024.4) (21,737.3)
Sales of reserves in place.................... (408.9) (1,402.5) (8,823.9)
--------- -------- ---------
Net proved reserves at December 31, 1994........ 148,611.0 7,303.8 192,433.8
Revisions of previous estimates............... (22,594.8) 3,265.8 (3,000.0)
Extensions, discoveries and other additions... 24,372.5 514.0 27,456.5
Purchases of reserves in place................ 1,119.2 12.7 1,195.4
Production.................................... (17,835.4) (1,027.9) (24,002.8)
Sales of reserves in place.................... 0.0 (224.4) (1,346.4)
--------- -------- ---------
Net proved reserves at December 31, 1995........ 133,672.5 9,844.0 192,736.5
========= ======== =========
Net proved developed reserves at December 31,
1993.......................................... 100,660.0 8,173.0 149,698.0
at December 31, 1994.......................... 115,099.0 6,717.0 155,401.0
at December 31, 1995.......................... 111,189.0 8,255.0 160,719.0
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves (Unaudited)
The following information has been developed utilizing procedures
prescribed by Statement of Financial Accounting Standards No. 69 "Disclosures
about Oil and Gas Producing Activities" (SFAS No. 69) and based on oil and gas
reserve and production volumes estimated, in part by the InterCoast Entities,
but primarily by the InterCoast Entities' independent reserve engineers,
Netherland, Sewell and Associates, Inc. It may be useful for certain comparative
purposes, but should not be solely relied upon in evaluating the InterCoast
Entities or their performance. Further, information contained in the following
table should not be considered as representative of realistic assessments of
future cash flows, nor should the Standardized Measure of Discounted Future Net
Cash Flows be viewed as representative of the current value of the InterCoast
Entities.
The InterCoast Entities believe that the following factors should be taken
into account in reviewing the following information: (1) future costs and
selling prices will probably differ from those required to be used in these
calculations; (2) due to future market conditions and governmental regulations,
actual
F-39
<PAGE> 219
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
rates of production achieved in future years may vary significantly from the
rate of production assumed in the calculations; (3) selection of a 10% discount
rate is arbitrary and may not be reasonable as a measure of the relative risk
inherent in realizing future net oil and gas revenues; and (4) future net
revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows were estimated by
applying period-end oil and gas prices adjusted for fixed and determinable
escalations to the estimated future production of period-end reserves. As of
December 31, 1995, approximately 37.5 Bcf of gas of the InterCoast Entities'
future production was subject to commodity price swap agreements (see Note 6).
Future cash inflows were reduced by estimated future development, abandonment
and production costs based on period-end costs in order to arrive at future net
cash flow before tax. Future income tax expense has been computed by applying
period-end statutory tax rates to aggregate future pre-tax net cash flows,
reduced by the tax basis of the properties involved and tax carryforwards. Use
of a 10% discount rate is required by SFAS No. 69.
Management does not rely solely upon the following information in making
investment and operating decisions. Such decisions are based upon a wide range
of factors, including estimates of probable as well as possible reserves and
varying price and cost assumptions considered more representative of a range of
possible economic conditions that may be anticipated.
The standardized measure of discounted future net cash flows relating to
proved oil and gas reserves is as follows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-------------------------------------
1993 1994 1995
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows.......................... $ 354,076 $ 369,430 $ 430,282
Future production costs...................... (119,855) (123,914) (155,984)
Future development and abandonment costs..... (13,886) (24,003) (16,078)
--------- --------- ---------
Future net cash flows before income taxes.... 220,335 221,513 258,220
Future income tax expense.................... (50,633) (47,526) (65,314)
10% annual discount for estimating timing of
cash
flows...................................... (51,500) (47,943) (55,982)
--------- --------- ---------
Standardized measure of discounted future net
cash flows................................. $ 118,202 $ 126,044 $ 136,924
========= ========= =========
</TABLE>
F-40
<PAGE> 220
THE INTERCOAST ENTITIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
A summary of the principal changes in the standardized measure of
discounted future net cash flows applicable to proved oil and gas reserves is as
follows (unaudited):
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
----------------------------------
1993 1994 1995
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Beginning of the period......................... $ 62,177 $118,202 $126,044
-------- -------- --------
Revisions of previous estimates:
Changes in prices and costs..................... (551) (25,715) 8,275
Changes in quantities........................... (3,957) (13,134) (2,627)
Changes in future development costs............. (6,016) (7,323) (2,948)
Previously estimated development costs incurred
during the period............................. 8,951 11,572 17,954
Additions to proved reserves resulting from
extensions and discoveries, less related
cost.......................................... 16,314 31,935 26,998
Sales of reserves in place...................... (2,763) (663) (769)
Purchases of reserves in place.................. 68,074 27,006 2,085
Accretion of discount........................... 7,760 13,771 14,460
Sales of oil and gas, net of production costs... (27,728) (29,129) (32,961)
Net changes in income taxes..................... (4,089) 958 (12,684)
Changes in estimated timing of production
and other..................................... 30 (1,436) (6,903)
-------- -------- --------
Net increase.................................... 56,025 7,842 10,880
-------- -------- --------
End of period................................... $118,202 $126,044 $136,924
======== ======== ========
</TABLE>
F-41
<PAGE> 221
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholder and Board of Directors of
InterCoast Energy Company:
We have audited the accompanying statements of revenues and direct
operating expenses of the Sawyer Canyon Properties (see Note 1) for the years
ended December 31, 1994 and 1995. These statements are the responsibility of
InterCoast Energy Company's management. Our responsibility is to express an
opinion on these statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the statements of revenues and direct
operating expenses are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the statements. An audit also includes assessing the accounting principles used
and significant estimates made by management, as well as evaluating the overall
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the statements of revenues and direct operating expenses
referred to above presents fairly, in all material respects, the revenues and
direct operating expenses of the Sawyer Canyon Properties (see Note 1) for the
years ended December 31, 1994 and 1995, in conformity with generally accepted
accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas
June 28, 1996
F-42
<PAGE> 222
SAWYER CANYON PROPERTIES
STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
<TABLE>
<CAPTION>
YEAR ENDED THREE MONTHS
--------------------------------------- ENDED
DECEMBER 31, 1994 DECEMBER 31, 1995 MARCH 31, 1996
----------------- ----------------- --------------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C>
REVENUES:
Oil and Gas............................ $20,661 $13,084 $3,425
Gathering systems...................... 2,033 1,594 315
------- ------- ------
Total revenues................. 22,694 14,678 3,740
------- ------- ------
DIRECT OPERATING EXPENSES:
Oil and Gas operating.................. 2,625 2,953 614
Gathering systems...................... 163 105 31
------- ------- ------
Total expenses................. 2,788 3,058 645
------- ------- ------
Excess of revenues over direct operating
expenses............................... $19,906 $11,620 $3,095
======= ======= ======
</TABLE>
The accompanying notes are an integral part of this financial statement.
F-43
<PAGE> 223
SAWYER CANYON PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
(1) THE SAWYER CANYON PROPERTIES
On March 30, 1996, Enron Oil & Gas Company (EOG) entered into a purchase
and sale agreement (the Agreement) to sell certain oil and gas properties and
related assets and two gathering systems (collectively, the Sawyer Canyon
Properties) to InterCoast Oil and Gas Company (the Company). The purchase price
as of the January 1, 1996 effective date, $55.5 million, was subject to certain
adjustments including the net revenues (as defined in the Agreement) between the
effective date and the closing date. The net purchase price at closing, April
12, 1996, was approximately $53.2 million of which $3.0 million was assigned to
the carrying value of related gathering systems which were transferred to
InterCoast Gas Services Company, an affiliated company. The properties,
predominantly natural gas, and the associated gathering systems are located in
West Texas.
Concurrent with the closing of the acquisition of the Sawyer Canyon
Properties from EOG, the Company conveyed certain interests in particular wells
to InterCoast Global Management, Inc., a wholly owned subsidiary of MidAmerican
Capital Company, the Company's indirect parent. The Company retained a
production payment on 100 percent of the net proceeds of production of such
wells until approximately 80 percent of the estimated proved developed natural
gas reserves attributable to the wells has been produced. The Company received
from InterCoast Global Management, Inc. $5.6 million in cash and a promissory
note in the amount of $2.3 million, which is payable in 48 monthly installments
over four years and bears interest at the prime rate. The Company recorded no
gain or loss on this transaction.
(2) BASIS OF PRESENTATION
Certain costs, such as depreciation, depletion and amortization, general
and administrative expenses and federal and state income taxes were not
allocated to the above properties because the property interests and related
assets and gathering systems acquired represent only a portion of EOG's business
and the costs incurred by EOG are not necessarily indicative of the costs to be
incurred by the Company. Historical financial information reflecting financial
position, results of operations and cash flows of the Sawyer Canyon Properties
are not presented because the entire acquisition cost was assigned to the gas
and oil property interests and the related gathering systems. Accordingly, the
historical statements of revenues and direct operating expenses have been
presented in lieu of the financial statements required under Rule 3-05 of
Securities and Exchange Commission Regulation S-X.
Revenues and direct operating expenses for the gas and oil properties
included in the accompanying statement represent EOG's interest in the
properties and are presented on the accrual basis of accounting and may not be
representative of future operations. Revenues on the oil and gas properties are
shown net of any applicable severance taxes. Certain of the oil and gas
properties qualify as high-cost natural gas wells and are currently exempt from
Texas severance taxes. Depreciation, depletion and amortization, allocated
general and administrative expenses and federal and state income taxes have been
excluded.
Revenues and direct operating expenses for the two gathering systems are
presented on the accrual basis of accounting and may not be representative of
future operations. Depreciation, depletion and amortization, allocated general
and administrative expenses and federal and state income taxes have been
excluded.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of revenues and direct operating
expenses during the reporting period. Actual results could differ from those
estimates.
F-44
<PAGE> 224
SAWYER CANYON PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES -- (CONTINUED)
(3) RELATED PARTY TRANSACTIONS
Included in oil and gas revenues (excluding severance taxes and gathering
and transportation expenses) for the gas and oil properties is approximately
$21.2 million, $13.0 million and $3.0 million for the years ended December 31,
1994 and 1995, and the three months ended March 31, 1996, respectively, related
to the sale of natural gas, crude oil and condensate volumes to affiliates of
EOG.
Included in revenues for the two gathering systems is approximately $1.8
million, $1.2 million and $0.3 million for the years ended December 31, 1994 and
1995, and the three months ended March 31, 1996, respectively, from the
transportation of natural gas for EOG's production volumes, which are shown as a
reduction in the related oil and gas revenues.
(4) COMMITMENTS AND CONTINGENCIES
Pursuant to the terms of the Agreement, certain claims, litigation, or
disputes pending as of the effective date and certain matters arising in
connection with ownership of the properties or the gathering systems prior to
the effective date are retained by EOG.
(5) SUPPLEMENTAL FINANCIAL INFORMATION FOR OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
Users of the following information should be aware that the process of
estimating quantities of proved and proved developed oil and gas reserves is
very complex, requiring significant subjective decisions in the evaluation of
all available geological, engineering and economic data for each reservoir. The
data for a given reservoir may also change substantially over time as a result
of numerous factors including, but not limited to, additional development
activity, evolving production history and continual reassessment of the
viability of production under varying economic conditions. Consequently,
material revisions to existing reserve estimates occur from time to time.
Although every reasonable effort is made to ensure that reserve estimates
reported represent the most accurate assessments possible, the significance of
the subjective decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other estimates
presented in connection with financial statement disclosures.
Proved reserves are estimated quantities of natural gas, crude oil and
condensate, that geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known reservoirs under
economic and operating conditions existing at the time the estimates were made.
Proved developed reserves are proved reserves expected to be recovered
through wells and equipment in place and under operating methods being utilized
at the time the estimates were made.
Estimates of proved and proved developed reserves at December 31, 1993 and
1994 were based on studies performed by the engineering staff of EOG. Estimates
of proved and proved developed reserves at December 31, 1995 are based on
estimates prepared by Netherland, Sewell and Associates, Inc.
F-45
<PAGE> 225
SAWYER CANYON PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES -- (CONTINUED)
Estimated Net Quantities of Oil and Gas Reserves
<TABLE>
<CAPTION>
OIL AND
GAS LIQUIDS
(MMCF) (MBBI)
------- -------
<S> <C> <C>
Net proved reserves at December 31, 1993........................... 79,614 51
Production....................................................... (10,903) (32)
------- ---
Net proved reserves at December 31, 1994........................... 68,711 19
Production....................................................... (8,145) (17)
Revisions of previous estimates and other........................ (2,812) 77
------- ---
Net proved reserves at December 31, 1995........................... 57,754 79
======= ===
Net proved developed reserves
at December 31, 1994............................................. 66,449 40
at December 31, 1995............................................. 55,546 72
</TABLE>
F-46
<PAGE> 226
SAWYER CANYON PROPERTIES
NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES -- (CONTINUED)
Standardized Measure of Discounted Future Net Cash Flows Relating to Oil and
Gas Properties
The following information has been developed utilizing procedures described
by Statement of Financial Accounting Standards No. 69 "Disclosures About Oil and
Gas Producing Activities" and based on oil and gas reserve and production
volumes estimated by the engineering staff of Netherland, Sewell and Associates,
Inc. It may be useful for certain comparison purposes, but should not be solely
relied upon in evaluating the oil and gas properties or their performance.
Further, information contained in the following table should not be considered
as representative of realistic assessments of future cash flows, nor should the
Standardized Measure of Discounted Future Net Cash Flows be viewed as
representative of the current value of the oil and gas properties.
The future cash flows presented below are based on sales prices, cost
rates, and statutory income tax rates in existence as of the date of the
projections estimated by Netherland, Sewell and Associates, Inc. It is possible
that material revisions to some estimates of natural gas and crude oil reserves
may occur in the future development and production of the reserves may occur in
periods other than those assumed, and actual prices realized and costs incurred
may vary significantly from those used.
The future cash flows presented by the Company in the future will be based
on the Company's cost structure and timing of future development and production
and accordingly may be significantly different from those of EOG.
<TABLE>
<CAPTION>
DECEMBER 31, 1994 DECEMBER 31, 1995
----------------- -----------------
(IN THOUSANDS)
<S> <C> <C>
Future cash inflows............................... $ 145,946 $ 133,190
Future production costs........................... (45,659) (43,034)
Future development costs.......................... (1,573) (1,573)
-------- --------
Future net cash flows............................. 98,714 88,583
Discount to present value at 10% annual rate...... (39,129) (33,171)
-------- --------
Standardized measure of discounted future net cash
flows relating to proved oil and gas reserves... $ 59,585 $ 55,412
======== ========
</TABLE>
Changes in Standardized Measure of Discounted Future Net Cash Flows
The following table sets forth the changes in the standardized measure of
discounted future net cash flows relating to proved oil and gas reserves for the
years ended December 31, 1994 and 1995:
<TABLE>
<CAPTION>
DECEMBER 31, 1994 DECEMBER 31, 1995
----------------- -----------------
(IN THOUSANDS)
<S> <C> <C>
Beginning of period............................... $ 70,565 $ 59,585
Accretion of discount............................. 7,056 5,958
Sales of oil and gas, net of production costs..... (18,036) (10,131)
-------- --------
Net decrease...................................... (10,980) (4,173)
-------- --------
End of period..................................... $ 59,585 $ 55,412
======== ========
</TABLE>
F-47
<PAGE> 227
NO DEALER, SALESPERSON OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS OTHER THAN THOSE CONTAINED IN OR
INCORPORATED BY REFERENCE IN THIS PROSPECTUS IN CONNECTION WITH THE OFFER MADE
BY THIS PROSPECTUS AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATIONS
MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE COMPANY OR ANY OF THE
UNDERWRITERS. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE
HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THERE HAS
BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE THE DATE HEREOF. THIS
PROSPECTUS DOES NOT CONSTITUTE AN OFFER OR SOLICITATION BY ANYONE IN ANY
JURISDICTION IN WHICH SUCH OFFER OR SOLICITATION IS NOT AUTHORIZED OR IN WHICH
THE PERSON MAKING SUCH OFFER OR SOLICITATION IS NOT QUALIFIED TO DO SO OR TO ANY
PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH SOLICITATION.
---------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
<S> <C>
Prospectus Summary........................ 3
Risk Factors.............................. 10
Disclosure Regarding Forward-Looking
Statements.............................. 13
Use of Proceeds........................... 14
Capitalization............................ 15
Price Range of Common Stock............... 16
Dividend Policy........................... 16
Pro Forma Financial Information........... 17
Management's Discussion and Analysis of
Financial Condition and Results of
Operations.............................. 24
Business and Properties................... 33
Management................................ 54
Security Ownership by Certain Beneficial
Owners and Management................... 56
Description of Capital Stock.............. 57
Certain United States Tax Consequences to
Non-United States Holders............... 59
Underwriting.............................. 61
Certain Legal Matters..................... 63
Accountants............................... 63
Reserve Engineers......................... 63
Available Information..................... 64
Incorporation of Certain Documents by
Reference............................... 64
Glossary.................................. 66
Index to Financial Statements............. F-1
</TABLE>
3,000,000 SHARES
KCS ENERGY, INC.
COMMON STOCK
($.01 PAR VALUE)
[KCS ENERGY CORP. LOGO]
SALOMON BROTHERS
INTERNATIONAL LIMITED
DONALDSON, LUFKIN & JENRETTE
SECURITIES CORPORATION
PRUDENTIAL-BACHE SECURITIES
MORGAN KEEGAN &
COMPANY, INC.
SOUTHCOAST CAPITAL
CORPORATION
PROSPECTUS
DATED JANUARY 29, 1997
