<PAGE> 1
Filed pursuant to
Rule 424(b)(4)
Registration No.
333-40479
PROSPECTUS
$125,000,000
KCS ENERGY, INC. [KCS ENERGY, INC. LOGO]
8 7/8% SENIOR SUBORDINATED NOTES DUE 2008
------------------
The 8 7/8% Senior Subordinated Notes due 2008 (the "Notes") are being
offered (the "Offering") by KCS Energy, Inc. (the "Company"). The Notes will
mature on January 15, 2008 and will bear interest at a rate of 8 7/8% per annum,
payable semi-annually on January 15 and July 15 of each year, commencing July
15, 1998.
The Notes will not be redeemable by the Company prior to January 15, 2003.
Thereafter, the Notes will be redeemable at the option of the Company, in whole
or in part, at the redemption prices set forth in this Prospectus, together with
accrued interest. In the event the Company consummates a Public Equity Offering
(as defined) on or prior to January 15, 2001, the Company may at its option use
all or a portion of the proceeds from such offering to redeem up to 33 1/3% of
the aggregate principal amount of the Notes originally issued at a redemption
price equal to 108.875% of the aggregate principal amount thereof, together with
accrued interest, provided that at least 66 2/3% of the aggregate principal
amount of Notes originally issued remains outstanding immediately after such
redemption. In addition, upon a Change of Control (as defined herein), each
holder of Notes shall have the right, at the holder's option, to require the
Company to repurchase such holder's Notes at a purchase price equal to 101% of
the principal amount thereof, together with accrued interest. See "Description
of the Notes -- Redemption."
The Notes will be unsecured obligations of the Company and will be
subordinate to all present and future Senior Indebtedness (as defined herein) of
the Company and senior to all future Subordinated Indebtedness (as defined
herein) of the Company. See "Description of the Notes -- Subordination." Each of
the Company's current and certain of its future subsidiaries will
unconditionally guarantee, jointly and severally, the Company's obligations
under the Notes on a senior subordinated basis. See "Description of the
Notes -- Subsidiary Guarantees of Notes."
The Notes have been approved for listing on the New York Stock Exchange,
subject to official notice of issuance, under the symbol "KCS08."
------------------
SEE "RISK FACTORS" BEGINNING ON PAGE 10 HEREIN FOR CERTAIN INFORMATION THAT
SHOULD BE CONSIDERED BY PROSPECTIVE INVESTORS.
------------------
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>
<CAPTION>
===================================================================================================================
PRICE TO DISCOUNTS AND PROCEEDS TO
PUBLIC(1) COMMISSIONS(2) COMPANY(3)
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Per Note...................................... 100% 2.625% 97.375%
- -------------------------------------------------------------------------------------------------------------------
Total......................................... $125,000,000 $3,281,250 $121,718,750
===================================================================================================================
</TABLE>
(1) Plus accrued interest, if any, from the date of initial issuance.
(2) The Company has agreed to indemnify the several Underwriters against
certain liabilities, including liabilities under the Securities Act of
1933. See "Underwriting."
(3) Before deducting expenses payable by the Company estimated at $725,000.
------------------
The Notes are being offered by the several Underwriters named herein,
subject to prior sale, when, as and if accepted by them and subject to certain
conditions. It is expected that delivery of the Notes in book-entry form will be
made through the facilities of The Depository Trust Company on or about January
21, 1998.
---------------------
SALOMON SMITH BARNEY
PRUDENTIAL SECURITIES INCORPORATED
CIBC OPPENHEIMER
JEFFERIES AND COMPANY, INC.
MORGAN KEEGAN & COMPANY, INC.
January 15, 1998
<PAGE> 2
CERTAIN PERSONS PARTICIPATING IN THE OFFERING MAY ENGAGE IN TRANSACTIONS
THAT STABILIZE, MAINTAIN, OR OTHERWISE AFFECT THE MARKET PRICE OF THE NOTES.
SPECIFICALLY, THE UNDERWRITERS MAY BID FOR, AND PURCHASE, THE NOTES IN THE OPEN
MARKET AND MAY IMPOSE PENALTY BIDS. FOR A DESCRIPTION OF THESE ACTIVITIES, SEE
"UNDERWRITING."
<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. Investors should carefully consider the statements set forth under
"Risk Factors." 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 has been adjusted to reflect a
two-for-one stock split that the Company completed on June 30, 1997. See
"Glossary" for definitions of certain terms used herein.
This Prospectus contains forward-looking statements that involve risks and
uncertainties. The Company's actual results may differ significantly from the
results discussed in the forward-looking statements. See "Special Note on
Forward-Looking Statements." Factors that might cause such differences include,
but are not limited to, those discussed in "Risk Factors."
THE COMPANY
GENERAL
KCS is an independent oil and gas company engaged in the acquisition,
exploration, development and production of oil and gas. Through its experienced
management and technical staff, the Company has grown significantly and created
a geographically diversified reserve base by implementing a balanced program of
development drilling, reserve acquisitions and exploration drilling. The Company
concentrates its activities in areas where it has accumulated geological
knowledge and technical expertise and where it can retain significant operating
control. As a result of these efforts, KCS has compiled a multi-year inventory
of over 600 potential drilling and recompletion locations, including a
significant number of sites in the Manderson Field in the Big Horn Basin in
Wyoming where the Company believes it has the potential to significantly
increase its reserves. Additionally, the Company augments its working interest
ownership of properties with a volumetric production payment ("VPP") program to
acquire priority rights to a portion of the oil and gas from other parties'
producing properties. The Company plans to spend $183 million on capital
expenditures in 1998, of which $95 million is for development drilling, $30
million is for exploration, $45 million is for the VPP program, $10 million is
for working interest acquisitions and $3 million is for other expenditures. The
Company currently plans to drill approximately 175 development wells and to
participate in approximately 60 exploratory prospects during 1998.
The Company's operations are primarily focused in the Rocky Mountain, Gulf
Coast, and Mid-Continent/West Texas regions, and through its VPP program
primarily in the Gulf of Mexico and Michigan. As of December 31, 1996, the
Company had estimated proved reserves of 355.8 Bcfe with an estimated pre-tax
present value of future net revenues ("PV-10") of $557.6 million. These
estimated reserves were 75% natural gas and 87% proved developed, and
approximately 10% were attributable to the Company's VPP program. The Company
operates properties comprising approximately 72% of its reserves (excluding VPP
reserves) at December 31, 1996.
A significant focus of the Company's future development is in the Manderson
Field in the Big Horn Basin in Wyoming. Since it acquired the field in November
1995, the Company has increased its acreage position from 7,500 to over 61,000
gross acres, and has undertaken an extensive exploration and development
drilling program. Through September 30, 1997, the Company had drilled 54 wells,
investing $35 million, and had spent $15.3 million to install infrastructure in
the field. Most of these wells are currently shut-in or awaiting completion,
remediation or stimulation because of delays in construction of a sour gas
treatment plant and associated gas injection system. Operations at the plant and
injection system commenced on December 3, 1997. Based on drilling and production
results and accumulation of additional seismic data, the Company believes that
there are seven productive formations located in the greater Manderson Field and
that they have significant reserve potential. The Company plans to spend $12
million in the fourth quarter of 1997 to complete a sour gas treatment plant in
the Manderson Field, bring the shut-in wells on production and drill
3
<PAGE> 4
17 additional wells. In 1998, the Company plans to spend approximately $40 to
$50 million to drill and complete as many as 70 to 100 wells in this field.
The Company has successfully increased its reserves through opportunistic
acquisitions. In May 1997, KCS completed an acquisition of properties in the
Langham Creek Field near Houston, Texas for $17 million (the "Langham Creek
Acquisition"), which enabled it to assume operatorship and increase its average
working interest in the area to approximately 61%. In December 1996, the Company
completed a major acquisition of oil and gas properties, principally in the
Mid-Continent region, for an aggregate purchase price of $199 million (the
"Medallion Acquisition"). As a result of the Medallion Acquisition, the Company
more than doubled its reserve base and production rate and significantly
expanded its presence in the Mid-Continent region. In November 1995, the Company
completed an acquisition in the Rocky Mountain region for $33 million (the
"Rocky Mountain Acquisition"), which resulted in numerous exploration and
development opportunities, including the Manderson Field.
Through its VPP program, the Company is able to add reserves at very
attractive rates of return and increase its exposure to acquisition, development
and exploration opportunities. In the three years ended September 30, 1997, the
Company invested $124 million in 25 separate VPP transactions, acquiring 71.8
Bcf of natural gas and 1.5 MMbbls of oil.
BUSINESS STRATEGY
KCS intends to continue to broaden its reserve base and increase production
and cash flow through a balanced program of development drilling, reserve
acquisitions and exploration drilling. The Company extensively utilizes advanced
technology, most notably 3-D seismic, computer-enhanced basin analysis, and
reservoir simulation and stimulation techniques, to better delineate and produce
reserves. The key components of the Company's business strategy include: (i)
exploiting and developing its multi-year inventory of development drilling
locations, (ii) capitalizing on the development potential of the Manderson
Field, (iii) acquiring properties with growth potential, (iv) controlling its
major properties, (v) continuing to expand its VPP program and (vi) pursuing a
balanced exploration program that includes high-potential opportunities.
KEY STRENGTHS
To implement its business strategy, the Company intends to take advantage
of several key strengths, including the following:
Proven Growth Record. The Company has achieved substantial growth in reserves,
production and EBITDA since 1992. KCS's estimated proved reserves have increased
at a compound annual growth rate of 57%, from 60.0 Bcfe as of December 31, 1992
to 355.8 Bcfe as of December 31, 1996. Over this period, production has
increased at a compound annual growth rate of 61%, from 4.4 Bcfe in 1992 to 30.1
Bcfe in 1996. Similarly, the Company's EBITDA has increased at a compound annual
growth rate of 81%, from $8.3 million for the year ended December 31, 1992 to
$88.9 million for the year ended December 31, 1996. For the nine months ended
September 30, 1997, the Company had oil and gas production of 41.2 Bcfe and
EBITDA of $72.0 million, compared to 22.2 Bcfe and $65.8 million for the same
period in 1996.
Innovative and Creative Approach to Expansion. The Company has demonstrated the
ability to identify and acquire oil and gas reserves in a disciplined, creative
manner and believes it has become one of the leaders in the acquisition of oil
and gas reserves through VPP transactions.
Large Multi-year Inventory of Drilling Opportunities. The Company has identified
more than 600 potential drilling and recompletion locations, representing a
three to four-year inventory. In addition, the Company believes that there are
significant exploratory opportunities in the acreage it has assembled, including
more than 265,000 gross undeveloped acres, in the onshore Gulf Coast regions of
Texas and Louisiana and in the Rocky Mountain and Mid-Continent regions.
Geographically Diversified Property Base. The Company operates in three distinct
regions: the Rocky Mountains, the Gulf Coast and the Mid-Continent/West Texas
regions. As a result, it benefits from diversification with respect to risks
associated with focusing on any one geographical region.
4
<PAGE> 5
Successful Drilling Program. During the three-year period ended December 31,
1996, the Company participated in the drilling of 118 development wells and 70
exploratory wells with a 93% and 46% completion rate. During the first nine
months of 1997, the Company participated in the drilling of 71 development
wells, 86% of which were completed and 23 exploratory wells, 43% of which were
completed. Over the five-year period ended December 31, 1996, the Company
replaced approximately 114% of its production through drilling.
High Operating Margins. The Company's drilling success and emphasis on an
efficient administrative and operating structure have enabled the Company to
generate high cash margins that the Company believes compare favorably with its
peer companies.
Control of Major Properties. The Company seeks to operate and own a majority
working interest in its major properties, which gives it greater control over
the timing and nature of future development as well as over operating costs and
the marketing of production. The Company operates properties comprising
approximately 72% of its reserves (excluding VPP reserves) at December 31, 1996.
Experienced, Motivated Management Team with a Significant Equity Stake. The
Company's senior management has extensive experience in the oil and gas industry
and is motivated to increase stockholder value. The Company's compensation
system is strongly geared to "pay for performance" with incentives directly tied
to operating and financial goals and objectives. Members of the Company's
management and directors currently own approximately 14% of the Company's common
stock, and the Company has established minimum direct ownership requirements for
all officers and directors.
5
<PAGE> 6
THE OFFERING
SECURITIES OFFERED............ $125,000,000 principal amount of 8 7/8% Senior
Subordinated Notes due 2008.
MATURITY...................... January 15, 2008.
PAYMENT OF INTEREST........... January 15 and July 15, commencing July 15,
1998.
OPTIONAL REDEMPTION........... The Notes will be redeemable in whole or in
part, at the option of the Company, at the
redemption prices set forth herein, together
with accrued interest, except that no
redemption may be made prior to January 15,
2003. In the event the Company consummates a
Public Equity Offering (as defined) on or prior
to January 15, 2001, the Company may at its
option use all or a portion of the proceeds
from such offering to redeem up to 33 1/3% of
the aggregate principal amount of the Notes
originally issued at a redemption price equal
to 108.875% of the aggregate principal amount
thereof, together with accrued interest,
provided that at least 66 2/3% of the aggregate
principal amount of Notes originally issued
remains outstanding immediately after such
redemption.
GUARANTEES.................... The Notes will be unconditionally guaranteed on
a senior subordinated basis by each of the
Company's current and certain of the Company's
future subsidiaries, and such Subsidiary
Guarantees (as defined) will be subordinate in
right of payment to all existing and future
Senior Indebtedness of the Subsidiary
Guarantors (as defined) and senior to all
future Subordinated Indebtedness of the
Subsidiary Guarantors.
RANKING....................... The Notes will be unsecured senior subordinated
obligations of the Company and will be
subordinate in right of payment to all existing
and future Senior Indebtedness of the Company
and senior to all future Subordinated
Indebtedness of the Company.
CHANGE OF CONTROL............. In the event that there shall occur a Change of
Control (as defined), each holder of the Notes
shall have the right, at the holder's option,
to require the Company to repurchase such
holder's Notes at 101% of their principal
amount, plus accrued interest. The term Change
in Control does not include other events that
might adversely affect the financial condition
of the Company or result in a downgrade in the
credit rating (if any) of the Notes. The
Company's ability to repurchase the Notes
following a Change of Control is dependent upon
the Company having sufficient funds and may be
limited by the terms of the Company's Senior
Indebtedness or the subordination provisions of
the Indenture. There is no assurance that the
Company will be able to repurchase the Notes
upon the occurrence of a Change of Control.
CERTAIN COVENANTS............. The Indenture relating to the Notes will
contain certain covenants, including covenants
which limit: (i) indebtedness; (ii) restricted
payments; (iii) issuances and sales of capital
stock of restricted subsidiaries; (iv)
transactions with affiliates; (v) other senior
subordinated indebtedness; (vi) liens; (vii)
asset sales; (viii) dividends and other payment
restrictions affecting restricted subsidiaries;
(ix) conduct of business; and (x) mergers,
consolida-
6
<PAGE> 7
tions and sales of assets. See "Description of
the Notes -- Certain Covenants" and "-- Merger,
Consolidation and Sale of Assets."
USE OF PROCEEDS............... The net proceeds to the Company from the sale
of the Notes will be used to fund the Company's
capital expenditure program and for working
capital and other general corporate purposes.
The proceeds will initially be used to repay
existing indebtedness under the Company's Bank
Credit Facilities (as defined).
LISTING....................... The Notes have been approved for listing on the
New York Stock Exchange ("NYSE"), subject to
official notice of issuance.
7
<PAGE> 8
SUMMARY HISTORICAL FINANCIAL DATA
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
The following table sets forth selected historical financial information of
the Company and should be read in conjunction with the Consolidated Financial
Statements (including the notes thereto) of KCS Energy, Inc. and the information
under the caption "Management's Discussion and Analysis of Financial Condition
and Results of Operations" included elsewhere in this Prospectus. The historical
data for the years ended December 31, 1994, 1995 and 1996 and for the nine
months ended September 30, 1996 (i) includes revenues attributable to an
above-market, take-or-pay contract with Tennessee Gas Pipeline Company (the
"Tennessee Gas Contract") which was terminated effective January 1, 1997 and
(ii) has been restated to reflect the discontinuation of the Company's natural
gas transportation and marketing operations in 1997.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
--------------------------------- ---------------------
1994 1995 1996 1996 1997
------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenue:
Oil and gas revenue(1)..................................... $66,215 $ 86,629 $108,015 $ 79,051 $100,396
Other revenue, net......................................... 1,185 486 359 377 3,702
------- -------- -------- -------- --------
Total................................................ 67,400 87,115 108,374 79,428 104,098
Operating costs and expenses:
Lease operating expenses................................... 6,218 6,156 9,167 6,582 20,470
Production taxes........................................... 845 467 2,526 1,671 4,354
General and administrative expenses........................ 4,853 4,704 7,825 5,411 7,302
Depreciation, depletion and amortization................... 18,783 38,231 45,460 33,128 42,486
------- -------- -------- -------- --------
Total................................................ 30,699 49,558 64,978 46,792 74,612
------- -------- -------- -------- --------
Operating income............................................ 36,701 37,557 43,396 32,636 29,486
Interest and other income, net.............................. 1,175 4,472 5,086 4,820 388
Interest expense............................................ (2,004) (6,807) (14,085) (11,193) (15,146)
------- -------- -------- -------- --------
Income from continuing operations before income taxes....... 35,872 35,222 34,397 26,263 14,728
Federal and state income taxes.............................. 12,269 11,817 12,680 9,483 5,452
------- -------- -------- -------- --------
Income from continuing operations........................... 23,603 23,405 21,717 16,780 9,276
Discontinued operations:
Net income (loss) from operations........................ 554 (2,099) (1,845) (1,974) (72)
Net gain on disposition.................................. -- -- -- -- 5,461
------- -------- -------- -------- --------
Net income.................................................. $24,157 $ 21,306 $ 19,872 $ 14,806 $ 14,665
======= ======== ======== ======== ========
Earnings per share:
Continuing operations.................................... $ 1.00 $ 1.00 $ 0.91 $ 0.70 $ 0.32
Discontinued operations.................................. 0.02 (0.09) (0.08) (0.08) 0.18
------- -------- -------- -------- --------
Total................................................ $ 1.02 $ 0.91 $ 0.83 $ 0.62 $ 0.50
======= ======== ======== ======== ========
Average common shares outstanding........................... 23,610 23,521 23,811 23,773 29,449
Dividends per common share.................................. $ 0.045 $ 0.060 $ 0.060 $ 0.045 $ 0.050
OTHER DATA (UNAUDITED):
Tennessee Gas Contract premium(2)........................... $42,828 $ 52,007 $ 32,829 $ 25,689 $ --
EBITDA(3)................................................... 55,484 75,788 88,856 65,764 71,972
Capital expenditures........................................ 74,953 128,699 277,218 52,735 171,884
Ratio of earnings to fixed charges(4)....................... 17.7x 6.1x 3.4x 3.3x 2.0x
Ratio of EBITDA to interest expense......................... 27.7x 11.1x 6.3x 5.9x 4.8x
</TABLE>
<TABLE>
<CAPTION>
SEPTEMBER 30, 1997
--------------------------
ACTUAL AS ADJUSTED(5)
-------- --------------
(UNAUDITED)
<S> <C> <C>
BALANCE SHEET DATA:
Cash and cash equivalents................................... $ 3,858 $ 3,858
Working capital............................................. 7,707 7,707
Oil and gas properties, net................................. 540,896 540,896
Total assets................................................ 614,043 618,049
Long-term debt.............................................. 275,723 279,729
Total stockholders' equity.................................. 251,990 251,990
</TABLE>
- ---------------
(1) Includes revenues attributable to the Tennessee Gas Contract, for the years
ended December 31, 1994, 1995 and 1996 and for the nine months ended
September 30, 1996, that was terminated effective January 1, 1997.
(2) Reflects revenues associated with the natural gas production covered by the
above-market prices provided for in the Tennessee Gas Contract in excess of
the revenues that would otherwise have been received for such production at
spot market prices.
(3) 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.
(4) For purposes of calculating the ratio of earnings to fixed charges, fixed
charges include interest expense and that portion of non-capitalized rental
expense deemed to be the equivalent of interest. Earnings represents income
before income taxes from continuing operations before fixed charges.
(5) As adjusted to give effect to the sale by the Company of the Notes offered
hereby and the application of the estimated net proceeds as described under
"Use of Proceeds."
8
<PAGE> 9
SUMMARY HISTORICAL OIL AND GAS RESERVE AND OPERATING DATA
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. Summary reserve information as of December 31, 1996 includes reserves
attributable 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>
DECEMBER 31,
----------------------------------
1994 1995 1996
-------- ------------ --------
<S> <C> <C> <C>
RESERVE DATA:
Proved developed reserves:
Oil (Mbbls)............................................... 1,336 3,808 12,133
Natural gas (MMcf)........................................ 74,215 121,987 236,454
Total (MMcfe)........................................... 82,231 144,835 309,252
Proved undeveloped reserves:
Oil (Mbbls)............................................... 983 3,709 2,498
Natural gas (MMcf)........................................ 14,969 18,976 31,571
Total (MMcfe)........................................... 20,867 41,230 46,561
Total proved reserves:
Oil (Mbbls)............................................... 2,319 7,517 14,631
Natural gas (MMcf)........................................ 89,184 140,963 268,025
Total (MMcfe)........................................... 103,098 186,065 355,813
Estimated future net revenue before income taxes
($000)(1)(2).............................................. $307,533 $405,049 $849,265
Present value of estimated future net revenues before income
taxes ($000)(2)(3)(4)..................................... $241,705 $291,085 $557,612
Standardized measure of discounted future net cash flows
($000)(2)(3)(5)........................................... $179,660 $231,763 $437,599
Reserve replacement percentage.............................. 242.3% 527.2% 703.8%
Reserve life (in years)..................................... 8.2 9.2 11.8
</TABLE>
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
--------------------------- -----------------
1994 1995 1996 1996 1997
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
NET PRODUCTION DATA:
Oil (Mbbls)................................................. 211 196 758 547 1,295
Liquids..................................................... -- -- -- -- 101
Natural gas (MMcf):
Tennessee Gas Contract.................................... 6,851 6,924 4,645 3,576 --
Other..................................................... 4,453 12,205 20,936 15,346 32,806
------- ------- ------- ------- -------
Total................................................... 11,304 19,129 25,581 18,922 32,806
Total (MMcfe)............................................... 12,570 20,305 30,129 22,204 41,180
OTHER DATA:
Average prices:
Oil (per bbl)............................................. $ 15.16 $ 17.28 $ 20.69 $ 19.72 $ 18.92
Liquids (per bbl)......................................... -- -- -- -- 11.05
Natural gas (per Mcf):
Tennessee Gas Contract.................................. 7.49 7.90 8.40 8.38 --
Other................................................... 1.81 1.62 2.35 2.29 2.28
Average................................................. 5.54 4.29 3.61 3.61 2.28
Average equivalent price (per Mcfe)......................... $ 5.27 $ 4.27 $ 3.59 $ 3.56 $ 2.44
Lifting cost (per Mcfe)(6).................................. 0.56 0.33 0.39 0.37 0.60
General and administrative expense (per Mcfe)............... 0.39 0.23 0.26 0.25 0.18
------- ------- ------- ------- -------
Cash margin (per Mcfe)...................................... $ 4.32 $ 3.71 $ 2.94 $ 2.94 $ 1.66
======= ======= ======= ======= =======
</TABLE>
- ---------------
(1) Reflects estimated future cash inflows less future production and
development costs.
(2) Estimates at December 31, 1994 and 1995 reflect the contract price for
natural gas to be delivered from the Bob West Field under the Tennessee Gas
Contract until January 1999. In December 1996, the contract was terminated
by agreement of the parties effective January 1, 1997.
(3) Other than gas and oil sold under contractual arrangements including swaps,
futures contracts and options, reflects average realized gas prices of
$1.50, $2.03 and $3.54 per Mcf and average realized oil prices of $16.99,
$18.23 and $22.45 per bbl in effect at December 31, 1994, 1995 and 1996,
respectively.
(4) Reflects estimated future net revenue before income taxes discounted at 10%
per annum.
(5) Reflects estimated future net revenue less future income taxes discounted at
10% per annum.
(6) Includes lease operating expenses and production taxes.
9
<PAGE> 10
RISK FACTORS
In addition to the other information set forth in this Prospectus,
prospective purchasers of the Notes should carefully consider the following risk
factors in evaluating an investment in the Notes. 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 "Special Note on 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. From time to time, oil and gas prices
have been depressed by excess domestic and imported supplies. There can be no
assurance that current price levels will be sustained, and it is impossible to
predict future oil and gas price movements with any certainty. 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. Additionally,
substantially all of the Company's sales of oil and gas are made in the spot
market and not pursuant to long-term fixed price contracts. With the objective
of reducing price risk, the Company may from time to time enter into hedging
transactions with respect to a portion of its expected future production. See
"-- Risks of Hedging Transactions." There can be no assurance that such hedging
transactions will reduce risk or mitigate the effect of any substantial or
extended decline in oil or gas prices. Any substantial or extended decline in
the prices of oil or gas would have a material adverse effect on the Company's
financial condition and results of operations.
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 and exploratory drilling. The decision to acquire a business or
to purchase, explore or develop an interest in a 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 assets (including
the Credit Facility and the Revolving Credit Agreement, as defined herein, the
"Bank Credit Facilities"). The Company anticipates that the net proceeds from
the sale of the Notes, 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 $183
million of capital expenditures currently budgeted for drilling and acquisition
activities in 1998. 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
10
<PAGE> 11
new reserves. If revenues were to decrease as a result of lower oil and gas
prices, decreased production or otherwise, and the Company had no availability
under the 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 the 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.
UNCERTAINTY OF ESTIMATES OF OIL AND GAS 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. 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. The Company's
properties may also be susceptible to hydrocarbon drainage from production by
other operators of adjacent properties. 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."
Approximately 13% of the Company's total proved reserves as of December 31,
1996 were undeveloped, which are by their nature less certain. Recovery of such
reserves will require substantial capital expenditures by the Company and the
successful completion of drilling operations. The Company's reserve data assume
that substantial capital expenditures by the Company will be required to develop
such reserves. Although cost and reserve estimates attributable to the Company's
reserves have been prepared in accordance with industry standards, no assurance
can be given that the estimated costs are accurate, that development will occur
as scheduled or that the results will be as estimated. See "Business and
Properties -- Oil and Gas Reserves."
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 (the "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.
The Company provides for depreciation, depletion and amortization ("DD&A")
using the future gross revenue method based on recoverable reserves valued at
current prices. See Note 1 to Consolidated Financial Statements -- "Property,
Plant and Equipment" for a description of how the Company provides for DD&A and
the related limitation on capitalized oil and gas property costs. Significant
declines in oil and gas prices,
11
<PAGE> 12
like those experienced in early 1997, if not offset by increases in proved oil
and gas reserves, could result in a substantial increase in non-cash DD&A
accruals and could negatively impact earnings.
SUBSTANTIAL INDEBTEDNESS AND RESTRICTIONS
At September 30, 1997, the Company had outstanding $150 million in 11%
Senior Notes due 2003 (the "Senior Notes") issued pursuant to an indenture
governing the Senior Notes (the "Senior Notes Indenture") and approximately
$126.2 million of outstanding indebtedness under the Bank Credit Facilities
(which amount has increased since such date). See "Use of Proceeds" and
"Capitalization." Giving effect to the Offering and the application of the net
proceeds to repay amounts owed under the Bank Credit Facilities, the Company
expects to have approximately $145 million available for borrowing under the
Bank Credit Facilities immediately after the sale of the Notes offered hereby.
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 Senior Notes Indenture require the Company to meet
certain financial tests. Other restrictions will also limit the Company's
ability to borrow additional funds and may affect its 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 or the Senior Notes Indenture.
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, the Senior Notes
Indenture 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.
SUBORDINATION OF NOTES
The Notes will be subordinate in right of payment to all current and future
Senior Indebtedness of the Company, including the Bank Credit Facilities and the
Senior Notes. Senior Indebtedness will include all indebtedness of the Company,
whether existing on or created or incurred after the issuance of the Notes, that
is not made subordinate to or pari passu with the Notes by the instrument
creating the indebtedness. At September 30, 1997, the aggregate amount of the
Company's Senior Indebtedness was approximately $276.2 million. By reason of the
subordination of the Notes, in the event of insolvency, bankruptcy, liquidation,
reorganization, or similar proceeding in relation to the Company or upon default
in payment with respect to certain Senior Indebtedness of the Company or an
event of default with respect to such indebtedness permitting the acceleration
thereof, the assets of the Company will be available to pay the amounts due on
the Notes only after all or certain of the Senior Indebtedness of the Company
has been paid in full. There can be no assurance that the assets of the Company
will be sufficient for that purpose at the time such payment is due. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources" and "Description of the
Notes -- Subordination."
RISKS RELATING TO ENFORCEABILITY OF SUBSIDIARY GUARANTEES
The Company's payment obligations under the Notes will be jointly and
severally guaranteed by all of its current and certain future subsidiaries. To
the extent that a court were to find that (i) a guarantee was incurred by a
subsidiary guarantor with the intent to hinder, delay or defraud any present or
future creditor, (ii) the subsidiary guarantor contemplated insolvency with a
design to prefer one or more creditors to the exclusion in whole or in part of
others or (iii) such subsidiary guarantor did not receive fair consideration or
reasonably equivalent value for issuing its guarantee and such subsidiary
guarantor (w) was insolvent, (x) was rendered insolvent by reason of the
issuance of such guarantee, (y) was engaged or about to engage in a business or
transaction for which the remaining assets of such subsidiary guarantor
constituted unreasonably small capital to carry on its business or (z) intended
to incur, or believed that it would incur, debts beyond its
12
<PAGE> 13
ability to pay such debts as they matured, the court, subject to applicable
statutes of limitations, could avoid or subordinate such guarantee in favor of a
subsidiary guarantor's creditors or take other action detrimental to the holders
of the Notes. Among other things, a legal challenge of a guarantee on fraudulent
conveyance grounds may focus on the benefits, if any, realized by a subsidiary
guarantor as a result of the issuance by the Company of the Notes.
To the extent any guarantees were avoided as a fraudulent conveyance or
held unenforceable for any other reason, holders of the Notes would cease to
have any claim in respect of such subsidiary guarantor and would be creditors
solely of the Company and any subsidiary guarantor whose guarantee was not
avoided or held unenforceable. In such event, the claims of holders of the Notes
against the issuer of an invalid guarantee would be subject to the prior payment
of all liabilities of such subsidiary guarantor. There can be no assurance that,
after providing for all prior claims, there would be sufficient assets remaining
to satisfy the claims of the holders of the Notes relating to any avoided
portions of any of the guarantees. In addition, if a court were to avoid the
guarantees under fraudulent conveyance laws or other legal principles or, by the
terms of such guarantees, the obligations thereunder were reduced as necessary
to prevent such avoidance, or the guarantees were released, the claims of other
creditors of the subsidiary guarantors, including trade creditors, would to such
extent have priority as to the assets of such subsidiary guarantors over the
claims of holders of the Notes.
The guarantees of the Notes by any subsidiary guarantor will be released in
certain circumstances. See "Description of the Notes -- Subsidiary Guarantees of
Notes."
LIMITATIONS ON REPURCHASE UPON A CHANGE OF CONTROL
In the event of a Change of Control (as defined in the Indenture) each
holder of Notes will have the right, at the holder's option, to require the
Company to repurchase all or a portion of such holder's Notes at a purchase
price equal to 101% of the principal amount thereof plus accrued interest
thereon to the repurchase date. The Company's ability to repurchase the Notes
upon a Change of Control may be limited by the terms of the Company's Senior
Indebtedness and the subordination provisions of the Indenture. Further, the
ability of the Company to repurchase Notes upon a Change of Control will be
dependent on the availability of sufficient funds and compliance with applicable
securities laws. Accordingly, there can be no assurance that the Company will be
able to repurchase the Notes upon a Change of Control. The term "Change of
Control" is limited to certain specified transactions and may not include other
events that might adversely affect the financial condition of the Company or
result in a downgrade of the credit rating (if any) of the Notes nor would the
requirement that the Company offer to repurchase the Notes upon a Change of
Control necessarily afford holders of the Notes protection in the event of a
highly leveraged reorganization, merger or similar transaction involving the
Company. See "Description of the Notes."
RISKS OF HEDGING TRANSACTIONS
In order to manage its exposure to price risks in the marketing of its oil
and gas, the Company has in the past entered into, and expects to continue to
enter into, oil and gas price hedging arrangements with respect to a portion of
its expected production. These arrangements may include futures contracts and
options sold on the New York Mercantile Exchange ("NYMEX") and
privately-negotiated forwards, swaps and options. While intended to reduce the
effects of volatility of oil and gas prices, such transactions may limit
potential gains by the Company if oil and gas prices were to rise substantially
over the prices established by hedging. In addition, such transactions may
expose the Company to the risk of financial loss in certain circumstances,
including instances in which (i) production is less than expected, (ii) there is
a widening of price differentials between delivery points for the Company's
production and the delivery point assumed in hedging arrangements, (iii) the
counterparties to the Company's future contracts fail to perform the contracts,
(iv) the Company fails to make timely deliveries or (v) a sudden, unexpected
event materially impacts oil or gas prices. See "Business and
Properties -- Marketing of Oil and Gas Production" and Note 8 to Consolidated
Financial Statements.
13
<PAGE> 14
EXPLORATION AND DEVELOPMENT RISKS
Exploratory drilling and development drilling 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. 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.
SHORTAGES OF RIGS, EQUIPMENT, SUPPLIES AND PERSONNEL
There is a general shortage of drilling rigs, equipment, supplies and
personnel which the Company believes may intensify. The costs and delivery times
of rigs, equipment, supplies and personnel are substantially greater than in
prior periods and currently are escalating. The demand for, and wage rates of,
qualified drilling rig crews have begun to rise in the drilling industry in
response to the increasing number of active rigs in service. Such shortages have
in the past occurred in the industry in times of increasing demand for drilling
services. If the number of active drilling rigs continues to increase, the oil
and gas industry may experience shortages of qualified personnel to operate
drilling rigs. Shortages of drilling rigs, equipment or supplies could delay and
adversely affect the Company's exploration and development operations, which
could have a material adverse effect on its financial condition and results of
operations.
MARKETING RISKS
The Company's ability to market oil and gas at commercially acceptable
prices is dependent upon the availability, and capacity, of gas gathering
systems, pipeline and processing facilities. The unavailability or lack of
capacity thereof could result in the shut-in of producing wells or the delay or
discontinuance of development plans for properties. Federal and state regulation
of oil and gas production and transportation, general economic conditions and
changes in supply and demand all could adversely affect the Company's ability to
produce and market its oil and gas. If market factors were to change
dramatically, the financial impact on the Company could be substantial. The
availability of markets and the volatility of product prices are beyond the
control of the Company and represent a significant risk.
ACQUISITION RISKS
Acquisitions of oil and gas businesses, working interests in 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 of the major properties it seeks to acquire
that it believes is consistent with industry practices (including a limited
review of title and other records), 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 of
operations. The Company's operations
14
<PAGE> 15
may be materially curtailed, delayed or canceled as a result of numerous
factors, including the presence of unanticipated pressure or irregularities in
formations, a high percentage of hydrogen sulfide gas ("sour gas"), title
problems, weather conditions, accidents, compliance with governmental
requirements and shortages or delays in the delivery of equipment. A number of
the Company's wells are currently shut-in due to the presence of quantities of
sour gas. Despite the Company's commitment of both financial and operational
resources in the Manderson Field, oil and gas production did not increase
significantly from this area during 1997. To the extent that mechanical,
equipment, weather and other delays continue to prevent the Company from
increasing production from the field, revenues and other aspects of the
Company's financial performance could be adversely affected. See "Business and
Properties -- Rocky Mountain Region -- Manderson Field." 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. In addition, in the
future, the Company may shut in wells due to the production of excess quantities
of sour gas, a risk against which it does not maintain insurance.
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."
ABSENCE OF PUBLIC MARKET FOR THE NOTES
Prior to this Offering, there has been no trading market for the Notes.
Although the Underwriters have advised the Company that they currently intend to
make a market in the Notes, they are not obligated to do so and may discontinue
such market making at any time without notice. In addition, such market making
activity will be subject to the limits imposed by the Securities Act and the
Exchange Act. Accordingly, although the Notes have been approved for listing on
the NYSE (subject to official notice of issuance), there can be no assurance
that any market for the Notes will develop or, if one does develop, that it will
be maintained. If an active market for the Notes fails to develop or be
sustained, the trading price of the Notes could be materially adversely
affected.
15
<PAGE> 16
SPECIAL NOTE ON 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 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" are forward-looking statements. Such statements include, without
limitation, discussions regarding planned capital expenditures, the Company's
financial position, business strategy and other plans and objectives for future
operations. 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. Such forward-looking
statements involve known and unknown risks, uncertainties, and other factors
that may cause actual results, performance or achievements to differ materially
from any future results, performance or achievements expressed or implied by
such forward-looking statements. 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
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.
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<PAGE> 17
USE OF PROCEEDS
The net proceeds to the Company from the Notes offered hereby are estimated
to be approximately $121 million, after deducting estimated offering expenses
payable by the Company. These estimated net proceeds will be used by the Company
to reduce the outstanding indebtedness under the Bank Credit Facilities. The
Bank Credit Facilities have been used historically to fund the Company's capital
expenditure program, including the Rocky Mountain and Medallion Acquisitions,
the Manderson Field development drilling program and the continued growth of the
VPP program. Consistent with past practice, the Company intends to use the
resulting borrowing capacity under these facilities to fund its future capital
expenditure program.
On December 26, 1997, the outstanding balance under the Bank Credit
Facilities was $140.6 million. The Bank Credit Facilities permit 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. The weighted average
interest rate on bank borrowings on September 30, 1997 was 7.2%. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- Debt Financing" and
"Description of Existing Indebtedness."
CAPITALIZATION
The following table sets forth the Company's capitalization at September
30, 1997, and as adjusted to give effect to the issuance of the Notes offered
hereby and the application of the estimated 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" and
the Company's Consolidated Financial Statements (including the notes thereto)
included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
SEPTEMBER 30, 1997
----------------------
ACTUAL AS ADJUSTED
-------- -----------
(IN THOUSANDS)
<S> <C> <C>
Long-term debt:
Bank Credit Facilities.................................... $126,200 $ 5,206
11% Senior Notes due 2003................................. 149,523 149,523
8 7/8% Senior Subordinated Notes due 2008................. -- 125,000
-------- --------
Total long-term debt.............................. 275,723 279,729
-------- --------
Stockholders' equity:
Preferred stock: 5,000,000 shares authorized; none
issued................................................. -- --
Common stock, par value $0.01 per share: 50,000,000 shares
authorized; 31,198,390 issued.......................... 312 312
Additional paid-in capital................................ 143,718 143,718
Retained earnings......................................... 111,348 111,348
Less treasury stock, 1,801,496 shares at cost............. (3,388) (3,388)
-------- --------
Total stockholders' equity........................ 251,990 251,990
-------- --------
Total capitalization.............................. $527,713 $531,719
======== ========
</TABLE>
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<PAGE> 18
KCS ENERGY, INC.
SELECTED HISTORICAL FINANCIAL INFORMATION
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
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. The historical data
for the years ended December 31, 1992, 1993, 1994, 1995 and 1996 and for the
nine months ended September 30, 1996 (i) includes revenues attributable to the
Tennessee Gas Contract which was terminated effective January 1, 1997 and (ii)
has been restated to reflect the discontinuation of the Company's natural gas
transportation and marketing operations in 1997.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------------------------------------------- -------------------------
1992 1993 1994 1995 1996 1996 1997
----------- ----------- ----------- ----------- ----------- ----------- -----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenue:
Oil and gas revenue(1)........ $ 13,496 $ 40,455 $ 66,215 $ 86,629 $ 108,015 $ 79,051 $ 100,396
Other revenue, net............ 568 973 1,185 486 359 377 3,702
----------- ----------- ----------- ----------- ----------- ----------- -----------
Total................... 14,064 41,428 67,400 87,115 108,374 79,428 104,098
Operating costs and expenses:
Lease operating expenses...... 2,223 4,598 6,218 6,156 9,167 6,582 20,470
Production taxes.............. 391 411 845 467 2,526 1,671 4,354
General and administrative
expenses.................... 3,190 4,158 4,853 4,704 7,825 5,411 7,302
Depreciation, depletion and
amortization................ 2,985 7,179 18,783 38,231 45,460 33,128 42,486
----------- ----------- ----------- ----------- ----------- ----------- -----------
Total................... 8,789 16,346 30,699 49,558 64,978 46,792 74,612
----------- ----------- ----------- ----------- ----------- ----------- -----------
Operating income................ 5,275 25,082 36,701 37,557 43,396 32,636 29,486
Interest and other income,
net........................... 659 1,022 1,175 4,472 5,086 4,820 388
Interest expense................ (217) (1,125) (2,004) (6,807) (14,085) (11,193) (15,146)
----------- ----------- ----------- ----------- ----------- ----------- -----------
Income from continuing
operations before income
taxes......................... 5,717 24,979 35,872 35,222 34,397 26,263 14,728
Federal and state income
taxes......................... 1,581 7,450 12,269 11,817 12,680 9,483 5,452
----------- ----------- ----------- ----------- ----------- ----------- -----------
Income from continuing
operations.................... 4,136 17,529 23,603 23,405 21,717 16,780 9,276
Discontinued operations:
Net income (loss) from
operations.................. (126) 1,082 554 (2,099) (1,845) (1,974) (72)
Net gain on disposition....... -- -- -- -- -- -- 5,461
----------- ----------- ----------- ----------- ----------- ----------- -----------
Net income...................... $ 4,010 $ 18,611 $ 24,157 $ 21,306 $ 19,872 $ 14,806 $ 14,665
=========== =========== =========== =========== =========== =========== ===========
Earnings per share:
Continuing operations......... $ 0.19 $ 0.75 $ 1.00 $ 1.00 $ 0.91 $ 0.70 $ 0.32
Discontinued operations....... (0.01) 0.05 0.02 (0.09) (0.08) (0.08) 0.18
----------- ----------- ----------- ----------- ----------- ----------- -----------
Total................... $ 0.18 $ 0.80 $ 1.02 $ 0.91 $ 0.83 $ 0.62 $ 0.50
Average common shares
outstanding................... 22,276 23,317 23,610 23,521 23,811 23,773 29,449
Dividends per common share...... $ 0.015 $ 0.030 $ 0.045 $ 0.060 $ 0.060 $ 0.045 $ 0.050
OTHER DATA (UNAUDITED):
Tennessee Gas Contract
premium(2).................... $ 4,059 $ 22,544 $ 42,828 $ 52,007 $ 32,829 $ 25,689 $ --
EBITDA(3)....................... 8,260 32,261 55,484 75,788 88,856 65,764 71,972
Capital expenditures............ 13,867 48,455 74,953 128,699 277,218 52,735 171,884
Ratio of earnings to fixed
charges(4).................... 17.0x 20.7x 17.7x 6.1x 3.4x 3.3x 2.0x
Ratio of EBITDA to interest
expense....................... 38.1x 28.7x 27.7x 11.1x 6.3x 5.9x 4.8x
BALANCE SHEET DATA (AT END OF
PERIOD):
Cash and cash equivalents....... $ 4,292 $ 5,369 $ 988 $ 5,846 $ 5,100 $ 53,597 $ 3,858
Working capital................. 23,924 29,396 33,969 81,953 30,755 78,497 7,707
Oil and gas properties, net..... 30,828 70,477 125,621 204,958 415,870 206,308 540,896
Total assets.................... 60,579 117,640 176,179 306,564 511,820 321,157 614,043
Long-term debt.................. 21,637 36,289 61,970 165,529 310,347 149,830 275,723
Total stockholders' equity...... 30,233 59,765 80,668 101,576 125,622 116,312 251,990
</TABLE>
- ---------------
(1) Includes revenues attributable to the Tennessee Gas Contract, for the years
ended December 31, 1992, 1993, 1994, 1995 and 1996 and for the nine months
ended September 30, 1996, that was terminated effective January 1, 1997.
(2) Reflects revenues associated with the natural gas production covered by the
above-market prices provided for in the Tennessee Gas Contract in excess of
the revenues that would otherwise have been received for such production at
spot market prices.
(3) 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.
(4) For purposes of calculating the ratio of earnings to fixed charges, fixed
charges include interest expense and that portion of non-capitalized rental
expense deemed to be the equivalent of interest. Earnings represents income
before income taxes from continuing operations before fixed charges.
18
<PAGE> 19
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 Pipeline Company
("Tennessee Gas") entered into a settlement covering all claims and litigation
between them related to the above-market, take-or-pay contract (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, and the parties also agreed to the dismissal of the contract
dispute that resulted in a November 1996 jury award to Tennessee Gas unfavorable
to the Company. See Note 9 to Consolidated Financial Statements. Prior to its
termination, the Tennessee Gas Contract had a material and positive effect on
the Company's gas revenue, income and cash flow. 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 in September 1996 of approximately $70 million in past
underpayments that had accrued under the contract.
As of December 31, 1996, the Company completed the arrangements for the
Medallion Acquisition (see Note 2 to Consolidated Financial Statements) for a
total purchase price of approximately $199.1 million, consisting of $194.1
million in cash and warrants to purchase 870,000 shares of Common Stock at an
exercise price of $22.50 per share with a four-year term.
During the first quarter of 1997, the Company sold its principal natural
gas transportation asset, the Texas intrastate pipeline, for a net sale price of
$27.9 million and realized an after-tax gain of $5.9 million. In addition, the
Company sold its gas marketing operations. Accordingly, the financial statements
included in this Prospectus have been restated to reflect the natural gas
transportation and marketing operations as discontinued operations.
These developments have transformed the Company from an enterprise heavily
dependent on the Bob West Field and the Tennessee Gas Contract, with significant
marketing and transportation operations, to a Company focused on exploration and
production, with a portfolio of operations in three core operating areas (the
Gulf Coast region, the Rocky Mountain region and the Mid-Continent/West Texas
region), and its VPP program. Production from the Bob West Field, which in 1993
accounted for 55% of total production and 78% of the Company's oil and gas
revenues, is expected to account for less than 5% of production and revenues in
1997.
The Company completed a two-for-one-stock split effective June 30, 1997.
All per share data and data relating to the number of outstanding shares of
Common Stock in this Prospectus have been adjusted to reflect the stock split.
RESULTS OF OPERATIONS FOR NINE MONTHS ENDED SEPTEMBER 30, 1997 AND SEPTEMBER 30,
1996
Results of Operations -- Consolidated
Net income for the nine months ended September 30, 1997 was $14.7 million,
or $0.50 per share, compared to $14.8 million, or $0.62 per share for the nine
months ended September 30, 1996. Income from continuing operations for the nine
months ended September 30, 1997 was $9.3 million, or $0.32 per share, compared
to $16.8 million, or $0.70 per share for the nine months ended September 30,
1996. Significantly higher oil and gas production during 1997 was more than
offset by the impact of the termination of the Tennessee Gas Contract and higher
net interest costs. In addition, current year earnings per share reflects the
19
<PAGE> 20
effect of six million additional shares of Common Stock outstanding following
the Company's public equity offering in January 1997. Net income for the current
nine-month period included net income of $5.4 million, or $0.18 per share, from
discontinued operations, principally from the gain on the sale of the Texas
intrastate pipeline system.
Revenue
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
-------------------
1996 1997
------- --------
<S> <C> <C>
Production:
Oil (Mbbl)................................................ 547 1,295
Liquids (Mbbl)............................................ -- 101
Gas (MMcf)................................................ 18,922 32,806
Total (MMcfe)..................................... 22,204 41,180
Average Prices:
Oil (per bbl)............................................. $ 19.72 $ 18.92
Liquids (per bbl)......................................... -- 11.05
Gas (per Mcf)............................................. 3.61 2.28
Total (per Mcfe).................................. 3.56 2.44
Revenue:
Oil....................................................... $10,779 $ 24,501
Liquids................................................... -- 1,113
Gas....................................................... 68,272 74,782
------- --------
Total............................................. $79,051 $100,396
</TABLE>
Oil and Gas Production. The Company's oil and gas production during the
nine months ended September 30, 1997 increased 85% to 41.2 Bcfe, compared to
22.2 Bcfe produced during the same period in 1996. For the nine months ended
September 30, 1997, oil and liquids production increased 155% to 1,396 Mbbls and
gas production increased 73% to 32.8 Bcf, compared to the same period in 1996.
The production increases were primarily as a result of the Medallion
Acquisition.
Gas Revenue. For the nine months ended September 30, 1997, gas revenues
increased $6.5 million to $74.8 million. Production gains added $31.9 million of
gas revenue during the 1997 period. This increase was largely offset by the
termination of the Tennessee Gas Contract, which provided $25.7 million in
premium over corresponding spot market prices in the nine-month period ended
September 30, 1996. Average realized prices for gas not covered by the Tennessee
Gas Contract were $2.28 and $2.29 per Mcf in the 1997 and 1996 nine-month
periods, respectively.
Oil and Liquids Revenue. For the nine months ended September 30, 1997, oil
and liquids revenue increased $14.8 million to $25.6 million. Production gains
added $15.3 million of oil and liquids revenue, partially offset by lower
average realized prices.
Other Revenue, Net
Other revenue includes certain marketing and gathering revenues incidental
to the Company's oil and gas exploration and production operations. The
increases for the nine months ended September 30, 1997 over the same period in
1996 were primarily the result of the Medallion Acquisition. The 1997 nine-month
total includes $1.3 million from the settlement of a gas sales contract dispute
during the second quarter of 1997.
Lease Operating Expenses
As a result of the substantial increase in oil and gas production, lease
operating expenses increased $13.9 million to $20.5 million for the nine months
ended September 30, 1997, compared to the same period in 1996. Approximately
$12.3 million of the increase was related to the Medallion properties, with the
remainder
20
<PAGE> 21
of the increase primarily due to the expanded operations in the Rocky Mountain
region, especially in the Manderson Field.
Production Taxes
Production taxes, which are generally based on a fixed percentage of
revenue, increased 161% to $4.4 million during the nine months of 1997, compared
to the same period in 1996. In addition to the effect of higher oil and gas
revenue during the 1997 period, a larger percentage of that revenue was subject
to severance taxes as a result of the termination of the Tennessee Gas Contract
which provided for reimbursement to the Company of severance taxes on production
covered under that contract.
General and Administrative Expenses
For the nine months ended September 30, 1997, general and administrative
expenses increased $1.9 million to $7.3 million, compared to the same period in
1996. This increase was primarily the result of the overall growth of the
Company, including expansion in the Mid-Continent region as a result of the
Medallion Acquisition and expanded VPP operations.
Depreciation, Depletion and Amortization
The Company provides for depreciation, depletion and amortization ("DD&A")
on its oil and gas properties using the future gross revenue method based on
recoverable reserves valued at current prices. For the nine months ended
September 30, 1997, DD&A on the Company's oil and gas properties increased $8.1
million over the same period in 1996. Production gains increased DD&A by $8.7
million, partially offset by a $0.6 million reduction attributable to a decline
in the DD&A rate. In addition, depreciation on assets other than oil and gas
properties increased $1.3 million primarily due to the expansion of the
Company's operations in the Mid-Continent and Rocky Mountain regions.
Interest and Other Income, Net
Interest and other income was lower during the nine-month period ended
September 30, 1997 compared to the same period in 1996 primarily due to the
absence of interest income on outstanding receivables related to the Tennessee
Gas litigation. The outstanding receivables plus interest were paid by Tennessee
Gas on September 30, 1996.
Interest Expense
Interest expense increased $4.0 million to $15.1 million for the nine
months ended September 30, 1997, as compared to the same period in 1996. Higher
average borrowings in 1997 due to the expansion of the Company's oil and gas
operations (including the Medallion Acquisition, the VPP program and the
development of the Manderson Field) were offset in part by lower average
interest rates during the period.
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
Results of Operations
Net income for the year ended December 31, 1996 was $19.9 million, or $0.83
per share, compared to $21.3 million, or $0.91 per share, for the year ended
December 31, 1995. Income from continuing operations was $21.7 million, or $0.91
per share, for the year ended December 31, 1996, compared to $23.4 million, or
$1.00 per share, for the year ended December 31, 1995. Significantly higher oil
and gas production, along with higher oil and gas prices in 1996 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. Loss from discontinued operations in 1996 was $1.8
million, or $0.08 per share, compared to a loss of $2.1 million, or $0.09 per
share, in 1995.
Net income for the year ended December 31, 1995 was $21.3 million, or $0.91
per share, compared to $24.2 million, or $1.02 per share, for the year ended
December 31, 1994. Income from continuing operations
21
<PAGE> 22
was $23.4 million, or $1.00 per share, for 1995, compared to $23.6 million, or
$1.00 per share, for 1994. A significant increase in gas production in 1995,
compared to 1994, was offset by the impact of lower natural gas prices and
higher net interest costs. Loss from discontinued operations in 1995 was $2.1
million, or $0.09 per share, compared to income from discontinued operations of
$0.6 million, or $0.02 per share, in 1994. Lower natural gas prices and the
absence of severe weather conditions during the peak 1994/1995 winter heating
season were the primary reasons for the 1995 loss from discontinued operations.
Revenue
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1994 1995 1996
------- ------- --------
<S> <C> <C> <C>
Production:
Oil (Mbbl)......................................... 211 196 758
Gas (MMcf)......................................... 11,304 19,129 25,581
Total (MMcfe).............................. 12,570 20,305 30,129
Average Prices:
Oil (per bbl)...................................... $ 15.16 $ 17.28 $ 20.69
Gas (per Mcf)...................................... 5.54 4.29 3.61
Total (per Mcfe)........................... 5.27 4.27 3.59
Revenue:
Oil................................................ $ 3,198 $ 3,387 $ 15,684
Gas................................................ 63,017 83,242 92,331
------- ------- --------
Total...................................... $66,215 $86,629 $108,015
</TABLE>
Oil and Gas Production. The Company's oil and gas production during 1996
increased 48% to 30.1 Bcfe, compared to 20.3 Bcfe produced during 1995. Oil
production increased 286% to 758 Mbbls and gas production increased 34% to 25.6
Bcf. Approximately 6.7 Bcfe of the increase in oil and gas production was
attributable to the Company's VPP program, with the remainder resulting from a
combination of lease acquisitions, exploration and development drilling.
Oil and gas production during 1995 increased 62% to 20.3 Bcfe, compared to
12.6 Bcfe in 1994, primarily due to higher gas and oil volumes delivered under
the Company's VPP program.
Gas Revenue. In 1996, gas revenues increased $9.1 million to $92.3 million.
Higher production from properties not covered by the Tennessee Gas Contract
along with higher average non-Tennessee Gas Contract prices more than offset the
impact of lower production from the properties covered by the Tennessee Gas
Contract. Sales under the Tennessee Gas Contract decreased to 4.6 Bcf in 1996
compared to 6.9 Bcf during 1995, largely due to the normal production decline
from existing wells. Average natural gas prices were $3.61 per Mcf in 1996,
compared to $4.29 per Mcf in 1995. This decrease reflected the lower percent of
production covered by the Tennessee Gas Contract. Average non-Tennessee Gas
Contract gas prices were $2.35 per Mcf in 1996, compared to $1.62 per Mcf in
1995. Natural gas sale prices under the Tennessee Gas Contract, excluding
severance tax reimbursements, were $8.40 in 1996, compared to $7.90 in 1995.
The early termination of the Tennessee Gas Contract, with its above-market
pricing provisions, resulted in downward revisions in the amounts of $37.1
million for estimated future net revenues before income taxes (based upon a
natural gas price of $3.69 per Mcf, the assumed realized price on December 31,
1996) and $34.7 million for PV-10.
With the termination of the Tennessee Gas Contract, the Company's earnings
have been and will continue to be more heavily impacted by changing energy
prices. Not only is the Company's oil and gas revenue more sensitive to spot
market price changes, but significant declines in oil and gas prices, like those
experienced in early 1997, if not offset by increases in proved oil and gas
reserves, could result in a substantial increase in non-cash depreciation,
depletion and amortization ("DD&A") accruals and could negatively impact
earnings. The Company provides for DD&A using the future gross revenue method
based on recoverable reserves valued at current prices. See Note 1 to
Consolidated Financial Statements -- "Property,
22
<PAGE> 23
Plant and Equipment" for a description of how the Company provides for DD&A and
the related limitation on capitalized oil and gas property costs. The Company
utilizes commodity price swaps, futures and options contracts and basis swaps
(see Note 8 to Consolidated Financial Statements) to help mitigate the impact of
fluctuations in the price of its natural gas and oil production.
Gas revenues in 1995 increased $20.2 million to $83.2 million. Higher
production from properties not covered by the Tennessee Gas Contract was
partially offset by lower average non-Tennessee Gas Contract prices. Sales to
Tennessee Gas were 6.9 Bcf in both 1995 and 1994. Average natural gas prices
were $4.29 per Mcf in 1995, compared to $5.54 per Mcf in 1994. This decrease
resulted from lower non-Tennessee Gas Contract gas prices of $1.62 in 1995,
compared to $1.81 in 1994. Natural gas sale prices under the Tennessee Gas
Contract, excluding severance tax reimbursements, were $7.90 in 1995, compared
to $7.49 in 1994.
Oil Revenue. In 1996, oil revenue increased $12.3 million to $15.7 million,
compared to 1995. Production gains, primarily from properties in the Rocky
Mountain region added $11.6 million. The remainder of the increase was due to
higher average oil prices.
Oil revenue in 1995 increased $0.2 million to $3.4 million mainly due to
higher average oil prices.
Lease Operating Expenses
For the year ended December 31, 1996, lease operating expenses increased
$3.0 million to $9.2 million, or $0.30 per Mcfe, primarily due to production
increases in the Rocky Mountain region over 1995 lease operating expenses of
$6.2 million, or $0.30 per Mcfe, and $6.2 million, or $0.49 per Mcfe, in 1994.
The reduction in rate per Mcfe in 1995 compared to 1994 was primarily due to
higher VPP volumes which do not bear any development or lease operating
expenses.
Production Taxes
Production taxes increased $2.1 million to $2.5 million in 1996 over 1995
primarily due to the increased revenue and, to a lesser extent, an increase in
average production tax rates, which are higher in the Rocky Mountain region as
compared to the Gulf Coast region. In addition, a larger percentage of the
Company's revenue was subject to production taxes in 1996, as compared to 1995,
due to the decline in production covered under the Tennessee Gas Contract, which
provided for reimbursement of severance taxes.
In 1995, production taxes were $0.5 million, compared to $0.8 million in
1994. While total revenue increased significantly, revenue subject to production
taxes was down slightly. The overall increase in revenue was mainly due to the
VPP program, which generally are free of production taxes.
General and Administrative Expenses
In 1996, general and administrative expenses were $7.8 million, compared to
$4.7 million in 1995. The increase reflected the overall growth of the Company,
most notably the expansion into the Rocky Mountain region. In 1995, general and
administrative expenses decreased slightly to $4.7 million, compared to $4.9
million in 1994.
Depreciation, Depletion and Amortization
For the year ended December 31, 1996, depreciation, depletion and
amortization ("DD&A") increased $7.2 million over DD&A for 1995 to $45.5 million
due to the increase in oil and gas revenue, which was partially offset by a
reduction in the DD&A rate to 41.7% in 1996 from 43.9% in 1995.
In 1995, DD&A increased $19.4 million over 1994 DD&A to $38.2 million due
to the increase in oil and gas revenue and an increase in the DD&A rate to 43.9%
in 1995 from 28% in 1994. The increase in the DD&A rate in 1995 reflects the
relative increase in the percentage of total proved reserves not covered by the
Tennessee Gas Contract.
23
<PAGE> 24
Interest and Other Income, Net
Interest and other income was $5.1 million in 1996, compared to $4.5
million in 1995 and $1.2 million in 1994. Of these amounts, $4.4 million, $3.1
million and $0.2 million for the years 1996, 1995 and 1994, respectively,
represented interest income accrued on the Tennessee Gas receivable. These
amounts were included in the September 1996 cash payment received from Tennessee
Gas. The Tennessee Gas Contract was terminated effective January 1, 1997. See
Note 9 to Consolidated Financial Statements.
Interest Expense
Interest expense was $14.1 million in 1996, compared to $6.8 million in
1995 and $2.0 million in 1994. 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 11% Senior Notes in January 1996. Higher average
borrowings in 1996, compared to 1995, as well as in 1995 compared to 1994, were
used to expand the Company's operations. The increases in interest expense
during the periods were partially offset by the increase in interest income as
discussed above.
Income Taxes
The income tax provision was $12.7 million in 1996, representing an
effective tax rate of 36.9%, compared to effective rates of 33.6% and 34.2% in
1995 and 1994, respectively. See Note 7 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 reflected on the
Company's income statements during these periods is deferred to future years.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flow From Operating Activities
Net income adjusted for non-cash charges increased to $57.6 million for the
nine months ended September 30, 1997, compared to $54.2 million during the same
period in 1996. The increase reflects cash flow from the properties acquired as
part of the Medallion Acquisition, which more than offset the impact of the
termination of the Tennessee Gas Contract ($25.7 million). Net cash provided by
operating activities was $61.9 million during the 1997 nine-month period,
compared to $105.1 million for the nine months ended September 30, 1996. The
1996 period included the receipt of approximately $70 million from Tennessee Gas
on September 30, 1996 for past underpayments and interest pursuant to the
Tennessee Gas Contract. The reduction in trade accounts receivable ($58.1
million) and in accounts payable and accrued liabilities ($54.6 million) were
largely related to the discontinuance of the natural gas transportation and
marketing operations. Net income adjusted for non-cash charges was $75.8 million
for the year ended December 31, 1996, compared to $71.1 million in 1995. Net
cash provided by operating activities was $121.3 million in 1996 compared to
$30.1 million in 1995. This increase resulted primarily from the receipt of $70
million from Tennessee Gas on September 30, 1996 and, to a lesser extent, the
timing of cash receipts and payments.
Investing Activities
Capital expenditures for the nine months ended September 30, 1997 were
$171.9 million of which $91.2 million was for development drilling, including
$10.8 million for Manderson Field infrastructure, $45.6 million for the
acquisition of proved reserves under the Company's VPP program and $33.0 million
for lease acquisitions, seismic surveys and exploratory drilling.
As of March 31, 1997, the Company completed the sale of its principal
natural gas transportation asset for a net sale price of $27.9 million, the
proceeds of which were used to reduce indebtedness under its Bank Credit
Facilities, and recognized an after-tax gain of $5.9 million.
The 1997 capital budget was initially set at $160 million and was
subsequently increased to $210 million for 1997 in order to further the
Company's expansion in the Rocky Mountain region and to provide additional
24
<PAGE> 25
funding for the VPP program. The Company believes that internally generated cash
and additional borrowings under the Bank Credit Facilities are sufficient to
fund its capital program.
The Company has established a preliminary capital expenditure budget for
1998 of $183 million, consisting of $95 million for development drilling, $30
million for exploration, $45 million for VPP transactions, $10 million for
working interest acquisitions and $3 million for other expenditures. The program
is expected to be largely funded by cash flow from operations, borrowings under
the Bank Credit Facilities and, to a lesser extent, the sale of non-strategic
assets.
Capital expenditures in 1996 were $282.2 million, of which $183.1 million
was related to the Medallion Acquisition (see Note 2 to Consolidated Financial
Statements), $54.9 million was for development drilling, including $13.8 million
in the Bob West Field, $15.9 million was for the purchase of proved reserves
under the Company's VPP program and $18.2 million was for lease acquisitions,
seismic surveys and exploratory drilling. The Company utilized approximately
$160.5 million from its Bank Credit Facilities to fund the Medallion
Acquisition, while the remainder of the 1996 capital program was funded
primarily with internally generated cash, including $70.0 million received from
Tennessee Gas and $16.6 million of proceeds from the sale of certain
non-strategic oil and gas properties.
Capital expenditures in 1995 were $128.7 million, of which $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
expenditures through a combination of additional borrowings under its credit
facilities and internally generated cash.
Debt Financing
The Company has outstanding $150 million principal amount of 11% Senior
Notes due 2003 issued pursuant to an indenture governing the Senior Notes dated
January 25, 1996. The Senior Notes mature on January 15, 2003 and bear interest
at the rate of 11% per annum, payable semi-annually. The Senior Notes are
redeemable at the option of the Company, in whole or in part, commencing January
15, 2000, at pre-determined redemption prices set forth within the Senior Notes
Indenture. 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 by the Company to 50% of the Company's
cumulative net income during the period beginning October 1, 1995.
Credit Facility
In September 1996, the Company consolidated two separate credit agreements
creating one revolving credit facility (the "Credit Facility") which will mature
on September 30, 2000. The Credit Facility is secured by the Company's oil and
gas assets excluding those securing the Revolving Credit Agreement (see below).
The borrowing base under the Credit Facility is a function of the lenders'
determination of the value of the collateral, and is limited to approximately
$75 million under the terms of the Senior Notes Indenture. The Credit Facility
bears interest at a spread over the prime rate or LIBOR, determined each quarter
based upon the Company's consolidated debt-to-EBITDA ratio. As of September 30,
1997, the weighted average interest rate under the Credit Facility was 6.8% and
$74.5 million was outstanding.
Revolving Credit Agreement
Simultaneous with the consummation of the Medallion Acquisition in January
1997, the Company entered into a revolving credit agreement (the "Revolving
Credit Agreement") with a group of banks which will mature on September 30,
2000. The Company's obligations under the Revolving Credit Agreement are secured
by substantially all of the oil and gas assets acquired in the Medallion
Acquisition and a pledge of Medallion's common stock. The Revolving Credit
Agreement permits the Company to borrow at interest rates
25
<PAGE> 26
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 September 30, 1997, the weighted average interest
rate under the Revolving Credit Agreement was 7.8% and $51.7 million was
outstanding.
Equity Financing
In January 1997, the Company completed a public offering of 6,000,000
shares of Common Stock. The net proceeds to the Company of approximately $110.6
million were used to reduce outstanding indebtedness under the Bank Credit
Facilities.
26
<PAGE> 27
BUSINESS AND PROPERTIES
GENERAL
KCS is an independent oil and gas company engaged in the acquisition,
exploration, development and production of oil and gas. Through its experienced
management and technical staff, the Company has grown significantly and created
a geographically diversified reserve base by implementing a balanced program of
development drilling, reserve acquisitions and exploration drilling. The Company
concentrates its activities in areas where it has accumulated geological
knowledge and technical expertise and where it can retain significant operating
control. As a result of these efforts, KCS has compiled a multi-year inventory
of over 600 potential drilling and recompletion locations, including a
significant number of sites in the Manderson Field in the Big Horn Basin in
Wyoming where the Company believes it has the potential to significantly
increase its reserves. Additionally, the Company augments its working interest
ownership of properties with a volumetric production payment ("VPP") program to
acquire priority rights to a portion of the oil and gas from other parties'
producing properties. The Company plans to spend $183 million on capital
expenditures in 1998, of which $95 million is for development drilling, $30
million is for exploration, $45 million is for the VPP program, $10 million is
for working interest acquisitions and $3 million is for other expenditures. The
Company currently plans to drill approximately 175 development wells and to
participate in approximately 60 exploratory prospects during 1998.
The Company's operations are primarily focused in the Rocky Mountain, Gulf
Coast, and Mid-Continent/West Texas regions, and through its VPP program
primarily in the Gulf of Mexico and Michigan. As of December 31, 1996, the
Company had estimated proved reserves of 355.8 Bcfe with an estimated pre-tax
present value of future net revenues of $557.6 million. These estimated reserves
were 75% natural gas and 87% proved developed, and approximately 10% were
attributable to the Company's VPP program. The Company operates properties
comprising approximately 72% of its reserves (excluding VPP reserves) at
December 31, 1996.
A significant focus of the Company's future development is in the Manderson
Field in the Big Horn Basin in Wyoming. Since it acquired the field in November
1995, the Company has increased its acreage position from 7,500 to over 61,000
gross acres, and has undertaken an extensive exploration and development
drilling program. Through September 30, 1997, the Company had drilled 54 wells,
investing $35 million, and had spent $15.3 million to install infrastructure in
the field. Most of these wells are currently shut-in or awaiting completion,
remediation or stimulation because of delays in construction of a sour gas
treatment plant and associated gas injection system. Operations at the plant and
injection system commenced on December 3, 1997. Based on drilling and production
results and accumulation of additional seismic data, the Company believes that
there are seven productive formations located in the greater Manderson Field and
that they have significant reserve potential. The Company plans to spend $12
million in the fourth quarter of 1997 to complete a sour gas treatment plant in
the Manderson Field, bring the shut-in wells on production and drill 17
additional wells. In 1998, the Company plans to spend approximately $40 to $50
million to drill and complete as many as 70 to 100 wells in this field.
The Company has successfully increased its reserves through opportunistic
acquisitions. In May 1997, KCS completed an acquisition of properties in the
Langham Creek Field near Houston, Texas for $17 million, which enabled it to
assume operatorship and increase its average working interest in the area to
approximately 61%. In December 1996, the Company completed a major acquisition
of oil and gas properties, principally in the Mid-Continent region, for an
aggregate purchase price of $199 million. As a result of the Medallion
Acquisition, the Company more than doubled its reserve base and production rate
and significantly expanded its presence in the Mid-Continent region. In November
1995, the Company completed an acquisition in the Rocky Mountain region for $33
million, which resulted in numerous exploration and development opportunities,
including the Manderson Field.
Through its VPP program, the Company is able to add reserves at very
attractive rates of return and increase its exposure to acquisition, development
and exploration opportunities. In the three years ended
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September 30, 1997, the Company invested $124 million in 25 separate VPP
transactions, acquiring 71.8 Bcf of natural gas and 1.5 MMbbls of oil.
BUSINESS STRATEGY
KCS intends to continue to broaden its reserve base and increase production
and cash flow through a balanced program of development drilling, reserve
acquisitions and exploration drilling. The Company extensively utilizes advanced
technology, most notably 3-D seismic, computer-enhanced basin analysis, and
reservoir simulation and stimulation techniques, to better delineate and produce
reserves. The key components of the Company's business strategy include: (i)
exploiting and developing its multi-year inventory of development drilling
locations, (ii) capitalizing on the development potential of the Manderson
Field, (iii) acquiring properties with growth potential, (iv) controlling its
major properties, (v) continuing to expand its VPP program and (vi) pursuing a
balanced exploration program that includes high-potential opportunities.
KEY STRENGTHS
To implement its business strategy, the Company intends to take advantage
of several key strengths, including the following:
Proven Growth Record. The Company has achieved substantial growth in reserves,
production and EBITDA since 1992. KCS's estimated proved reserves have increased
at a compound annual growth rate of 57%, from 60.0 Bcfe as of December 31, 1992
to 355.8 Bcfe as of December 31, 1996. Over this period, production has
increased at a compound annual growth rate of 61%, from 4.4 Bcfe in 1992 to 30.1
Bcfe in 1996. Similarly, the Company's EBITDA has increased at a compound annual
growth rate of 81%, from $8.3 million for the year ended December 31, 1992 to
$88.9 million for the year ended December 31, 1996. For the nine months ended
September 30, 1997, the Company had oil and gas production of 41.2 Bcfe and
EBITDA of $72.0 million, compared to 22.2 Bcfe and $65.8 million for the same
period in 1996.
Innovative and Creative Approach to Expansion. The Company has demonstrated the
ability to identify and acquire oil and gas reserves in a disciplined, creative
manner and believes it has become one of the leaders in the acquisition of oil
and gas reserves through VPP transactions.
Large Multi-year Inventory of Drilling Opportunities. The Company has identified
more than 600 potential drilling and recompletion locations, representing a
three to four-year inventory. In addition, the Company believes that there are
significant exploratory opportunities in the acreage it has assembled, including
more than 265,000 gross undeveloped acres, in the onshore Gulf Coast regions of
Texas and Louisiana and in the Rocky Mountain and Mid-Continent regions.
Geographically Diversified Property Base. The Company operates in three distinct
regions: the Rocky Mountains, the Gulf Coast and the Mid-Continent/West Texas
regions. As a result, it benefits from diversification with respect to risks
associated with focusing on any one geographical region.
Successful Drilling Program. During the three-year period ended December 31,
1996, the Company participated in the drilling of 118 development wells and 70
exploratory wells with a 93% and 46% completion rate. During the first nine
months of 1997, the Company participated in the drilling of 71 development
wells, 86% of which were completed and 23 exploratory wells, 43% of which were
completed. Over the five-year period ended December 31, 1996, the Company
replaced approximately 114% of its production through drilling.
High Operating Margins. The Company's drilling success and emphasis on an
efficient administrative and operating structure have enabled the Company to
generate high cash margins that the Company believes compare favorably with its
peer companies.
Control of Major Properties. The Company seeks to operate and own a majority
working interest in its major properties, which gives it greater control over
the timing and nature of future development as well as over operating costs and
the marketing of production. The Company operates properties comprising
approximately 72% of its reserves (excluding VPP reserves) at December 31, 1996.
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Experienced, Motivated Management Team with a Significant Equity Stake. The
Company's senior management has extensive experience in the oil and gas industry
and is motivated to increase stockholder value. The Company's compensation
system is strongly geared to "pay for performance" with incentives directly tied
to operating and financial goals and objectives. Members of the Company's
management and directors currently own approximately 14% of the Company's common
stock, and the Company has established minimum direct ownership requirements for
all officers and directors.
The Company's executive offices are located at 379 Thornall Street, Edison,
New Jersey 08837, and its telephone number is (732) 632-1770. The Company has
regional operating offices in Worland, Wyoming; Houston, Texas; and Tulsa,
Oklahoma.
OIL AND GAS OPERATIONS AND PRINCIPAL PROPERTIES
From 1991 through 1996, the Company's most significant property was the Bob
West Field in south Texas, which accounted for approximately 34% of the
Company's gas production and 61% of oil and gas revenues during that six-year
period. 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 and terminated the
contract effective January 1, 1997.
Prior to their sale earlier in 1997, the Company also operated an
intrastate natural gas transportation business and a natural gas marketing and
services business, both of which are reflected in the Company's financial
statements as discontinued operations. The Company sold its 150-mile intrastate
pipeline system for an adjusted net sale price of $27.9 million and recorded an
after-tax gain of $5.9 million. The Company also sold its natural gas marketing
operations. The Company has retained its natural gas gathering systems in Texas,
Montana and Louisiana, which primarily serve Company-operated wells.
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<PAGE> 30
Approximately 84% of the Company's PV-10 of estimated proved reserves at
December 31, 1996 (excluding the impact of oil and gas hedging activities) and
90% of its total proved oil and gas reserves were attributable to properties in
which it has a working interest. The remaining 16% of PV-10 of proved reserves
(excluding the impact of oil and gas hedging activities) and 10% of proved
reserves were attributable to its reserves acquired through the VPP program. The
Company operates properties comprising approximately 72% of its reserves
(excluding VPP reserves) at December 31, 1996. The following table sets forth
data as of December 31, 1996 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 working interest and VPP properties. Except where
otherwise provided by contractual agreement, future cash inflows are estimated
using year-end prices. Oil and gas prices at December 31, 1996 are not
necessarily reflective of the prices the Company expects to receive in the
future. Other than gas sold under certain contractual arrangements, including
swaps, futures contracts and options, average realized gas prices of $3.54 per
Mcf and average realized oil prices of $22.45 per bbl were in effect at December
31, 1996.
<TABLE>
<CAPTION>
ESTIMATED PROVED RESERVES
GROSS ------------------------------- % OF
PRODUCING OIL NATURAL GAS TOTAL PV-10 TOTAL
LOCATION WELLS (MBBLS) (MMCF) (MMCFE) ($000'S) PV-10
-------- --------- ------- ----------- ------- -------- -----
<S> <C> <C> <C> <C> <C> <C>
Rocky Mountain Region:
Manderson Field, Wyoming............. 32 3,574 13,027 34,471 $ 41,558 8%
Ignacio Blanco Field, Colorado....... 49 -- 9,944 9,944 7,646 1
Dragon Trail Field, Colorado......... 160 1 6,921 6,927 7,378 1
Others............................... 1,335 3,295 23,037 42,807 39,916 7
----- ------ ------- ------- -------- ---
Total............................. 1,576 6,870 52,929 94,149 96,498 17
Gulf Coast Region:
Bob West Field, Texas................ 50 -- 23,025 23,025 39,945 7
Langham Creek Area, Texas............ 12 193 16,232 17,390 33,935 6
Eugene Island 251, Gulf of Mexico.... 7 67 3,004 3,406 11,088 2
Bayou Rambio Field, Louisiana........ 1 23 2,600 2,738 6,621 1
South Timbalier 148, Gulf of
Mexico............................ 10 87 1,978 2,500 6,404 1
Laurel Ridge Field, Louisiana........ 2 71 1,329 1,755 6,303 1
Glasscock Ranch Field, Texas......... 10 70 2,863 3,283 5,736 1
Others............................... 314 1,380 23,660 31,940 69,215 13
----- ------ ------- ------- -------- ---
Total............................. 406 1,891 74,691 86,037 179,247 32
Mid-Continent/West Texas Region:
Sawyer Canyon Field, Texas........... 345 65 50,845 51,235 84,427 15
Elm Grove Field, Louisiana........... 29 50 17,278 17,578 38,409 7
Aubrey/Wilsonia Fields, Louisiana.... 7 228 2,512 3,880 10,596 2
Mills Ranch Field, Texas............. 16 8 4,078 4,126 8,126 2
Others............................... 594 2,453 33,793 48,511 71,925 13
----- ------ ------- ------- -------- ---
Total............................. 991 2,804 108,506 125,330 213,483 39
Other Regions:
Newhall-Potrero Field, California.... 35 1,758 1,577 12,125 11,559 2
Mayfield/Hayes Properties,
Michigan.......................... 6 196 2,681 3,857 8,845 2
Others............................... 24 36 498 720 1,214 --
----- ------ ------- ------- -------- ---
Total............................. 65 1,990 4,756 16,702 21,618 4
Total Working Interest
Properties................. 3,038 13,555 240,882 322,218 510,846 92
Volumetric Production Payments (VPP):
Niagaran Reef Trend, Michigan........ 95 803 11,060 15,878 46,539 8
Gulf of Mexico....................... 30 160 15,648 16,608 45,607 6
Others............................... 127 113 435 1,109 3,844 3
----- ------ ------- ------- -------- ---
Total VPP Properties......... 252 1,076 27,143 33,595 95,990 17
Hedging Effects.............. -- -- -- -- (49,224) (9)
Total Company.............. 3,290 14,631 268,025 355,813 $557,612 100%
===== ====== ======= ======= ======== ===
</TABLE>
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All of the Company's exploration and development activities are located
within the United States. Set forth below are descriptions of certain of the
Company's working interest and VPP producing properties and those targeted for
significant drilling activity during the remainder of 1997 and in 1998.
ROCKY MOUNTAIN REGION
General
In the Rocky Mountain Region, the Company's operations are focused
primarily in the Big Horn, Green River and Wind River Basins. Estimated proved
reserves in the region were 94,149 MMcfe at December 31, 1996. The Company has
budgeted $70 million for development and exploratory drilling activities in the
region during 1998 and expects to have spent $73 million for such activities
during 1997, including approximately $16 million for Manderson Field
infrastructure. During the nine months ended September 30, 1997, the Company
drilled 37 gross (37 net) development wells and 6 gross (5.3 net) exploratory
wells in the Rocky Mountain Region. It expects to drill another 18 gross (18
net) development wells by the end of the year and as many as 125 gross (125 net)
development wells and 8 gross (7.3 net) exploratory wells during 1998.
Rocky Mountain Acquisition
The Company's principal Rocky Mountain properties were acquired in November
1995 when the Company acquired substantially all of the oil and gas assets of
Natural Gas Processing Company for a purchase price of approximately $33
million. Included in the acquisition were interests in 531 gross (301 net) wells
located in over 30 different fields, principally in six producing basins located
in Wyoming, Colorado and Montana. Proved reserves were estimated at the time of
the acquisition to be 66,700 MMcfe, consisting of 40,900 MMcf of natural gas and
4,300 Mbbls of oil and representing an average net acquisition cost of $0.49 per
Mcfe. Since the acquisition, the Company has undertaken an aggressive field
development and acreage acquisition program in the region that has resulted in
significant increases in acreage holdings and numerous exploration and
development drilling opportunities, most notably in the Manderson Field.
The Rocky Mountain Acquisition also included approximately 197,000 gross
(160,000 net) acres of properties, which the Company believes contain extensive
development drilling opportunities. As the result of additional property
acquisitions and leasing, the Company has increased its leasehold acreage in the
Rocky Mountain region to approximately 514,072 gross (377,957 net) developed and
undeveloped acres as of September 30, 1997. Following the Rocky Mountain
Acquisition, the Company hired highly experienced and technically competent
exploration, engineering and operational personnel with experience in the Rocky
Mountain region who were formerly employed by the seller. The Company's staff in
the region totaled 80 persons as of September 30, 1997.
Manderson Field
The Manderson Field is located in the Big Horn Basin of north central
Wyoming. The field was discovered in 1951, and 14 wells targeting the Phosphoria
Dolomite were drilled using primarily 320 and 640-acre spacing from 1951 to 1954
(with average reserve recovery for the wells of approximately 150 Mbbls of oil
per well). The Company has expanded its holdings in the field from approximately
7,500 acres obtained in the Rocky Mountain Acquisition to more than 61,000 gross
(56,000 net) acres at September 30, 1997, covering an area 20 miles long and 14
miles wide. The field has multiple reservoirs ranging from 4,500 to 8,600 feet
that are producing or potentially productive, including the Phosphoria Dolomite
and the Muddy, Octh Louie, Frontier, Lakota, Dakota and Tensleep sands. All of
these formations except the Phosphoria and Tensleep are known to produce sweet
oil and/or gas.
Through September 30, 1997, the Company had drilled a total of 54 wells
targeting the Phosphoria, Muddy, Frontier and Octh Louie formations. Based on
drilling and production results, coupled with the acquisition and interpretation
of additional seismic data, the Company believes that the seven productive
formations located in its holdings in the greater Manderson Field area have
significant potential. As a result, the Company has commenced an extensive
development drilling program in the area. At December 31, 1996,
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the Company's proved reserves included 3,574 Mbbls of oil and 13,027 MMcf of gas
from its acreage in the field, representing 10% of its proved reserves.
Through September 30, 1997, of the 54 wells the Company had drilled, 42
wells targeted the Phosphoria in the Manderson Field. As of September 30, 1997,
eight of the completed Phosphoria wells were stimulated and 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. The presence of sour gas from the Phosphoria formation and
the limitations imposed by the State of Wyoming and the federal government on
the amount of sour gas that can be flared have severely limited production from
the completed Phosphoria wells, most of which have been shut-in for extended
periods of time awaiting completion of a sour gas processing facility (amine
plant) and an associated acid gas injection system. As of September 30, 1997,
nine wells drilled to the Phosphoria had been plugged back to the shallower Octh
Louie or Muddy formations due to well bore damage caused by being shut-in, 11
Phosphoria wells were awaiting completion, 13 wells were awaiting stimulation or
remediation and one Phosphoria well had been completed to a full-stream
re-injection well. In addition, eight previously stimulated wells may require
remediation due to effects of being shut-in for extended periods. Through
September 30, 1997, the Company also drilled 12 wells targeting the Muddy,
Frontier and Octh Louie formations and had completed two wells to the Muddy, one
to the Frontier and five to the Octh Louie, with four wells still in the process
of being completed.
In February 1997, the Company began construction of an amine plant to
process the sour gas produced from the Phosphoria formation. Testing of the
plant's systems commenced in May 1997 and the Company began to test processing
sour gas in late July 1997. Although operation of the amine plant had been
severely limited due to delays in receipt of acid gas disposal equipment,
operations at the plant and the associated acid gas injection system commenced
on December 3, 1997. Once fully operational, the Company's treatment plant will
have the design capacity to treat up to 28,000 Mcf of sour gas (20% hydrogen
sulfide content level) per day to pipeline specifications. Assuming a
steady-state 2 Mcf to 1 bbl gas/oil ratio, the plant's design capacity, assuming
treatment to pipeline specifications, would permit oil production from the
Manderson Field at up to 14,000 bbls of oil per day. There can be no assurance
that the Company will be able to produce oil and gas from the Manderson Field at
rates sufficient to fully utilize such capacities. See "Risk Factors --
Operating Risks." The plant's sour gas handling capacity would be substantially
higher if the Company elected to treat its 20% sour gas to a 3% hydrogen sulfide
content level and then transport the 3% sour gas to an existing gas treatment
facility owned by a third party for processing to pipeline specifications. That
facility is currently undergoing modifications to safely handle such sour gas.
The Company has also drilled and completed an acid gas injection well, and
has received an approved permit to drill and complete a second such well, in
order to inject the acid gas by-product (approximately 98% hydrogen sulfide
content level) from its amine plant back into the ground. The Company plans to
drill the second acid gas injection well early in the first quarter of 1998. The
Company expects each of these injection wells to have sufficient capacity to
inject the plant's acid gas for a significant number of years. As of September
30, 1997, the Company operated two full-stream gas re-injection wells, had
permits pending for a third and was engineering a fourth re-injection well. Each
of the re-injection wells is expected to have the capacity to re-inject from
2,000 to 2,500 Mcf per day of 20% sour gas back into the Phosphoria. Once fully
operational, these four gas re-injection wells could permit the production of up
to 4,000 to 5,000 bbls of oil per day, assuming a steady-state 2 Mcf to 1 bbl
gas/oil ratio. The Company expects to use this sour gas re-injection capacity
primarily as a backup for its amine plant.
The Btu content of the sweet gas produced from the shallower formations in
the Manderson Field (the Muddy, Frontier, Octh Louie, Lakota and Dakota sands)
ranges from 1,050 to 1,350 MMBtu per Mcf. As a result, the rich gas must be
processed to remove the natural gas liquids prior to shipment. The Company has
several options for the removal of these liquids, including contracting for
processing services from existing nearby liquids processing facilities with
available capacity or the procurement, installation and operation by the Company
of its own liquids processing plant. The Company also has the option of treating
the sour gas produced from the Phosphoria to pipeline specification at its own
amine plant and using the nearby third-party gas treatment facility to remove
the natural gas liquids from sweet gas from the shallower formations. Based
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<PAGE> 33
on currently anticipated production levels, the Company does not expect that
production will be constrained due to the need to remove the natural gas
liquids.
At November 30, 1997, the Company had two drilling rigs and eight
completion rigs in the field and plans to have drilled at least 70 wells
targeting the Phosphoria, Muddy, Octh Louie and Frontier formations by year-end
1997, 50 of which it estimates will be on line (although less than one-third
will have been stimulated). In 1998, the Company plans to drill an additional 70
to 100 wells in the field. The exact mix of formations to be targeted will
depend on several factors, including relative oil and gas pricing, sour gas
treatment plant and gas re-injection capacity, timing of receipt of permits, the
availability of natural gas liquids processing and gas and oil transportation
capacity. During September 1997, the average production attributable to the
Company's interest in the Manderson Field was 4,252 (2,833 re-injected) Mcf of
natural gas and 352 bbls of oil per day, as most of the Company's wells remained
shut-in pending completion of the amine plant and related acid gas injection
facilities. Operations at the amine plant and the acid gas injection system
commenced on December 3, 1997.
Other Big Horn Basin Properties
In addition to its holdings in the Manderson Field, the Company also has
interests in five other producing properties with many of the same formations as
the Manderson Field in the Big Horn Basin, totaling 114,381 gross (114,024 net)
acres. The most significant of these fields is the Fourteen-Mile Field, located
in Washakie County southwest of the Manderson Field in the Big Horn Basin where
the Company currently has lease holdings on 70,000 gross (70,000 net) acres. As
of September 30, 1997, one new well had been drilled and completed to the Dakota
sand at a depth of approximately 11,000 feet and pipe had been set on a second
well which was awaiting a completion rig. The Company plans to drill at least 10
wells during 1998. Drilling results also indicate the presence of possible
hydrocarbons in the Muddy, Frontier, Cody, Mesa Verde, Phosphoria and the
Tensleep formations.
GULF COAST REGION
The Company's Gulf Coast Region operations are comprised primarily of
onshore properties in Texas and Louisiana, including the Bob West Field in south
Texas and the Langham Creek Area near Houston, Texas. The Company also owns
non-operated interests in the Gulf of Mexico. Estimated proved reserves in the
region, (exclusive of VPP interests) were 86,037 MMcfe as of December 31, 1996.
The Company has budgeted $35 million for development and exploratory drilling
activities in the region during 1998 and expects to have spent $34 million for
such activities during 1997. During the nine months ended September 30, 1997,
the Company drilled 12 gross (7.0 net) development wells and 16 gross (7.7 net)
exploratory wells in the Gulf Coast Region. It expects to drill another 4 gross
(3.65 net) development wells and 5 gross (4.25 net) exploratory wells by the end
of 1997 and expects to participate in approximately 16 gross development wells
and 17 gross exploratory wells during 1998.
Bob West Field
The Company has interests in approximately 863 gross (599 net) acres in
this field located in Zapata and Starr Counties, Texas. Historically, the Bob
West field has been the Company's most significant producing property,
accounting for approximately 35% of gas production and 61% of oil and gas
revenues during the six-year period ended December 31, 1996. 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 were
drilled directionally under the lake from common lakeshore drill sites. The
Company owns interests in two principal areas in the Bob West Field.
The Company has an effective 12.5% working interest in all production from
the Guerra "A" and Guerra "B" units containing 34 producing wells. The Company
also owns a 100% working interest in and operates 511 acres referred to as the
Falcon/Bob West Field which contains 16 producing natural gas wells. During
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<PAGE> 34
September 1997, the average combined rate of production attributable to the
Company's net revenue interest in these areas was approximately 6,815 Mcf of
natural gas per day.
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 interests in
10,187 gross (8,590 net) acres and is the operator. 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 16,500 feet.
The Company acquired additional working interests in the Langham Creek Area
in Harris County, Texas in May 1997, which added 14,000 MMcfe of proved reserves
and the potential for significant additional reserves for approximately $17
million. With this acquisition, the Company's third in a series of acquisitions
in this field, KCS assumed operatorship and now owns working interests varying
from 33% to 87% in 15 wells in this area, representing an average working
interest of approximately 61%. During September 1997, the average production
attributable to the Company's interest was approximately 11,140 Mcf of natural
gas and 100 bbls of condensate per day. The geological and geophysical evidence
indicates the potential for as many as four to eight additional development
drilling locations, with the upper-middle Wilcox sands as the primary target.
The Company plans to continue active development in the area and plans to drill
as many as five additional wells targeting these sands in 1998. In addition, the
Company is currently completing a 16,500-foot well to test the deeper Wilcox
sands on trend with North Milton Field, which field has produced approximately
200 Bcf to date, and has initiated a 3-D seismic survey to better delineate
potential drilling locations. Results of the 3-D seismic survey are expected to
be completed during the first quarter of 1998 and could change the number of
potential drilling locations.
Gulf of Mexico
The Company has working interests ranging from 1% to 14% in 13 offshore
fields (including blocks located in the Eugene Island, Ship Shoal, South
Timbalier, Vermilion, West Cameron and Galveston Island areas) which are
operated by other companies, primarily Newfield Exploration Company
("Newfield"). The Company has interests in 53 gross (5.0 net) wells with an
average working interest of approximately 9%. During September 1997, average
daily production from this area attributable to the Company's interest was
approximately 8,700 Mcf of natural gas and 364 bbls of oil.
These fields produce from various Pleistocene, Pliocene and Miocene sands
ranging from 6,000 feet to 15,000 feet in depth. The Company's participation
with Newfield in the development of these offshore reserves was initiated in
1990. The last year of active participation in new leasehold acquisitions with
Newfield was 1992, although the Company has continued to participate in the
development of the properties where it already owns leases.
During 1997, Newfield drilled one successful development well at the South
Timbalier 148 field and one unsuccessful exploration well at the South Timbalier
111 field. The Company has aggregate working interests in proved reserves of
11.8 Bcfe in the Gulf of Mexico, of which 96% are proved developed.
The Company also has acquired substantial reserves in the Gulf of Mexico
under its VPP program. See "-- Volumetric Production Payment Program."
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 #2 Claiborne Plantation was
completed in December 1995 in the shallower Miogyp (Frio) formation. A 3-D
seismic program has been shot and is currently being evaluated to identify
additional locations. During September 1997, the average production attributable
to the Company's interest was 1,340 Mcf of natural gas and 126 bbls of oil per
day.
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MID-CONTINENT/WEST TEXAS REGION
General
In the Mid-Continent/West Texas Region, the Company has active development
and exploration drilling programs in the Anadarko, Ardmore, Arklatex, Arkoma,
and Permian Basins. Estimated proved reserves in the region were 125,330 MMcfe
as of December 31, 1996. The Company has budgeted $30 million for development
and exploratory drilling activities in the region during 1998 and expects to
have spent $29 million for such activities during 1997. During the nine months
ended September 30, 1997, the Company participated in the drilling of 22 gross
(16.5 net) development wells and 1 gross (0.9 net) exploratory wells. The
Company expects to drill 12 gross (7.5 net) additional development wells and 1
gross (0.4 net) additional exploratory wells by the end of the year. The Company
plans to continue to exploit areas of the various basins that require
development wells for adequate reserve drainage and intends to drill 40
locations in these areas during 1998. Also, the Company plans to drill two
exploratory wells in 1998.
Medallion Acquisition
Effective December 31, 1996, the Company acquired all of the outstanding
stock of InterCoast Oil and Gas Company (formerly Medallion Production Company),
GED Energy Services, Inc. and InterCoast Gas Services Company, for a total price
of $199.1 million. The Medallion Acquisition more than doubled the Company's
reserve base and rate of oil and gas production and added management and
technical expertise, particularly in the new Mid-Continent region. Medallion's
principal oil and gas assets were estimated as of December 31, 1996 to be
187,458 MMcfe of proved oil and gas reserves, consisting of 140,320 MMcf of
natural gas (78% of total proved reserves) and 7,856 Mbbls of oil and
condensate, representing an average net acquisition cost of $0.98 per Mcfe.
These reserves were located primarily in west Texas, the Texas panhandle,
northwest Oklahoma and north Louisiana.
Sawyer Canyon Field
The Company's holdings in the Sawyer Canyon Field, located in Sutton
County, Texas, represented 14% of the Company's proved reserves as of December
31, 1996. As of September 30, 1997, the Company owned interests in 345 gross
(309 net) wells, of which it operates 332 gross (309 net) wells. The Company's
average working interest in this field was 90%, and its leasehold position at
September 30, 1997 consisted of approximately 34,887 gross (34,053 net) acres.
During September 1997, the average combined rate of production attributable to
the Company's interest was approximately 14,600 Mcf of natural gas and 4 bbls of
condensate per day.
The main producing formation in the Sawyer Canyon Field is the Canyon
sandstone at a depth of approximately 5,500 feet. 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.
The Company's 51,235 MMcfe of proved reserves attributable to the Sawyer
Canyon Field at December 31, 1996 are 97% proved developed. The Company has
continued to optimize the field's production and cash flow performance by
maintaining close well, compressor and operating expense surveillance. The
Company currently plans to drill up to seven additional locations, one of which
will be drilled in the fourth quarter of 1997, 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 drilled and is producing
one of these additional locations in 1997 and a second location is scheduled to
be drilled in the fourth quarter of 1997. In addition to exploiting these Canyon
sand development opportunities, the Company intends to continue 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.
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Elm Grove Field
The Company's reserve holdings of 17,578 MMcfe in the Elm Grove Field,
Bossier Parish, Louisiana represent approximately 5% of the Company's total
proved reserves as of December 31, 1996 and are 97% 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. As of September 30, 1997,
the Company owned an interest in 29 gross (25 net) wells, of which 27 gross (25
net) were operated by the Company. The Company's operated leasehold position
consisted of approximately 5,760 gross (5,545 net) acres. Average daily
production from the Elm Grove Field, net to its interest, was approximately
4,400 Mcf of natural gas and 12 bbls of oil during September 1997.
The Company has drilled and completed one Cotton Valley well this year and
plans to re-fracture one of the thirteen wells drilled by the Company since it
first acquired its interest in the field in September 1994. Also, the Company
has identified three 2,500-foot Tuscaloosa development locations which it plans
to drill in the fourth quarter of this year. The Company has identified several
behind pipe zones and plans to drill three to five additional Cotton Valley and
Tuscaloosa wells in 1998.
OTHER REGIONS
Newhall-Potrero Field
The Company's Newhall-Potrero Field is located in Los Angeles County,
California, outside the city of Valencia. At December 31, 1996, net proved
reserves were 12,125 MMcfe, all of which were proved developed. The Company is
the operator and owns a 100% working interest in 35 active wells. Average daily
production from the area, net to its interest, was approximately 836 Mcf of
natural gas and 417 bbls of oil during September 1997. The Company has been able
to maintain the oil production at or above the same daily rate as the field was
producing when it was acquired by Medallion in 1993 by converting certain wells
from gas lift to pumping unit operations and reworking other wells, and was able
to reduce the per barrel lifting cost. The Company believes that there are other
production enhancement opportunities in the Newhall-Potrero Field through the
recompletion of wells or the drilling of high angle laterals to undrained
portions of the oil reservoirs.
Niagaran Reef Trend (Michigan)
The Company owns non-operated working interests averaging 19% in 23 active
producing wells located in the northern Niagaran Reef trend of Michigan. At
December 31, 1996, net proved reserves attributed to these interests were 3,179
MMcf and 231 Mbbls with a total PV-10 of $10.1 million. Of this PV-10 amount,
59% was attributable to three wells in the Mayfield "28" reef and 29% was
attributable to five wells in the Hayes "11" reef. During September 1997, daily
production net to the Company's interests from all the Michigan wells averaged
approximately 95 bbls of oil and 750 Mcf of gas. The Niagaran Reef reservoirs
are tall carbonate mounds (limestones & dolomites) varying from several hundred
to more than 600 feet in height and are typically found at depths of 4,000 to
6,500 feet.
The Company acquired its ownership in the Michigan properties in December
1995 in conjunction with a VPP transaction with a subsidiary of Hawkins Oil and
Gas, Inc. ("Hawkins"), which currently operates the majority of the wells in
which the Company has an interest. The Company intends to become the operator of
these properties on or about January 1, 1998. During 1997, the Company began
expanding its involvement in the area by acquiring a 30% working interest in a
28 square mile 3-D seismic exploration project designed to identify and drill
for Niagaran Reefs in a previously underexplored area of the northern reef
trend. This project area offsets a portion of the existing productive reef trend
that statistically contains more than 1.5 reefs per square mile, where per well
cumulative productions have exceeded 450 Mbbls of oil. This project is currently
in the final stages of seismic processing, and, following interpretation, the
project's operator expects to finalize leasing and embark on a multi-well
drilling program that could result in the drilling of 30 or more test wells over
the next several years.
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<PAGE> 37
VOLUMETRIC PRODUCTION PAYMENT PROGRAM
General
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
currently not the operator of any of the properties underlying its volumetric
production payments, and it does not bear any development or lease operating
expenses. The Company intends to become the operator of the properties
underlying the Michigan VPP transaction on or about January 1, 1998. 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.
In the three years ended September 30, 1997, the Company had invested $124
million in 25 separate transactions under the VPP program, and had acquired
proved reserves of 80,865 MMcfe, consisting of 71,805 MMcf of natural gas and
1,510 Mbbls of oil. This represents an average net acquisition cost of $1.54 per
Mcfe, without the burden of development and lease operating expenses. Through
September 30, 1997, the Company had recovered approximately $75 million from the
sale of oil and gas received under its VPP program. Scheduled for delivery under
the VPP program after September 30, 1997 are 42,328 MMcf of gas and 1,008 Mbbls
of oil. The Company's unrecovered cost under its VPP program, including future
commitments of $10.6 million, is $1.17 per Mcfe. The VPP program accounted for
33,595 MMcfe (10%) of the Company's total proved oil and gas reserves as of
December 31, 1996. The properties underlying the VPP program are principally
located in two major regions, the Gulf of Mexico and the Niagaran Reef trend in
Michigan.
During the nine months ended September 30, 1997, the Company invested $45.5
million in 10 separate VPP transactions and acquired 22,805 MMcf of gas and 110
Mbbls of oil. The newly acquired reserves are primarily located in 11 blocks in
the offshore Gulf of Mexico.
The following table shows, as of September 30, 1997, the oil and gas
deliveries to the Company scheduled to be made pursuant to its VPP program over
the period from October 1, 1997 through December 31, 2006. Total future net cash
flows to the Company from the volumetric production payment deliveries scheduled
below are estimated to be $126.6 million, based on spot market prices in effect
at September 30, 1997 ($2.57 per MMBtu (Henry Hub) and $17.63 per bbl (Koch WTI
EDQ posting), before adjustments for appropriate basis differentials and Btu
content).
<TABLE>
<CAPTION>
NATURAL GAS OIL TOTAL % OF
PERIOD FROM TO (MMCFE) (MBBLS) (MMCFE) TOTAL
----------- -- ----------- ------- ------- ----------
<S> <C> <C> <C> <C> <C>
October 1, 1997 December 31, 1997......... 4,389 87 4,911 10%
January 1, 1998 December 31, 1998......... 22,145 386 24,461 51
January 1, 1999 December 31, 1999......... 10,087 173 11,125 23
January 1, 2000 December 31, 2000......... 1,803 109 2,457 5
January 1, 2001 December 31, 2001......... 1,369 75 1,819 4
January 1, 2002 December 31, 2006......... 2,535 178 3,603 7
------ ----- ------ ---
42,328 1,008 48,376 100%
====== ===== ====== ===
</TABLE>
37
<PAGE> 38
Niagaran Reef Trend (Michigan) VPP Properties
The Company's northern and southern Niagaran Reef trend properties, located
in Michigan, were acquired in December 1995. The VPP program reserves are being
produced largely from a group of 25 wells located in 12 fields, currently
operated by Hawkins. The Niagaran Reef reservoirs are typically found at depths
between 4,000 and 6,500 feet. The Company intends to become the operator of the
properties underlying the Michigan VPP transaction on or about January 1, 1998.
Of the remaining 9,187 MMcf and 645 Mbbls to be delivered under the volumetric
production payment, the Company is scheduled to receive 603 MMcf and 47 Mbbls
during the last three months of 1997, 2,195 MMcf and 162 Mbbls in 1998, with the
balance to be delivered between 1999 and 2006.
Gulf of Mexico VPP Properties
Hall-Houston Oil Company Properties. The Company has acquired interests in
12 blocks off the coast of Texas and Louisiana through volumetric production
payment contracts with Hall-Houston Oil Company ("HHOC"), which is the operator
of all of the blocks. The blocks contain 20 wells drilled during 1994, 1995,
1996 and the first nine months of 1997 in the shallow waters of the Gulf of
Mexico, producing at depths ranging from 4,500 to 10,000 feet. Pursuant to the
HHOC volumetric production payments, the Company received deliveries totaling
9,640 MMcf during 1996 and 4,400 MMcf during the nine months ended September 30,
1997 and is scheduled to receive deliveries totaling 2,173 MMcf during the
balance of 1997, 7,164 MMcf in 1998, and 4,922 MMcf in 1999.
ATP Oil & Gas Properties. The Company has acquired interests in 8 blocks
off the coast of Louisiana, one block off the coast of Texas and one onshore
property in Texas through volumetric production payment contracts with ATP Oil &
Gas Co. of Houston, Texas ("ATP"), which is the operator of all of the blocks.
The blocks contain 10 wells drilled during 1996 and the first nine months of
1997 that are at depths ranging from 3,000 to 13,500 feet in the shallow waters
of the Gulf of Mexico. Pursuant to the ATP volumetric production payments, the
Company received deliveries totaling 427 MMcfe during 1996 and 928 MMcfe during
the nine months ended September 30, 1997 and is scheduled to receive deliveries
totaling 1,765 MMcfe during the balance of 1997, 13,904 MMcfe in 1998, and 3,791
MMcfe in 1999. The terms of the VPP with ATP specify that the Company receives a
fixed percentage of the production attributable to ATP's working interest until
payout of the Company's investment, then a reduced percentage until the
Company's return on its initial investment reaches a defined level, at which
time the Company would be entitled to a continuing overriding royalty interest
for the remaining life of the reserves. As a result, the exact volumes to be
delivered to the Company will vary depending on a number of factors including
the timing of production and the actual realized oil and gas prices.
Other VPP Properties
The Company is also scheduled to receive deliveries totaling 88 MMcfe
during the remainder of 1997 and 352 MMcfe from 1998 to 1999 from several
smaller volumetric production payments.
EXPLORATION PROGRAM
During the three-year period ended December 31, 1996, the Company
participated in the drilling of 70 exploratory wells with a 46% success rate.
Discoveries included wells in the Langham Creek Area, the Laurel Ridge Field,
the Tensas Parish Area and the Manderson Field. During the first nine months of
1997, the Company participated in the drilling of 23 exploratory wells and
completed 10 wells. Of the 1997 exploration budget of $25 million, $16.8 million
was spent during the nine months ended September 30, 1997. The Company plans to
participate in approximately 60 exploratory prospects in 1998, committing
approximately 40% of its $30 million 1998 exploration budget to higher risk,
higher potential projects.
The Company's policy is to commit no more than 25% of its operating cash
flow to exploration activities and generally to have no more than a $750,000 dry
hole cost exposure for any exploratory well. The Company has established an
initial budget of $30 million for exploration in 1998 and intends to participate
in drilling a wide variety of prospects, including both moderate-risk and
high-risk, high-potential prospects in order to
38
<PAGE> 39
maintain a balanced drilling program with the potential for significant reserve
additions. During 1998, the Company plans 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. Major ongoing exploration projects include the Franklin
Deep, Laurel Ridge, Bayou Carlin and Bayou Segnett prospects in south Louisiana;
the Langham Creek Deep and Buna Gap prospects in southeast Texas; the Buck
prospect in northeast Texas; the Wilde Horse Butte in Wyoming, the Breeze
Anticline prospect in Colorado; the Montana Tyler prospect in Montana and the
Spearfish and Lodgepole prospects in North Dakota.
OIL AND GAS RESERVES
All information in this Prospectus relating to estimates of the Company's
proved reserves is derived from reports prepared for the Company by Ryder Scott
Company, H.J. Gruy and Associates, Inc., R.A. Lenser and Associates, Inc. and
Netherland, Sewell and Associates, Inc., 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 VPP agreements (which
amounts are substantially less than the net working interest production
reflected in the independent reserve engineers' reports).
The following table sets forth as of December 31, 1996, the historical
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 plus (ii) the reserve amounts contracted for pursuant to the VPP
agreements.
<TABLE>
<CAPTION>
DECEMBER 31,
1996
------------
<S> <C>
PROVED RESERVES:
Oil (Mbbls)................................................. 14,631
Natural gas (MMcf).......................................... 268,025
Total (MMcfe).......................................... 355,813
Future net revenues ($000).................................. $849,265
Present value of future net revenues before income taxes
($000).................................................... $557,612
PROVED DEVELOPED RESERVES:
Oil (Mbbls)................................................. 12,133
Natural gas (MMcf).......................................... 236,454
Total (MMcfe).......................................... 309,252
Future net revenues ($000).................................. $750,990
Present value of future net revenues before income taxes
($000).................................................... $494,240
</TABLE>
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. As of December 31,
1996, spot market gas prices of $3.90 per Mcf (Henry Hub) and $23.38 per bbl
(Koch WTI EDQ posting) were in effect. These prices were substantially higher
than spot market prices as of September 30, 1997, which were $2.57 per Mcf
(Henry Hub) and $17.63 per bbl (Koch WTI EDQ posting). 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 "Risk Factors -- Volatile Nature of Oil
and Gas Markets; Fluctuations in Prices" and "-- Uncertainty of Estimates of Oil
and Gas Reserves and Future Net Cash Flows."
39
<PAGE> 40
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. See
"Risk Factors -- Volatile Nature of Oil and Gas Markets; Fluctuations in Prices"
and "-- Uncertainty of Estimates of Oil and Gas Reserves and Future Net Cash
Flows."
ACREAGE
The following table sets forth certain information with respect to
developed and undeveloped leased acreage of the Company as of September 30,
1997. 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>
Wyoming........................................ 257,425 207,259 50,548 50,548
Texas.......................................... 122,714 71,157 42,330 22,407
Montana........................................ 85,433 46,938 29,047 22,222
Louisiana...................................... 114,393 27,911 39,857 32,576
Oklahoma....................................... 49,217 19,302 12,006 7,559
Colorado....................................... 27,254 12,946 7,020 5,270
Other.......................................... 64,569 11,639 84,533 26,988
------- ------- ------- -------
Total................................ 721,005 397,152 265,341 167,570
======= ======= ======= =======
</TABLE>
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 obtain 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.
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.
40
<PAGE> 41
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.
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, 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 under short-term
contracts (one year or less) providing for variable or market sensitive prices.
The Company sells its oil production in each of its producing regions pursuant
to contracts based on postings by major purchasers.
The price of 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 applicable period. 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 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 two separate natural gas price swaps in place as a result
of the Medallion Acquisition. For the calendar years 1996, 1997 and 1998, these
transactions cover 11.7 million MMBtu, 8.1 million MMBtu and 4.8 million MMBtu
of natural gas, respectively, and result in annual weighted average prices per
MMBtu of $2.072, $2.020 and $1.983, respectively.
SIGNIFICANT CUSTOMER
One customer, Tennessee Gas, accounted for approximately 82%, 72% and 40%
of the oil and gas revenue for the years ended December 31, 1994, 1995, and
1996, respectively. No other single customer accounted for more than 10% of the
Company's consolidated revenue during these periods or in the nine months ended
September 30, 1997. Effective January 1, 1997, the Company's contract with
Tennessee Gas was terminated.
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. 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.
41
<PAGE> 42
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 a 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.
State Regulation of Energy. The Company's production investments are
subject to regulation at the state level. Such regulation varies from state to
state but generally includes requiring permits for the drilling of wells,
maintaining bonding requirements in order to drill or operate wells, and
regulating the location of wells, the method of drilling and casing wells, the
surface use and restoration of properties upon which wells are drilled, the
plugging and abandoning of wells, and the disposal of fluids used in connection
with operations. The Company's operations are also subject to various state
conservation laws and regulations. These include regulation of the size of
drilling and spacing units or proration units, the density of wells which may be
drilled, and the unitization or pooling of oil and gas properties. In addition,
state conservation laws establish maximum rates of production from oil and gas
wells, restrict the venting or flaring of gas and impose certain requirements
regarding the ratability of production. These regulatory burdens may affect
profitability, and the Company is unable to predict the future cost or impact of
complying with such regulations.
Federal 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.
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
pipelines' sales of natural gas. Order No. 636 and certain related proceedings
have been the subject of a number of judicial appeals and orders on remand by
the FERC. Although Order No. 636 has largely been upheld on appeal, several
appeals remain pending in related restructuring proceedings. The Company cannot
predict when these remaining appeals will be completed or their impact on the
Company. FERC continues to address Order 636-related issues (including capacity
brokering, alternative and negotiated ratemaking and transportation policy
matters) in a number of pending proceedings. In May 1997, FERC held a public
conference and inquiry to receive comments on the FERC's future regulatory
policies and priorities in the post-Order 636 environment. It is not possible
for the Company to predict what effect, if any, the ultimate outcome of the
FERC's various initiatives will have on the Company's operations. However, the
court's decision is still subject to further action.
Although Order No. 636 does not directly regulate the Company's production
activities, Order No. 636 was issued to foster increased competition within all
phases of the natural gas industry. It is unclear what future impact, if any,
increased competition within the natural gas industry under Order No. 636 and
related orders will have on the Company's activities. Although Order No. 636
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 several important transportation-related policy
statements and proposed rule changes, including a statement of policy and a
request for comments concerning alternatives to its traditional cost-of-service
ratemaking methodology to establish the rates that pipelines may charge for
their services. A number of pipelines have obtained FERC authorization to charge
negotiated rates as one such alternative. In February 1997, the FERC announced a
broad inquiry into issues facing the natural gas industry to assist the FERC in
establishing regulatory goals and priorities in the post-Order No. 636
environment. While these
42
<PAGE> 43
changes would affect the Company only indirectly, they are intended to further
enhance competition in the natural gas markets.
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. For example, the Texas Railroad
Commission has recently changed its regulations governing transportation and
gathering services provided by intrastate pipelines and gatherers to prohibit
undue discrimination in favor of affiliates. Other state regulation of gathering
facilities generally includes various safety, environmental, and in some
circumstances, nondiscriminatory take requirements, but does not generally
entail rate regulation. 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 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 Company believes that its natural gas gathering facilities meet the
traditional tests that the FERC has used to establish a pipeline's status as a
gatherer not subject to FERC jurisdiction. However, whether on state or federal
land or in offshore waters subject to the Outer Continental Shelf Land Act
("OCSLA") natural gas gathering may receive greater federal regulatory scrutiny
in the post-Order No. 636 environment. The effects, if any, of these 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. 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"). The MMS
has issued a notice of proposed rulemaking in which it proposes to amend its
regulations governing the calculation of royalties and the valuation of crude
oil produced from federal leases. This proposed rule would modify the valuation
procedures for both arm's length and non-arm's length crude oil transactions to
decrease reliance on oil posted prices and assign a value to crude oil that
better reflects its market value, establish a new MMS form for collecting
differential data, and
43
<PAGE> 44
amend the valuation procedure for the sale of federal royalty oil. The Company
cannot predict what action the MMS will take on this matter, nor can it predict
how the Company will be affected by any change to this regulation.
In April 1997, after two years of study, the MMS withdrew proposed changes
to the way it values natural gas for royalty payments. These proposed changes
would have established an alternative market-based method to calculate royalties
on certain natural gas sold to affiliates or pursuant to non-arm's length sales
contracts. Informal discussions among the MMS and industry officials are
continuing, although it is uncertain whether, and what changes may be proposed
regarding gas royalty valuation. In addition, MMS has recently announced its
intention to issue a proposed rule that would require all but the smallest
producers to be capable of reporting production information electronically by
the end of 1998.
MMS leases contain relatively standardized terms requiring compliance with
detailed MMS regulations and, in the case of offshore leases, orders pursuant to
OCSLA (which are subject to change by the MMS). For such offshore operations,
lessees must obtain MMS approval for exploration, development, and production
plans prior to the commencement of such operations. The MMS has promulgated
regulations requiring offshore production facilities located on the OCS to meet
stringent engineering and construction specification. The MMS also has proposed
additional safety-related regulations concerning the design and operating
procedures for OCS production platforms and pipelines, but these proposed
regulations were withdrawn pending further discussions among interested federal
agencies. With respect to conservation, the MMS has regulations restricting the
flaring or venting of natural gas and has amended such regulations to prohibit
the flaring of liquid hydrocarbons and oil without prior authorization. The MMS
has also promulgated other regulations governing the plugging and abandonment of
wells located offshore and the removal of all production facilities. To cover
the various obligations of lessees on the OCS, the MMS generally requires that
lessees post substantial bonds or other acceptable assurances that such
obligations will be met. The cost of such bonds or other surety can be
substantial and there is no assurance that any particular lease operator can
obtain bonds or other surety in all cases. Under certain circumstances, the MMS
may require operations on federal leases to be suspended or terminated. Any such
suspension or termination could adversely affect the Company's interests.
Additional proposals and proceedings that might affect the oil and gas
industry are pending before Congress, the FERC, the MMS, state commissions 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 various agencies 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.
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
44
<PAGE> 45
lying within wetlands or other protected areas and impose substantial
liabilities for pollution or releases of hazardous substances resulting from
drilling and production operations. Failure to comply with these laws and
regulations may also result in civil and criminal fines and penalties. 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.
For example, soil contamination and possible groundwater contamination
exist on properties in the Newhall-Potrero Field in California acquired by the
Company in the Medallion Acquisition. The surface landowner has notified the
Company and some prior operators of the Newhall-Potrero Field properties that
the landowner expects them to remediate the contamination. Oryx Energy Company
("Oryx"), the successor to one of the prior operators in the field, has in the
past performed some remediation of contamination in the field to the
satisfaction of the surface landowner. However, the additional remediation
demanded by the surface landowner is estimated to cost between $4 million and
$47 million, with the most probable costs ranging between $5 million and $14
million. The Company acquired the Newhall-Potrero Field properties when it
acquired InterCoast Oil and Gas Company, InterCoast Gas Services Company, and
GED Energy Services, Inc. (collectively "InterCoast"). InterCoast had been
indemnified for 100% of the cost of remediation and restoration activities at
the properties by the company from which it acquired the properties, and the
Company believes that it is a valid successor to InterCoast's indemnity. In
addition, the Company received an indemnity from the owners of InterCoast
(InterCoast Energy and affiliated entities) for 90% of any costs the Company is
required to incur in relation to remediation and restoration activities at the
Newhall-Potrero Field. This indemnity was guaranteed by MidAmerican Capital
Company and it covers environmental claims that are filed against the Company
before January 2, 1999. The Company and Oryx have been negotiating with the
surface landowner and have reached a tentative agreement regarding the scope of
the additional remediation to be performed in the field. The tentative agreement
requires Oryx to pay for substantially all of the additional remediation and
requires only minimal expenditures by the Company. Given the indemnities
available to the Company with respect to this matter and the tentative agreement
obligating Oryx to perform substantially all of the additional remediation and
restoration activities on the properties, management does not expect the Company
to incur any material environmental costs in connection with historical
contamination in the Newhall-Potrero Field.
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.
The Company's operations may be subject to the Clean Air Act ("CAA") and
comparable state and local requirements. Amendments to the CAA were adopted in
1990 and contain provisions that may result in the gradual imposition of certain
pollution control requirements with respect to air emissions from the operations
of the Company. The EPA and states have been developing regulations to implement
these requirements. The Company may be required to incur certain capital
expenditures in the next several years for air pollution control equipment in
connection with maintaining or obtaining permits and approvals addressing
45
<PAGE> 46
other air emission-related issues. The Company does not believe, however, that
its operations will be materially adversely affected by any such requirements.
In addition, the U.S. Oil Pollution Act ("OPA") requires owners and
operators of facilities 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. Such financial assurances may
be increased by as much as $150 million if a formal assessment indicates such an
increase is warranted.
Operations of the Company are also subject to the federal Clean Water Act
("CWA") and analogous state laws. In accordance with the CWA, the state of
Louisiana has issued regulations prohibiting discharges of produced water in
state coastal waters effective July 1, 1997. The Company may be required to
incur certain capital expenditures in the next several years in order to comply
with the prohibition against the discharge of produced waters into Louisiana
coastal waters or increase operating expenses in connection with offshore
operations in Louisiana coastal waters. Pursuant to other requirements of the
CWA, the EPA has adopted regulations concerning discharges of storm water
runoff. This program requires covered facilities to obtain individual permits,
participate in a group permit or seek coverage under an EPA general permit.
While certain of its properties may require permits for discharges of storm
water runoff, the Company believes that it will be able to obtain, or be
included under, such permits, where necessary, and make minor modifications to
existing facilities and operations that would not have a material effect on the
Company.
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.
LEGAL PROCEEDINGS
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 two subsequently filed suits in
Zapata County, Texas. On May 30, 1997, one of the Zapata County suits was
dismissed in connection with a partial settlement with certain of the royalty
owners that is discussed below. On October 22, 1997, the other Zapata County
suit was dismissed by the court on its own motion, inasmuch as the suit had been
abated since September 15, 1995 in favor of the earlier-filed suit in Dallas
County.
The Dallas County action was instituted to obtain a declaratory judgment
that 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 is erroneous. The Company paid royalties for this natural
gas produced from the Guerra "A", Guerra "B" and Jesus Yzaguirre Units based
upon the spot market price. Because its leases have market-value royalty
provisions, the Company believes it is in full compliance under the leases with
its royalty holders. Its position has been confirmed in the Dallas County suit,
where the trial judge has granted the Company and its co-plaintiffs' motions for
summary judgment on this issue. In addition, the Dallas County trial judge has
granted summary judgment against the royalty owners with respect to their
various counterclaims concerning the Company's Jesus Yzaguirre Unit and the
jointly-owned Guerra "A" and Guerra "B" Units. The royalty owners had also
counterclaimed against the Company with respect to the Jesus Yzaguirre Unit,
alleging (i) that the largest lease contained therein had terminated in December
1975 and (ii) 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. On May 30, 1997, the Company and these royalty owners
settled the issue of lease termination, and on June 2, 1997, the trial judge
signed an order of dismissal with prejudice as to that issue. On the issue of
the effect of the 1992 division orders, the parties filed renewed motions for
summary judgment.
46
<PAGE> 47
On August 12, 1997, the trial judge signed an order granting the Company's
motion and denying the royalty owners' motion.
At a hearing on October 29, 1997, the trial judge entered a final judgment
in favor of the Company based upon the prior separate summary judgments in favor
of the Company's position on the issues and counterclaims involved with the
Jesus Yzaguirre Unit lawsuit.
The royalty owners in the Guerra "A" and Guerra "B" Units and in the Jesus
Yzaguirre Unit have appealed the trial court's decision to the Fifth District
Court of Appeals in Dallas, Texas. While the Company believes its positions are
meritorious and that it should prevail, there can be no assurance as to the
ultimate outcome of these matters.
The Company is also party 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 does
not expect such matters to have a material adverse effect, either singly or in
the aggregate, on the financial position or results of operations of the
Company.
47
<PAGE> 48
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....... 49 President, Chief Executive Officer and Director
Henry A. Jurand.......... 48 Senior Vice President, Chief Financial Officer and
Secretary
C.R. Devine.............. 51 Vice President, Oil and Gas Operations; President,
KCS Resources, Inc.
Frederick Dwyer.......... 37 Vice President and Controller
Kathryn M. Kinnamon...... 33 Vice President, Treasurer and Asst. Secretary
Harry Lee Stout.......... 49 President, KCS Energy Services, Inc.
Gene C. Daley............ 47 President, KCS Medallion Resources, Inc.
J. Chris Jacobsen........ 42 Senior Vice President, KCS Medallion Resources, Inc.
Dan A. Magee............. 55 Vice President, KCS Resources, Inc. d/b/a KCS
Mountain Resources, Inc.
G. Stanton Geary......... 63 Director
Stewart B. Kean.......... 63 Director and Chairman of the Board
James E. Murphy, Jr. .... 41 Director
Robert G. Raynolds....... 45 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 its inception in 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.
Henry A. Jurand was appointed Senior Vice President in March 1997. He has
served as Chief Financial Officer since January 1996, Vice President of the
Company from September 1990 to March 1997, 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 of Constellation
Investments, Inc. On September 15, 1997, Mr. Jurand announced his retirement
from the Company, effective December 31, 1997, to pursue a career in academia.
The Company has initiated a search for his successor.
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.
Frederick Dwyer was appointed Vice President and Controller of the Company
in March 1997. He served as Assistant Vice President and Controller from May
1996 to March 1997. He joined the Company upon its formation in 1988, holding
various management and supervisory positions. He is a certified public
accountant and began his career with Peat, Marwick, Mitchell & Co.
Kathryn M. Kinnamon was appointed Vice President and Treasurer of the
Company in March 1997. She served as Treasurer since January 1996, as Assistant
Vice President from May 1996 to March 1997 and as Assistant Treasurer from May
1991 to December 1995. She joined the Company upon its formation in 1988,
holding various management and supervisory positions.
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<PAGE> 49
Harry Lee Stout has served as President of KCS Energy Marketing, Inc., the
Company's subsidiary, since joining the Company in August 1991. In September
1996, he was named President of KCS Energy Services, Inc., the subsidiary of the
Company engaged in the volumetric production payment program. 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.
Gene C. Daley was named President of KCS Medallion Resources, Inc. in
December 1997. He previously served as Senior Vice President, Exploration and
Development of KCS Medallion Resources, Inc. (formerly InterCoast Oil and Gas
Company) since 1991. Prior to joining InterCoast he served as President of
Carter Resources, Inc. from its inception in 1974 until its acquisition by
InterCoast in 1991. From 1972 to 1974 he was an offshore exploration geologist
for Texaco, Inc.
J. Chris Jacobsen has served as Senior Vice President, Exploration,
Development and Reserves of KCS Medallion Resources, Inc. since 1994 and also
has responsibility as director of reservoir engineering for all of the Company.
From 1982 to 1994 he was Senior Vice President of Netherland, Sewell &
Associates. From 1977 to 1982 he was employed by Exxon Company U.S.A. holding
various engineering and supervisory positions.
Dan A. Magee has served as Vice President of KCS Resources, Inc., d/b/a KCS
Mountain Resources, Inc. since May 1996. Prior to May 1996 he was a consultant
to KCS Resources, Inc. in connection with acquisition activities beginning May
1995. From 1992 to 1995 he was a consulting engineer and Manager of Acquisitions
at Hanson Production Company. From 1974 to 1992 he was the Production, Drilling
and Operations Manager for Edwin L. Cox and Cox Oil & Gas, Inc.
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 President of the Liberty Hall Foundation. 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.
49
<PAGE> 50
SECURITY OWNERSHIP BY CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
As of September 30, 1997, there were 29,394,894 shares of the Company's
Common Stock outstanding. These shares were held by 1,149 holders of record. The
following table sets forth information as to the number and percentage of shares
owned beneficially as of September 30, 1997 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.
<TABLE>
<CAPTION>
SHARES OWNED PERCENT
BENEFICIALLY(1) OF CLASS
--------------- --------
<S> <C> <C>
James W. Christmas...................................... 1,007,023(2)(3) 3.4%
C. R. Devine............................................ 116,869(2) *
Henry A. Jurand......................................... 37,615(2) *
Frederick Dwyer......................................... 7,794(2) *
Kathryn M. Kinnamon..................................... 3,712(2) *
Harry Lee Stout......................................... 61,724(2) *
G. Stanton Geary........................................ 12,654(2) *
Stewart B. Kean......................................... 2,761,829(2)(4) 9.4%
James E. Murphy, Jr..................................... 30,884(2) *
Robert G. Raynolds...................................... 7,160(2) *
Joel D. Siegel.......................................... 191,388(2)(5) *
Christopher A. Viggiano................................. 58,388(2) *
Executive officers and directors as a group (12
persons).............................................. 4,297,040 14.3%
Metropolitan Life Insurance Company(6).................. 3,361,000 11.4%
One Madison Avenue
New York, New York 10010
Warburg, Pincus Counsellors, Inc........................ 1,918,100 6.5%
466 Lexington Avenue
New York, New York 10017
</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 November 1, 1997 of 600,000, 27,500,
17,500, 30,000 and 200 for Messrs. Christmas, Devine, Jurand, Stout, and
Dwyer, respectively; 200 for Ms. Kinnamon; 8,000 each for Messrs. Geary,
S.B. Kean, Murphy, Siegel and Viggiano and 4,000 for Mr. Raynolds and (ii)
are allocated to the beneficial owner's account under 401(k) plans.
(3) Includes 36,000 shares held in trusts established for the benefit of Mr.
Christmas' children, the beneficial ownership of which is disclaimed by Mr.
Christmas.
(4) Includes 1,025,648 shares held under certain family trusts as to which Mr.
Kean shares voting and investment power.
(5) Includes 16,000 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 3,337,600 shares (11.4%) owned by an affiliate of Metropolitan Life
Insurance Company, State Street Research and Management Company, One
Financial Center, 30th Floor, Boston, Massachu-
setts 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 and chief executive officer must become the owner of
Common Stock with a market value of four times his annual base salary. For
50
<PAGE> 51
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 EXISTING INDEBTEDNESS
The Company and certain of its subsidiaries borrow funds for working
capital and property acquisitions from several banks under two Bank Credit
Facilities. The following summaries of the Credit Facility and Revolving Credit
Agreement do not purport to be complete and are subject to, and qualified in
their entirety by reference to the applicable credit agreements. The lenders
under the Bank Credit Facilities have provided waivers or consents as the
Company has determined to be necessary to permit the issuance of the Notes.
CREDIT FACILITY
Certain subsidiaries of the Company are borrowers under the Credit Facility
with a group of banks which provides for revolving credit and letters of credit
for up to $150 million in the aggregate (the "Commitment Amount").
The Credit Facility matures on September 30, 2000. The actual amount
available for borrowing under the Credit Facility is determined by a fluctuating
borrowing base (the "Borrowing Base") that is a function of a periodic valuation
by the lenders of the borrowers' oil and gas reserves. The amount of credit
available to the borrowers under the Credit Facility is the lesser of the
Borrowing Base or the Commitment Amount. The Borrowing Base is currently $75
million. Although the oil and gas reserves pledged as collateral under the
Credit Facility may support borrowings greater than $75 million, the Senior
Notes Indenture effectively limits the borrowing base under this facility to the
greater of $75 million or 15% of adjusted consolidated net tangible assets (as
defined in the Senior Notes Indenture).
Repayment of principal under the Credit Facility is required to the extent
the aggregate amount of borrowing and letters of credit outstanding exceeds the
Borrowing Base as calculated from time to time.
The obligations of the borrowers under the Credit Facility are secured by
first liens on (a) those oil and gas properties owned by the borrowers which are
included in the calculation of the Borrowing Base and on the hydrocarbon
production from those oil and gas properties and (b) the other assets of the
borrowers, including accounts receivable, inventory and machinery and equipment
related to the oil and gas properties.
Commitment fees of 3/8 of 1% per annum are paid on the difference between
the amount actually borrowed and the lesser of the Commitment Amount and the
Borrowing Base. The borrowers have the option of borrowing at the following
rates of interest per annum (subject to immaterial adjustments): (i) the prime
rate, plus a spread ranging from 0% to 0.50%, (ii) the London Interbank Offered
Rate ("LIBOR") plus a spread ranging from 0.625% to 1.50%. The spread under each
alternative rate is determined quarterly based upon the consolidated
debt-to-EBITDA ratio of the Company and its subsidiaries. At December 26, 1997,
there was $74.5 million outstanding under the Credit Facility.
To the extent that the lenders have a commitment to make advances under the
Credit Facility, or outstanding indebtedness exists under the Credit Facility,
the borrowers may not incur or have outstanding any other indebtedness, except
as expressly permitted by the credit agreement. The credit agreement permits the
borrowers to incur indebtedness to the Company and other subsidiaries of the
Company under certain circumstances, to incur obligations under oil and gas
leases entered into in the ordinary course of business, to continue to pay in
accordance with their terms certain specified indebtedness, to incur
indebtedness of up to $1 million which otherwise would be prohibited under the
Credit Facility and to incur purchase money indebtedness and indebtedness under
equipment leases, the aggregate outstanding principal balance of which does not
exceed $1 million at any time. Other covenants and provisions in the Credit
Facility prohibit or restrict, among other things, the borrowers' ability to (a)
encumber its assets; (b) enter into negative pledge agreements with respect to
its assets; (c) merge or consolidate; (d) dissolve or liquidate; (e) amend its
corporate charter or corporate structure, activities or nature in any manner
which could have a material adverse effect; (f) become a general partner, joint
venturer or venturer with respect to any transaction except
51
<PAGE> 52
joint operating agreements, exploration agreements and similar arrangements,
containing customary terms and entered into in the ordinary course of business;
(g) declare or pay certain dividends or make certain payments on account of
capital stock or redeem, retire or otherwise acquire for value any of its
capital stock at any time an Event of Default exists; (h) make any distribution
of assets; (i) repay any indebtedness to the Company or any affiliate of the
Company at any time an Event of Default exists, except for certain inter-company
indebtedness specified in the Credit Facility; (j) lend money or acquire any
securities, other than a fractional undivided interest in oil and gas
properties, obligations of the United States of America, certificates of deposit
and other institutional debt obligations, certain specified loans and advances,
advances in accordance with the Company's cash management program and repurchase
agreements (within specified limits); (k) enter into transactions with an
affiliate on terms less favorable to the Company than would be available in a
comparable arms-length transaction; (l) sell or otherwise dispose of assets
except in the ordinary course of business; (m) enter into sale-leaseback
transactions; and (n) prepay any debt.
Events of default under the Credit Facility include, among other things,
(a) a failure of the borrowers to pay principal, interest or any other payment
due under the Credit Facility; (b) certain defaults in respect of other
indebtedness; (c) a material breach of any representation or warranty; (d) a
breach of certain agreements and covenants, including all negative covenants,
contained in the Credit Facility; (e) a breach of any other covenants in the
Credit Facility which has not been cured within 30 days; (f) a failure by the
Company to perform, observe or comply with the negative covenants and financial
covenants contained in the Company's guaranty described below, (g) certain acts
of bankruptcy, insolvency or dissolution and (h) the rendering of a final
judgment in excess of $2.5 million that is not discharged or stayed within a
specified period.
The Company has guaranteed the obligations of its subsidiary borrowers
under the Credit Facility pursuant to a Guaranty Agreement. This guaranty
prohibits or restricts, among other things, the Company's ability to (a) merge
or consolidate, (b) dissolve or liquidate, (c) amend its corporate charter or
corporate structure, activities or nature in any manner which could have a
material adverse effect and (d) pay dividends in excess of 50% of Consolidated
Net Income (as defined in the guaranty) for the period from September 30, 1993
to the time such dividend is paid. Additionally, the guaranty requires that (a)
the Company and its subsidiaries on a consolidated basis maintain a minimum
Consolidated Tangible Net Worth (as defined in the guaranty), and (b) the
Company and its subsidiaries on a consolidated basis maintain a minimum EBITDA
to interest expense ratio. The Company is currently in compliance with all such
covenants.
REVOLVING CREDIT AGREEMENT
In January 1997, simultaneous with the consummation of the Medallion
Acquisition, the Company and certain of its subsidiaries entered into the
Revolving Credit Agreement with a group of banks. The Revolving Credit Agreement
will mature September 30, 2000. The amount of credit available at any time under
the Revolving Credit Agreement is the lesser of (i) the maximum credit
commitment of $150 million (the "Revolving Commitment Amount") and (ii) the
aggregate amount of indebtedness (the "Revolving Borrowing Base") which can be
supported by the lenders' evaluation of the oil and gas reserves attributable to
the oil and gas properties pledged as collateral to the lenders. In addition to
the oil and gas properties, the stock of the subsidiaries acquired in the
Medallion Acquisition were also pledged as collateral. The Revolving Borrowing
Base is currently set at $90 million.
Commitment fees of 3/8 of 1% per annum are paid on the difference between
the amounts actually borrowed and the lesser of the Revolving Commitment Amount
and the Revolving Borrowing Base. The borrowers have the option of borrowing at
the following rates of interest per annum (subject to immaterial adjustments):
(i) the prime rate, plus a spread ranging from 0% to 0.625%, (ii) the LIBOR plus
a spread ranging from 0.75% to 1.625%. The spread under each alternative rate is
determined quarterly based upon the consolidated debt-to-EBITDA ratio of the
Company and its subsidiaries. At December 26, 1997, there was $66.1 million
outstanding under the Revolving Credit Agreement, not including $0.5 million
reserved for existing letters of credit.
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The Revolving Credit Agreement includes customary affirmative and negative
covenants which, among other things, require the meeting of certain financial
tests and limit the borrowers with respect to incurrence of additional
indebtedness, liens, mergers, consolidation or changes in its corporate
structure, dividends, loans, transactions with affiliates, disposition of assets
and sale and leaseback agreements similar to those described above with respect
to the Credit Facility. The borrowers are currently in compliance with all such
covenants.
Events of default under the Revolving Credit Agreement include, among other
things, (a) a failure of the borrowers to pay principal, interest or any other
payment due under the Credit Facility; (b) certain defaults in respect of other
indebtedness; (c) a material breach of any representation or warranty; (d) a
breach of certain agreements and covenants, including all negative covenants,
contained in the Credit Facility; (e) a breach of any other covenants in the
Credit Facility which has not been cured within 30 days; (f) a failure by the
Company to perform, observe or comply with the negative covenants and financial
covenants contained in the Company's guaranty described below; (g) certain acts
of bankruptcy, insolvency or dissolution and (h) the rendering of a final
judgment in excess of $2.5 million that is not discharged or stayed within a
specified period.
11% SENIOR NOTES DUE 2003
In January 1996, the Company privately offered and sold $150,000,000
aggregate principal amount at maturity of 11% Senior Notes due 2003, Series A,
pursuant to the Senior Notes Indenture between the Company and State Street Bank
and Trust Company (as successor trustee to Fleet National Bank of Connecticut).
Subsequent to the private offering and sale of the original senior notes, the
Company filed a Registration Statement with the Commission and exchanged such
original senior notes for 11% Senior Notes due 2003, Series B ("Senior Notes"),
of the Company with terms substantially identical to such notes, except that the
new securities did not contain transfer restrictions on the resale of such
securities. Interest on the Senior Notes is payable on January 15 and July 15 of
each year. Such payment commenced on July 15, 1996. The Senior Notes are
redeemable at the option of the Company, in whole or in part, at anytime on or
after January 15, 2000, at the redemption prices set forth in the Senior Notes
Indenture, together with accrued interest to the date of redemption.
In the event the Company consummates a Public Equity Offering (as defined
in the Senior Notes Indenture) on or prior to January 15, 1999, the Company may
at its option use all or a portion of the proceeds from such offering to redeem
up to $35 million principal amount of the Senior Notes at a redemption price
equal to 111% of the aggregate principal amount thereof, together with accrued
interest to the date of redemption, provided that at least $115 million in
aggregate principal amount of Senior Notes remains outstanding immediately after
such redemption.
The Senior Notes are unconditionally guaranteed on a senior unsecured basis
by each of the Company's current and certain of the Company's future
subsidiaries, and such subsidiary guarantees rank pari passu in right of payment
with all existing and future senior indebtedness of the subsidiary guarantors
and senior to all subordinated indebtedness of the subsidiary guarantors.
The Senior Notes are senior unsecured obligations of the Company ranking
pari passu in right of payment with all existing and future senior indebtedness
of the Company and senior to all subordinated indebtedness of the Company.
The Senior Notes and the subsidiary guarantees, however, are effectively
subordinated to secured indebtedness of the Company and the subsidiary
guarantors, respectively, with respect to the assets securing such indebtedness,
including indebtedness of certain subsidiary guarantors under the Bank Credit
Facilities which is secured by liens on substantially all of the assets of such
subsidiary guarantors and guaranteed by the Company.
Upon the occurrence of a Change of Control (as defined in the Senior Notes
Indenture), each holder of Senior Notes will have the right to require the
Company to purchase all or a portion of such holder's Senior Notes at a price
equal to 101% of the aggregate principal amount thereof, together with accrued
interest to the date of purchase.
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<PAGE> 54
The Senior Notes Indenture contains certain covenants, including covenants
which limit: (i) indebtedness; (ii) restricted payments; (iii) issuances and
sales of capital stock of restricted subsidiaries; (iv) sale/leaseback
transactions; (v) transactions with affiliates; (vi) liens; (vii) asset sales;
(viii) dividends and other payment restrictions affecting restricted
subsidiaries; (ix) conduct of business; and (x) mergers, consolidations and
sales of assets. In addition, the Senior Notes Indenture includes various
circumstances that will constitute, upon occurrence and subject in certain cases
to notice and grace periods, an event of default thereunder.
DESCRIPTION OF THE NOTES
The Notes will be issued under an indenture (the "Indenture") to be entered
into among the Company, as issuer, KCS Resources, Inc., KCS Michigan Resources,
Inc., KCS Energy Marketing, Inc., KCS Medallion Resources, Inc., KCS Energy
Services, Inc., Medallion California Properties Co., Medallion Gas Services,
Inc., National Enerdrill Corporation and Proliq, Inc., as Subsidiary Guarantors,
and State Street Bank and Trust Company, as trustee (the "Trustee"). The
Indenture will be subject to and governed by the Trust Indenture Act of 1939, as
amended (the "Trust Indenture Act"). The following summary of certain provisions
of the Indenture does not purport to be complete and is subject to, and is
qualified in its entirety by reference to, all of the provisions of the
Indenture, including the definitions of certain terms contained therein and
those terms that are made a part of the Indenture by reference to the Trust
Indenture Act. A form of the Indenture is filed as an exhibit to the
Registration Statement of which this Prospectus is a part. Capitalized terms not
otherwise defined below or elsewhere in this Prospectus have the meanings given
to them in the Indenture. The definitions of certain capitalized terms used in
the following summary are set forth below under "-- Certain Definitions."
The Indenture will provide for the issuance of up to $125 million of Notes
in connection with the Offering (the "Offered Notes"). The Indenture will also
provide the Company the flexibility of issuing up to $25 million of additional
Notes in the future; however, any issuance of such additional Notes would be
subject to the covenant described under "-- Certain Covenants -- Limitation on
Indebtedness and Disqualified Capital Stock." The Offered Notes and any such
additional Notes are collectively referred to as the "Notes" in this
"Description of the Notes."
As used in this "Description of the Notes," the term "Company" refers only
to KCS Energy, Inc.
GENERAL
The Offered Notes will be unsecured senior subordinated obligations of the
Company limited to $125 million aggregate principal amount. The Notes will be
issued only in registered form, without coupons, in denominations of $1,000 and
integral multiples thereof. Principal of, premium, if any, and interest on the
Notes will be payable at the office or agency of the Company in the City of New
York maintained for such purpose, and the Notes may be surrendered for transfer
or exchange at the corporate trust office of the Trustee. In addition, in the
event the Notes do not remain in book-entry form, interest may be paid, at the
option of the Company, by check mailed to the Holders of the Notes at their
respective addresses as shown on the Note Register, subject to the right of any
Holder of Notes in the principal amount of $500,000 or more to request payment
by wire transfer. No service charge will be made for any transfer, exchange or
redemption of the Notes, but the Company or the Trustee may require payment of a
sum sufficient to cover any tax or other governmental charge that may be payable
in connection therewith.
The obligations of the Company under the Notes will be guaranteed on a
senior subordinated basis by the Subsidiary Guarantors. See "-- Subsidiary
Guarantees of Notes."
MATURITY, INTEREST AND PRINCIPAL PAYMENTS
The Notes will mature on January 15, 2008. Interest on the Notes will
accrue from January 21, 1998 at the rate of 8 7/8% per annum and will be payable
semiannually in cash on January 15 and July 15 of each year, commencing July 15,
1998, to the Persons in whose name the Notes are registered in the Note Register
at the close of business on January 1 or July 1 next preceding such interest
payment date. Interest will be computed on the basis of a 360-day year comprised
of twelve 30-day months.
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REDEMPTION
Optional Redemption. The Notes will be redeemable at the option of the
Company, in whole or in part, at any time on or after January 15, 2003, upon not
less than 30 or more than 60 days' notice, at the redemption prices (expressed
as percentages of principal amount) set forth below, plus accrued and unpaid
interest, if any, to the date of redemption (subject to the right of Holders of
record on the relevant record date to receive interest due on an interest
payment date that is on or prior to the date of redemption), if redeemed during
the 12-month period beginning on January 15 of the years indicated below:
<TABLE>
<CAPTION>
REDEMPTION
YEAR PRICE
- ---- ----------
<S> <C> <C>
2003............................................... 104.438%
2004............................................... 102.958%
2005............................................... 101.479%
2006 and thereafter................................ 100.00%
</TABLE>
In the event that less than all of the Notes are to be redeemed, the
particular Notes (or any portion thereof that is an integral multiple of $1,000)
to be redeemed shall be selected not less than 30 nor more than 60 days prior to
the date of redemption by the Trustee, from the outstanding Notes not previously
called for redemption, pro rata, by lot or by any other method the Trustee shall
deem fair and appropriate.
Notwithstanding the foregoing, at any time on or prior to January 15, 2001,
up to 33 1/3% of the aggregate principal amount of Notes originally issued will
be redeemable, at the option of the Company, from the Net Cash Proceeds of a
Public Equity Offering, at a redemption price equal to 108.875% of the principal
amount thereof, together with accrued and unpaid interest to the date of
redemption, provided that at least 66 2/3% of the aggregate principal amount of
Notes originally issued remains outstanding immediately after such redemption
and that such redemption occurs within 60 days following the closing of such
Public Equity Offering.
Offers to Purchase. As described below, (a) upon the occurrence of a Change
of Control, the Company will be obligated to make an offer to purchase all
outstanding Notes at a purchase price equal to 101% of the principal amount
thereof, together with accrued and unpaid interest, if any, to the date of
purchase and (b) upon certain sales or other dispositions of assets, the Company
may be obligated to make offers to purchase Notes with a portion of the Net
Available Proceeds of such sales or other dispositions at a purchase price equal
to 100% of the principal amount thereof, together with accrued and unpaid
interest, if any, to the date of purchase. See " -- Certain Covenants -- Change
of Control" and " -- Limitation on Asset Sales."
SUBORDINATION
The payment of principal of, premium, if any, and interest, on the Notes
and any other payment obligations of the Company in respect of the Notes
(including any obligation to repurchase the Notes) will be subordinated in
certain circumstances in right of payment, as set forth in the Indenture, to the
prior payment in full of the Senior Notes and all other Senior Indebtedness of
the Company, whether outstanding on the date of the Indenture or thereafter
incurred. The Subsidiary Guarantees will also be subordinated (to the same
extent and in the same manner as the Notes are subordinated to Senior
Indebtedness of the Company) to the prior payment in full of all Senior
Indebtedness of the Subsidiary Guarantors. See "-- Subsidiary Guarantees of
Notes." As of September 30, 1997, Senior Indebtedness of the Company and the
Subsidiary Guarantors on a consolidated basis was approximately $276.2 million.
The Notes and the Subsidiary Guarantees will rank prior in right of payment only
to other Indebtedness of the Company or the Subsidiary Guarantors, as the case
may be, which is expressly subordinated in right of payment to the Notes or the
Subsidiary Guarantees, as the case may be. There is currently no Indebtedness of
the Company or any Subsidiary Guarantor which would constitute such Subordinated
Indebtedness. Subject to certain limitations, the Company and its Subsidiaries
may incur additional Indebtedness (including Senior Indebtedness) in the future.
See " -- Certain Covenants -- Limitation on Indebtedness and Disqualified
Capital Stock."
Upon any distribution to creditors of the Company in a liquidation or
dissolution of the Company or in a bankruptcy, reorganization, insolvency,
receivership or similar proceeding relating to the Company or its
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property, an assignment for the benefit of creditors or any marshaling of the
Company's assets and liabilities, the holders of Senior Indebtedness will be
entitled to receive payment in full of all amounts due in respect of such Senior
Indebtedness (including interest after the commencement of any such proceeding
at the rate specified in the applicable Senior Indebtedness) before the Holders
of Notes will be entitled to receive any payment with respect to the Notes, and
until all amounts due with respect to Senior Indebtedness are paid in full, any
distribution to which the Holders of Notes would be entitled shall be made to
the holders of Senior Indebtedness (except that Holders of Notes may receive
securities that are subordinated at least to the same extent as the Notes to
Senior Indebtedness of the Company and any securities issued in exchange for
Senior Indebtedness of the Company and Holders of Notes may also receive
payments made from the trust described under "-- Legal Defeasance or Covenant
Defeasance of Indenture").
The Company also may not make any payment upon or in respect of the Notes
(except in such subordinated securities or from the trust described under
"-- Legal Defeasance or Covenant Defeasance of Indenture") if (i) a default in
the payment of the principal of, premium, if any, or interest on Designated
Senior Indebtedness of the Company occurs and is continuing beyond any
applicable period of grace or (ii) any other default occurs and is continuing
with respect to Designated Senior Indebtedness of the Company that permits, or
with the giving of notice or passage of time or both (unless cured or waived)
will permit, holders of the Designated Senior Indebtedness as to which such
default relates to accelerate its maturity and the Trustee receives a notice of
such default (a "Payment Blockage Notice") from the Company or the holders of
any Designated Senior Indebtedness of the Company. Payments on the Notes shall
be resumed (a) in the case of a payment default, upon the earliest of the date
on which such default is cured or waived or holders of such Designated Senior
Indebtedness agree to such resumption or such Designated Senior Indebtedness has
been repaid in full and (b) in case of a nonpayment default, the earliest of the
date on which such nonpayment default is cured or waived or holders of such
Designated Senior Indebtedness agree to such resumption or such Designated
Senior Indebtedness has been repaid in full or 179 days after the date on which
the applicable Payment Blockage Notice is received, unless the maturity of any
Designated Senior Indebtedness of the Company has been accelerated (and such
acceleration has not been rescinded or annulled). No new period of payment
blockage in the case of a nonpayment default may be commenced unless and until
(i) 360 days have elapsed since the date of commencement of the immediately
prior Payment Blockage Notice period and (ii) all scheduled payments of
principal, premium, if any, and interest on the Notes that have come due have
been paid in full in cash. No nonpayment default that existed or was continuing
on the date of delivery of any Payment Blockage Notice to the Trustee shall be,
or be made, the basis for a subsequent Payment Blockage Notice, unless such
default has been cured or waived for a period of not less than 90 consecutive
days commencing after the date of delivery of such Payment Blockage Notice. In
no event will a payment blockage period in the case of a nonpayment default
extend beyond 179 days from the date of the receipt by the Trustee of the notice
and there must be a 181 consecutive day period in any 360-day period during
which no such payment blockage period is in effect. In the event that,
notwithstanding the foregoing, the Company makes any payment or distribution to
the Trustee or the Holder of any Note prohibited by the subordination provisions
of the Indenture, then such payment or distribution will be required to be paid
over and delivered forthwith to the holders (or their representative) of
Designated Senior Indebtedness of the Company.
If the Company fails to make any payment on the Notes when due or within
any applicable grace period, whether or not on account of the payment blockage
provisions described above, such failure would constitute an Event of Default
under the Indenture and would enable the Holders of the Notes to accelerate the
maturity thereof. See "-- Events of Default."
The Indenture will further require that the Company promptly notify holders
of Senior Indebtedness if payment of the Notes is accelerated because of an
Event of Default.
As a result of the subordination provisions described above, in the event
of a liquidation or insolvency of the Company, Holders of Notes may recover less
ratably than creditors of the Company who are holders of Senior Indebtedness,
and funds which would be otherwise payable to the Holders of the Notes will be
paid to the holders of the Senior Indebtedness of the Company to the extent
necessary to pay such Senior Indebtedness in full, and the Company may be unable
to meet its obligations in full with respect to the Notes.
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<PAGE> 57
SUBSIDIARY GUARANTEES OF NOTES
Each Subsidiary Guarantor will unconditionally guarantee, jointly and
severally, to each Holder and the Trustee, the full and prompt performance of
the Company's obligations under the Indenture and the Notes, including the
payment of principal of, premium, if any, and interest on the Notes pursuant to
its Subsidiary Guarantee. The initial Subsidiary Guarantors are currently all of
the Company's subsidiaries. In addition to the initial Subsidiary Guarantors,
the Company is obligated under the Indenture to cause each Restricted Subsidiary
that becomes, or comes into existence as, a Restricted Subsidiary after the date
of the Indenture and has assets, businesses, divisions, real property or
equipment with a fair market value (as determined in good faith by the Board of
Directors of the Company) in excess of $1 million to execute and deliver a
supplement to the Indenture pursuant to which such Restricted Subsidiary will
guarantee the payment of the Notes on the same terms and conditions as the
Subsidiary Guarantees by the initial Subsidiary Guarantors.
The Subsidiary Guarantee of each Subsidiary Guarantor will be unsecured and
subordinated (to the same extent and in the same manner as the Notes are
subordinated to Senior Indebtedness of the Company) to the prior payment in full
of all Senior Indebtedness of such Subsidiary Guarantor.
The obligations of each Subsidiary Guarantor will be limited to the maximum
amount as will, after giving effect to all other contingent and fixed
liabilities of such Subsidiary Guarantor and after giving effect to any
collections from or payments made by or on behalf of any other Subsidiary
Guarantor in respect of the obligations of such other Subsidiary Guarantor under
its Subsidiary Guarantee or pursuant to its contribution obligations under the
Indenture, result in the obligations of such Subsidiary Guarantor under its
Subsidiary Guarantee not constituting a fraudulent conveyance or fraudulent
transfer under federal or state law. Each Subsidiary Guarantor that makes a
payment or distribution under a Subsidiary Guarantee shall be entitled to a
contribution from each other Subsidiary Guarantor in a pro rata amount based on
the Adjusted Net Assets of each Subsidiary Guarantor.
Each Subsidiary Guarantor may consolidate with or merge into or sell or
otherwise dispose of all or substantially all of its properties and assets to
the Company or another Subsidiary Guarantor without limitation, except to the
extent any such transaction is subject to the "Merger, Consolidation and Sale of
Assets" covenant of the Indenture. Each Subsidiary Guarantor may consolidate
with or merge into or sell all or substantially all of its properties and assets
to a Person other than the Company or another Subsidiary Guarantor (whether or
not affiliated with the Subsidiary Guarantor), provided that (a) if the
surviving Person is not the Subsidiary Guarantor, the surviving Person agrees to
assume such Subsidiary Guarantor's Subsidiary Guarantee and all its obligations
pursuant to the Indenture (except to the extent the following paragraph would
result in the release of such Subsidiary Guarantee) and (b) such transaction
does not (i) violate any of the covenants described below under "-- Certain
Covenants" or (ii) result in a Default or Event of Default immediately
thereafter that is continuing.
Upon the sale or other disposition (by merger or otherwise) of a Subsidiary
Guarantor (or all or substantially all of its properties and assets) to a Person
other than the Company or another Subsidiary Guarantor and pursuant to a
transaction that is otherwise in compliance with the Indenture (including as
described in the foregoing paragraph), such Subsidiary Guarantor shall be deemed
released from its Subsidiary Guarantee and the related obligations set forth in
the Indenture; provided, however, that any such release shall occur only to the
extent that all obligations of such Subsidiary Guarantor under all of its
guarantees of, and under all of its pledges of assets or other security
interests which secure, other Indebtedness of the Company or any Restricted
Subsidiary shall also be released upon such sale or other disposition. Each
Subsidiary Guarantor that is designated as an Unrestricted Subsidiary in
accordance with the Indenture shall be released from its Subsidiary Guarantee
and related obligations set forth in the Indenture for so long as it remains an
Unrestricted Subsidiary.
Separate financial statements of the Subsidiary Guarantors have not been
provided because the Subsidiary Guarantors are jointly and severally liable for
the obligations of the Company under the Notes and the aggregate assets,
earnings and equity of the Subsidiary Guarantors are substantially equivalent to
the consolidated assets, earnings and equity of the Company.
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CERTAIN COVENANTS
The Indenture will contain, among others, the covenants described below.
Limitation on Indebtedness and Disqualified Capital Stock. The Company will
not, and will not permit any of its Restricted Subsidiaries to, create, incur,
issue, assume, guarantee or in any manner become directly or indirectly liable
for the payment of (collectively, "incur") any Indebtedness (including any
Acquired Indebtedness but excluding any Permitted Indebtedness) or any
Disqualified Capital Stock, unless, on a pro forma basis after giving effect to
such incurrence and the application of the proceeds therefrom, the Consolidated
EBITDA Coverage Ratio for the four full quarters immediately preceding such
event, taken as one period, would have been equal to or greater than 2.5 to 1.0.
Limitation on Restricted Payments. (a) The Company will not, and will not
permit any Restricted Subsidiary to, directly or indirectly:
(i) declare or pay any dividend on, or make any other distribution to
holders of, any shares of Capital Stock of the Company (other than dividends or
distributions payable solely in shares of Qualified Capital Stock of the Company
or in options, warrants or other rights to purchase Qualified Capital Stock of
the Company);
(ii) purchase, redeem or otherwise acquire or retire for value any Capital
Stock of the Company or any Affiliate thereof (other than any Restricted
Subsidiary) or any options, warrants or other rights to acquire such Capital
Stock;
(iii) make any principal payment on or repurchase, redeem, defease or
otherwise acquire or retire for value, prior to any scheduled principal payment,
scheduled sinking fund payment or maturity, any Subordinated Indebtedness,
except in any case out of the net cash proceeds of Permitted Refinancing
Indebtedness; or
(iv) make any Restricted Investment;
(such payments or other actions described in clauses (i) through (iv) being
collectively referred to as "Restricted Payments"), unless at the time of and
after giving effect to the proposed Restricted Payment (the amount of any such
Restricted Payment, if other than cash, shall be the amount determined by the
Board of Directors of the Company, whose determination shall be conclusive and
evidenced by a Board Resolution),
(1) no Default or Event of Default shall have occurred and be continuing,
(2) the Company could incur $1.00 of additional Indebtedness (other than
Permitted Indebtedness) in accordance with the "-- Limitation on Indebtedness
and Disqualified Capital Stock" covenant, and
(3) the aggregate amount of all Restricted Payments declared or made after
the date of the Indenture shall not exceed the sum (without duplication) of the
following:
(A) 50% of the Consolidated Net Income of the Company accrued on a
cumulative basis during the period beginning on October 1, 1997 and ending
on the last day of the Company's last fiscal quarter ending prior to the
date of such proposed Restricted Payment (or, if such Consolidated Net
Income is a loss, minus 100% of such loss),
(B) the aggregate Net Cash Proceeds received after the date of the
Indenture by the Company from the issuance or sale (other than to any of
its Restricted Subsidiaries) of shares of Qualified Capital Stock of the
Company or any options, warrants or rights to purchase such shares of
Qualified Capital Stock of the Company,
(C) the aggregate Net Cash Proceeds received after the date of the
Indenture by the Company (other than from any of its Restricted
Subsidiaries) upon the exercise of any options, warrants or rights to
purchase shares of Qualified Capital Stock of the Company,
(D) the aggregate Net Cash Proceeds received after the date of the
Indenture by the Company from the issuance or sale (other than to any of
its Restricted Subsidiaries) of Indebtedness or shares of Disqualified
Capital Stock that have been converted into or exchanged for Qualified
Capital Stock of the
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Company, together with the aggregate cash received by the Company at the
time of such conversion or exchange,
(E) to the extent not otherwise included in Consolidated Net Income,
the net reduction in Investments in Unrestricted Subsidiaries resulting
from dividends, repayments of loans or advances, or other transfers of
assets, in each case to the Company or a Restricted Subsidiary after the
date of the Indenture from any Unrestricted Subsidiary or from the
redesignation of an Unrestricted Subsidiary as a Restricted Subsidiary
(valued in each case as provided in the definition of Investment), not to
exceed in the case of any Unrestricted Subsidiary the total amount of
Investments (other than Permitted Investments) in such Unrestricted
Subsidiary made by the Company and its Restricted Subsidiaries in such
Unrestricted Subsidiary after the date of the Indenture, and
(F) $25 million.
(b) Notwithstanding paragraph (a) above, the Company and its Restricted
Subsidiaries may take the following actions so long as (in the case of clauses
(ii), (iii) and (iv) below) no Default or Event of Default shall have occurred
and be continuing:
(i) the payment of any dividend on any Capital Stock of the Company within
60 days after the date of declaration thereof, if at such declaration date such
declaration complied with the provisions of paragraph (a) above (and such
payment shall be deemed to have been paid on such date of declaration for
purposes of any calculation required by the provisions of paragraph (a) above);
(ii) the repurchase, redemption or other acquisition or retirement of any
shares of any class of Capital Stock of the Company or any Restricted
Subsidiary, in exchange for, or out of the aggregate Net Cash Proceeds from, a
substantially concurrent issuance and sale (other than to a Restricted
Subsidiary) of shares of Qualified Capital Stock of the Company;
(iii) the purchase, redemption, repayment, defeasance or other acquisition
or retirement for value of any Subordinated Indebtedness in exchange for, or out
of the aggregate Net Cash Proceeds from, a substantially concurrent issuance and
sale (other than to a Restricted Subsidiary) of shares of Qualified Capital
Stock of the Company; and
(iv) repurchases, acquisitions or retirements of shares of Qualified
Capital Stock of the Company deemed to occur upon the exercise of stock options
or similar rights issued under employee benefit plans of the Company if such
shares represent all or a portion of the exercise price or are surrendered in
connection with satisfying any federal income tax obligation.
The actions described in clauses (i), (ii), (iii) and (iv) of this paragraph (b)
shall be Restricted Payments that shall be permitted to be made in accordance
with this paragraph (b) but shall reduce the amount that would otherwise be
available for Restricted Payments under clause (3) of paragraph (a), provided
that any dividend paid pursuant to clause (i) of this paragraph (b) shall reduce
the amount that would otherwise be available under clause (3) of paragraph (a)
when declared, but not also when subsequently paid pursuant to such clause (i).
Limitation on Issuances and Sales of Capital Stock of Restricted
Subsidiaries. The Company (i) will not permit any Restricted Subsidiary to issue
or sell any Capital Stock to any Person other than the Company or another
Restricted Subsidiary (unless, after giving effect thereto, such Restricted
Subsidiary no longer qualifies as such) and (ii) will not permit any Person
other than the Company or a Restricted Subsidiary to own any Capital Stock of
any Restricted Subsidiary.
Limitation on Transactions with Affiliates. The Company will not, and will
not permit any Restricted Subsidiary to, directly or indirectly, enter into or
suffer to exist any transaction or series of related transactions (including,
without limitation, the sale, purchase, exchange or lease of assets or property
or the rendering of any services) with, or for the benefit of, any Affiliate of
the Company (other than the Company or a Restricted Subsidiary), unless (i) such
transaction or series of transactions is on terms that are no less favorable to
the Company or such Restricted Subsidiary, as the case may be, than those that
would be
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available in a comparable arm's length transaction with unrelated third parties,
(ii) with respect to any one transaction or series of transactions involving
aggregate payments in excess of $1 million, the Company delivers an Officers'
Certificate to the Trustee certifying that such transaction or series of
transactions complies with clause (i) above and that such transaction or series
of transactions has been approved by a majority of the Disinterested Directors
of the Company, and (iii) with respect to any one transaction or series of
transactions involving aggregate payments in excess of $10 million, the
Officers' Certificate referred to in clause (ii) above also certifies that the
Company has obtained a written opinion from an independent nationally recognized
investment banking firm or appraisal firm specializing or having a speciality in
the type and subject matter of the transaction or series of transactions at
issue, which opinion shall be to the effect set forth in clause (i) above or
shall state that such transaction or series of transactions is fair from a
financial point of view to the Company or such Restricted Subsidiary; provided,
however, that the foregoing restriction shall not apply to (w) loans or advances
to officers, directors and employees of the Company or any Restricted Subsidiary
made in the ordinary course of business and consistent with past practices of
the Company and its Restricted Subsidiaries in an aggregate amount not to exceed
$1 million outstanding at any one time, (x) indemnities of officers, directors,
employees and other agents of the Company or any Restricted Subsidiary permitted
by corporate charter or other organizational document, bylaw or statutory
provisions, (y) the payment of reasonable and customary regular fees to
directors of the Company or any of its Restricted Subsidiaries who are not
employees of the Company or any Affiliate and (z) the Company's employee
compensation and other benefit arrangements.
Limitation on Other Senior Subordinated Indebtedness. The Company will not
incur any Indebtedness that is expressly subordinate or junior in right of
payment to any Senior Indebtedness of the Company and senior in right of payment
to the Notes, and no Subsidiary Guarantor will incur any Indebtedness that is
expressly subordinate or junior in right of payment to any Senior Indebtedness
of such Subsidiary Guarantor and senior in right of payment to its Subsidiary
Guarantee; provided, however, that the foregoing limitations will not apply to
distinctions between categories of Indebtedness that exist by reason of any
Liens arising or created in respect of some but not all such Indebtedness.
Limitation on Liens. The Company will not, and will not permit any
Restricted Subsidiary to, directly or indirectly, create, incur, assume, affirm
or suffer to exist or become effective any Lien of any kind, except for
Permitted Liens, upon any of their respective property or assets, whether now
owned or acquired after the date of the Indenture, or any income, profits or
proceeds therefrom, to secure (a) any Indebtedness of the Company or such
Restricted Subsidiary (if it is not also a Subsidiary Guarantor), unless prior
to, or contemporaneously therewith, the Notes are equally and ratably secured,
or (b) any Indebtedness of any Subsidiary Guarantor, unless prior to, or
contemporaneously therewith, the Subsidiary Guarantees are equally and ratably
secured; provided, however, that if such Indebtedness is expressly subordinated
in right of payment to the Notes or the Subsidiary Guarantees, the Lien securing
such Indebtedness will be subordinated and junior to the Lien securing the Notes
or the Subsidiary Guarantees, as the case may be, with the same relative
priority as such Indebtedness has with respect to the Notes or the Subsidiary
Guarantees. The foregoing covenant will not apply to any Lien securing Acquired
Indebtedness, provided that any such Lien extends only to the property or assets
that were subject to such Lien prior to the related acquisition by the Company
or such Restricted Subsidiary and was not created, incurred or assumed in
contemplation of such transaction. The incurrence of additional secured
Indebtedness by the Company and its Restricted Subsidiaries is subject to
further limitations on the incurrence of Indebtedness as described under
" -- Limitation on Indebtedness and Disqualified Capital Stock."
Change of Control. Upon the occurrence of a Change of Control, the Company
shall be obligated to make an offer to purchase all of the then outstanding
Notes (a "Change of Control Offer"), and shall purchase, on a Business Day (the
"Change of Control Purchase Date") not more than 60 nor less than 30 days
following such Change of Control, all of the then outstanding Notes validly
tendered pursuant to such Change of Control Offer, at a purchase price (the
"Change of Control Purchase Price") equal to 101% of the principal amount
thereof plus accrued and unpaid interest, if any, to the Change of Control
Purchase Date. The Change of Control Offer is required to remain open for at
least 20 Business Days and until the close of business on the fifth Business Day
prior to the Change of Control Purchase Date.
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In order to effect such Change of Control Offer, the Company shall, not
later than the 30th day after the Change of Control, give to the Trustee and
each Holder a notice of the Change of Control Offer, which notice shall govern
the terms of the Change of Control Offer and shall state, among other things,
the procedures that Holders must follow to accept the Change of Control Offer.
The occurrence of a Change of Control would result in the holders of any
then outstanding Senior Notes having the right under the Senior Indenture to
require the Company to make an offer to purchase all of such Senior Notes upon
substantially the same terms as the Notes. Further, the existing Bank Credit
Facilities contain, and any future credit agreements or other agreements
relating to Indebtedness or other obligations of the Company may contain,
prohibitions or restrictions on the Company's ability to effect a Change of
Control Offer, which would then also be blocked by the subordination provisions
of the Indenture. In the event a Change of Control occurs at a time when such
prohibitions or restrictions are in effect, the Company could seek the consent
of its lenders to the repurchase of Notes or could attempt to refinance the
borrowings or renegotiate the agreements that contain such prohibitions. If the
Company does not obtain such a consent or repay such borrowings or change such
agreements, the Company will be effectively prohibited from repurchasing Notes.
Failure by the Company to purchase the Notes when required would result in an
Event of Default, whether or not such purchase is permitted by the subordination
provisions of the Indenture. See " -- Subordination" and " -- Events of
Default." There can be no assurance that the Company would have adequate
resources to repay or refinance all Indebtedness and other obligations owing
under the Bank Credit Facilities and such other agreements and to fund the
purchase of the Senior Notes and the Notes upon a Change of Control.
The Company will not be required to make a Change of Control Offer upon a
Change of Control if another Person makes the Change of Control Offer at the
same purchase price, at the same times and otherwise in substantial compliance
with the requirements applicable to a Change of Control Offer to be made by the
Company and purchases all Notes validly tendered and not withdrawn under such
Change of Control Offer.
The definition of Change of Control includes a phrase relating to the
disposition of "all or substantially all" of the properties and assets of the
Company and its Restricted Subsidiaries, taken as a whole. Although there is a
developing body of case law interpreting the phrase "substantially all," there
is no precise established definition of the phrase under applicable law.
Accordingly, the ability of a Holder of the Notes to require the Company to
purchase such Notes as a result of a disposition of less than all of the
properties and assets of the Company and its Restricted Subsidiaries, taken as a
whole, to another Person may be uncertain.
The Company intends to comply with Rule 14e-1 under the Exchange Act and
any other securities laws and regulations thereunder, if applicable, in the
event that a Change of Control occurs and the Company is required to purchase
Notes as described above. The existence of a Holder's right to require, subject
to certain conditions, the Company to repurchase its Notes upon a Change of
Control may deter a third party from acquiring the Company in a transaction that
constitutes, or results in, a Change of Control.
Limitation on Asset Sales. (a) The Company will not, and will not permit
any Restricted Subsidiary to, engage in any Asset Sale unless (i) the Company or
such Restricted Subsidiary, as the case may be, receives consideration at the
time of such Asset Sale at least equal to the fair market value of the assets
and properties sold or otherwise disposed of pursuant to the Asset Sale (as
determined by the Board of Directors of the Company, whose determination shall
be conclusive and evidenced by a Board Resolution), (ii) at least 75% of the
consideration received by the Company or the Restricted Subsidiary, as the case
may be, in respect of such Asset Sale consists of cash, Cash Equivalents or
properties used in the Oil and Gas Business of the Company or its Restricted
Subsidiaries and (iii) the Company delivers to the Trustee an Officers'
Certificate certifying that such Asset Sale complies with clauses (i) and (ii).
The amount (without duplication) of any Indebtedness (other than Subordinated
Indebtedness) of the Company or such Restricted Subsidiary that is expressly
assumed by the transferee in such Asset Sale and with respect to which the
Company or such Restricted Subsidiary, as the case may be, is unconditionally
released by the holder of such Indebtedness, shall be deemed to be cash or Cash
Equivalents for purposes of clause (ii) and shall also be deemed to constitute a
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repayment of, and a permanent reduction in, the amount of such Indebtedness for
purposes of the following paragraph.
(b) If the Company or any Restricted Subsidiary engages in an Asset Sale,
the Company or such Restricted Subsidiary may either, no later than 360 days
after such Asset Sale, (i) apply all or any of the Net Available Proceeds
therefrom to repay Senior Indebtedness (including Senior Notes) or Pari Passu
Indebtedness (provided that in connection with the reduction of Pari Passu
Indebtedness, the Company or such Restricted Subsidiary redeems a pro rata
portion of the Notes) of the Company or any Restricted Subsidiary, provided, in
each case, that the related loan commitment (if any) is thereby permanently
reduced by the amount of such Indebtedness so repaid, or (ii) invest all or any
part of the Net Available Proceeds thereof in properties and assets that will be
used in the Oil and Gas Business of the Company or its Restricted Subsidiaries,
as the case may be. The amount of such Net Available Proceeds not applied or
invested as provided in this paragraph will constitute "Excess Proceeds."
(c) When the aggregate amount of Excess Proceeds equals or exceeds $10
million, the Company will be required to make an offer to purchase, from all
Holders of the Notes, an aggregate principal amount of Notes equal to such
Excess Proceeds as follows:
(i) The Company will make an offer to purchase (a "Net Proceeds Offer")
from all Holders of the Notes in accordance with the procedures set forth in the
Indenture the maximum principal amount (expressed as a multiple of $1,000) of
Notes that may be purchased out of the amount (the "Payment Amount") of such
Excess Proceeds.
(ii) The offer price for the Notes will be payable in cash in an amount
equal to 100% of the principal amount of the Notes tendered pursuant to a Net
Proceeds Offer, plus accrued and unpaid interest, if any, to the date such Net
Proceeds Offer is consummated (the "Offered Price"), in accordance with the
procedures set forth in the Indenture. To the extent that the aggregate Offered
Price of the Notes tendered pursuant to a Net Proceeds Offer is less than the
Payment Amount relating thereto (such shortfall constituting a "Net Proceeds
Deficiency"), the Company may use such Net Proceeds Deficiency, or a portion
thereof, for general corporate purposes, subject to the limitations of the
"Limitation on Restricted Payments" covenant.
(iii) If the aggregate Offered Price of Notes validly tendered and not
withdrawn by Holders thereof exceeds the Payment Amount, Notes to be purchased
will be selected on a pro rata basis.
(iv) Upon completion of such Net Proceeds Offer, the amount of Excess
Proceeds shall be reset to zero.
The Company will not permit any Restricted Subsidiary to enter into or suffer to
exist any agreement that would place any restriction of any kind (other than
pursuant to law or regulation) on the ability of the Company to make a Net
Proceeds Offer following any Asset Sale. The Company intends to comply with Rule
14e-1 under the Exchange Act, and any other securities laws and regulations
thereunder, if applicable, in the event that an Asset Sale occurs and the
Company is required to purchase Notes as described above.
Limitation on Guarantees by Subsidiary Guarantors. The Company will not
permit any Subsidiary Guarantor to guarantee the payment of any Subordinated
Indebtedness of the Company unless such guarantee shall be subordinated to such
Subsidiary Guarantor's Subsidiary Guarantee at least to the same extent as such
Subordinated Indebtedness is subordinated to the Notes; provided, however, that
this covenant will not be applicable to any guarantee of any Subsidiary
Guarantor that (i) existed at the time such Person became a Subsidiary of the
Company and (ii) was not incurred in connection with, or in contemplation of,
such Person becoming a Subsidiary of the Company.
Limitation on Dividends and Other Payment Restrictions Affecting Restricted
Subsidiaries. The Company will not, and will not permit any Restricted
Subsidiary to, directly or indirectly, create or suffer to exist or allow to
become effective any consensual encumbrance or restriction of any kind on the
ability of any Restricted Subsidiary (a) to pay dividends, in cash or otherwise,
or make any other distributions on its Capital Stock, or make payments on any
Indebtedness owed, to the Company or any other Restricted Subsidiary, (b) to
make loans or advances to the Company or any other Restricted Subsidiary or (c)
to transfer any of its property or assets to the Company or any other Restricted
Subsidiary (any such restrictions being collectively
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referred to herein as a "Payment Restriction"), except for such encumbrances or
restrictions existing under or by reason of (i) customary provisions restricting
subletting or assignment of any lease governing a leasehold interest of the
Company or any Restricted Subsidiary, or customary restrictions in licenses
relating to the property covered thereby and entered into in the ordinary course
of business, (ii) any instrument governing Indebtedness of a Person acquired by
the Company or any Restricted Subsidiary at the time of such acquisition, which
encumbrance or restriction is not applicable to any other Person, other than the
Person, or the property or assets of the Person, so acquired, provided that such
Indebtedness was not incurred in anticipation of such acquisition or (iii) the
Bank Credit Facilities as in effect on the date of the Indenture or any
agreement that amends, modifies, supplements, restates, extends, renews,
refinances or replaces the Bank Credit Facilities, provided that the terms and
conditions of any Payment Restrictions thereunder are not materially less
favorable to the Holders of the Notes than those under the Bank Credit
Facilities as in effect on the date of the Indenture.
Limitation on Conduct of Business. The Company will not, and will not
permit any of its Restricted Subsidiaries to, engage in the conduct of any
business other than the Oil and Gas Business.
Reports. The Company will file on a timely basis with the Commission, to
the extent such filings are accepted by the Commission and whether or not the
Company has a class of securities registered under the Exchange Act, the annual
reports, quarterly reports and other documents that the Company would be
required to file if it were subject to Section 13 or 15 of the Exchange Act. The
Company will also be required (a) to file with the Trustee (with exhibits), and
provide to each Holder of Notes (without exhibits), without cost to such Holder,
copies of such reports and documents within 15 days after the date on which the
Company files such reports and documents with the Commission or the date on
which the Company would be required to file such reports and documents if the
Company were so required and (b) if filing such reports and documents with the
Commission is not accepted by the Commission or is prohibited under the Exchange
Act, to supply at its cost copies of such reports and documents (including any
exhibits thereto) to any Holder of Notes promptly upon written request.
Future Designation of Restricted and Unrestricted Subsidiaries. The
foregoing covenants (including calculation of financial ratios and the
determination of limitations on the incurrence of Indebtedness and Liens) may be
affected by the designation by the Company of any existing or future Subsidiary
of the Company as an Unrestricted Subsidiary. The definition of "Unrestricted
Subsidiary" set forth under the caption "-- Certain Definitions" describes the
circumstances under which a Subsidiary of the Company may be designated as an
Unrestricted Subsidiary by the Board of Directors of the Company.
MERGER, CONSOLIDATION AND SALE OF ASSETS
The Company will not, in any single transaction or series of related
transactions, merge or consolidate with or into any other Person, or sell,
assign, convey, transfer, lease or otherwise dispose of all or substantially all
of the properties and assets of the Company and its Restricted Subsidiaries on a
consolidated basis to any Person or group of Affiliated Persons, and the Company
will not permit any of its Restricted Subsidiaries to enter into any such
transaction or series of transactions if such transaction or series of
transactions, in the aggregate, would result in the sale, assignment,
conveyance, transfer, lease or other disposition of all or substantially all of
the properties and assets of the Company and its Restricted Subsidiaries on a
consolidated basis to any other Person or group of Affiliated Persons, unless at
the time and after giving effect thereto (i) either (A) if the transaction is a
merger or consolidation, the Company shall be the surviving Person of such
merger or consolidation, or (B) the Person (if other than the Company) formed by
such consolidation or into which the Company is merged or to which the
properties and assets of the Company or its Restricted Subsidiaries, as the case
may be, are sold, assigned, conveyed, transferred, leased or otherwise disposed
of (any such surviving Person or transferee Person being the "Surviving Entity")
shall be a corporation organized and existing under the laws of the United
States of America, any state thereof or the District of Columbia and shall, in
either case, expressly assume by a supplemental indenture to the Indenture
executed and delivered to the Trustee, in form satisfactory to the Trustee, all
the obligations of the Company under the Notes and the Indenture, and, in each
case, the Indenture shall remain in full force and effect; (ii) immediately
before and immediately after giving effect to such transaction or series of
transactions on a
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pro forma basis (and treating any Indebtedness not previously an obligation of
Company or any of its Restricted Subsidiaries which becomes an obligation of the
Company or any of its Restricted Subsidiaries in connection with or as a result
of such transaction as having been incurred at the time of such transaction), no
Default or Event of Default shall have occurred and be continuing; (iii) except
in the case of the consolidation or merger of any Restricted Subsidiary with or
into the Company, immediately after giving effect to such transaction or
transactions on a pro forma basis, the Consolidated Net Worth of the Company (or
the Surviving Entity if the Company is not the continuing obligor under the
Indenture) is at least equal to the Consolidated Net Worth of the Company
immediately before such transaction or transactions; (iv) except in the case of
the consolidation or merger of the Company with or into a Restricted Subsidiary
or any Restricted Subsidiary with or into the Company or another Restricted
Subsidiary, immediately before and immediately after giving effect to such
transaction or transactions on a pro forma basis (assuming that the transaction
or transactions occurred on the first day of the period of four fiscal quarters
ending immediately prior to the consummation of such transaction or
transactions, with the appropriate adjustments with respect to the transaction
or transactions being included in such pro forma calculation), the Company (or
the Surviving Entity if the Company is not the continuing obligor under the
Indenture) could incur $1.00 of additional Indebtedness (other than Permitted
Indebtedness) pursuant to the "-- Limitation on Indebtedness and Disqualified
Capital Stock" covenant; (v) if the Company is not the continuing obligor under
the Indenture, then each Subsidiary Guarantor, unless it is the Surviving
Entity, shall have by supplemental indenture to the Indenture confirmed that its
Subsidiary Guarantee of the Notes shall apply to the Surviving Entity's
obligations under the Indenture and the Notes; (vi) if any of the properties or
assets of the Company or any of its Restricted Subsidiaries would upon such
transaction or series of related transactions become subject to any Lien (other
than a Permitted Lien), the creation and imposition of such Lien shall have been
in compliance with the "Limitation on Liens" covenant; and (vii) the Company (or
the Surviving Entity if the Company is not the continuing obligor under the
Indenture) shall have delivered to the Trustee, in form and substance reasonably
satisfactory to the Trustee, (a) an Officers' Certificate stating that such
consolidation, merger, transfer, lease or other disposition and any supplemental
indenture in respect thereto comply with the requirements under the Indenture
and (b) an Opinion of Counsel stating that the requirements of clause (i) of
this paragraph have been satisfied.
Upon any consolidation or merger or any sale, assignment, lease,
conveyance, transfer or other disposition of all or substantially all of the
properties and assets of the Company and its Restricted Subsidiaries on a
consolidated basis in accordance with the foregoing, in which the Company is not
the continuing corporation, the Surviving Entity shall succeed to, and be
substituted for, and may exercise every right and power of, the Company under
the Indenture with the same effect as if the Surviving Entity had been named as
the Company therein, and thereafter the Company, except in the case of a lease,
will be discharged from all obligations and covenants under the Indenture and
the Notes and may be liquidated and dissolved.
EVENTS OF DEFAULT
The following will be "Events of Default" under the Indenture:
(i) default in the payment of the principal of or premium, if any, on any
of the Notes, whether such payment is due at Stated Maturity, upon redemption,
upon repurchase pursuant to a Change of Control Offer or a Net Proceeds Offer,
upon acceleration or otherwise; or
(ii) default in the payment of any installment of interest on any of the
Notes, when due, and the continuance of such default for a period of 30 days
(even if such payment is prohibited by the subordination provisions of the
Indenture); or
(iii) default in the performance or breach of the provisions of the
"Merger, Consolidation and Sale of Assets" section of the Indenture, the failure
to make or consummate a Change of Control Offer in accordance with the
provisions of the "Change of Control" covenant or the failure to make or
consummate a Net Proceeds Offer in accordance with the provisions of the
"Limitation on Asset Sales" covenant; or
(iv) the Company or any Subsidiary Guarantor shall fail to perform or
observe any other term, covenant or agreement contained in the Notes, any
Subsidiary Guarantee or the Indenture (other than a default
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specified in (i), (ii) or (iii) above) for a period of 60 days after written
notice of such failure stating that it is a "notice of default" under the
Indenture and requiring the Company or such Subsidiary Guarantor to remedy the
same shall have been given (x) to the Company by the Trustee or (y) to the
Company and the Trustee by the Holders of at least 25% in aggregate principal
amount of the Notes then outstanding; or
(v) the occurrence and continuation beyond any applicable grace period of
any default in the payment of the principal of, premium, if any, or interest on
any Indebtedness of the Company (other than the Notes) or any Subsidiary
Guarantor or any other Restricted Subsidiary for money borrowed when due, or any
other default resulting in acceleration of any Indebtedness of the Company or
any Subsidiary Guarantor or any other Restricted Subsidiary for money borrowed,
provided that the aggregate principal amount of such Indebtedness shall exceed
$5.0 million and provided, further, that if any such default is cured or waived
or any such acceleration rescinded, or such Indebtedness is repaid, within a
period of 10 days from the continuation of such default beyond the applicable
grace period or the occurrence of such acceleration, as the case may be, such
Event of Default under the Indenture and any consequential acceleration of the
Notes shall be automatically rescinded, so long as such rescission does not
conflict with any judgment or decree; or
(vi) any Subsidiary Guarantee shall for any reason cease to be, or be
asserted by the Company or any Subsidiary Guarantor, as applicable, not to be,
in full force and effect (except pursuant to the release of any such Subsidiary
Guarantee in accordance with the Indenture); or
(vii) final judgments or orders rendered against the Company or any
Subsidiary Guarantor or any other Restricted Subsidiary that are unsatisfied and
that require the payment in money, either individually or in an aggregate
amount, that is more than $5.0 million over the coverage under applicable
insurance policies and either (A) commencement by any creditor of an enforcement
proceeding upon such judgment (other than a judgment that is stayed by reason of
pending appeal or otherwise) or (B) the occurrence of a 60-day period during
which a stay of such judgment or order, by reason of pending appeal or
otherwise, was not in effect; or
(viii) the entry of a decree or order by a court having jurisdiction in the
premises (A) for relief in respect of the Company or any Subsidiary Guarantor or
any other Restricted Subsidiary in an involuntary case or proceeding under any
applicable federal or state bankruptcy, insolvency, reorganization or other
similar law or (B) adjudging the Company or any Subsidiary Guarantor or any
other Restricted Subsidiary bankrupt or insolvent, or approving a petition
seeking reorganization, arrangement, adjustment or composition of the Company or
any Subsidiary Guarantor or any other Restricted Subsidiary under any applicable
federal or state law, or appointing under any such law a custodian, receiver,
liquidator, assignee, trustee, sequestrator or other similar official of the
Company or any Subsidiary Guarantor or any other Restricted Subsidiary or of a
substantial part of its consolidated assets, or ordering the winding up or
liquidation of its affairs, and the continuance of any such decree or order for
relief or any such other decree or order unstayed and in effect for a period of
60 consecutive days; or
(ix) the commencement by the Company or any Subsidiary Guarantor or any
other Restricted Subsidiary of a voluntary case or proceeding under any
applicable federal or state bankruptcy, insolvency, reorganization or other
similar law or any other case or proceeding to be adjudicated bankrupt or
insolvent, or the consent by the Company or any Subsidiary Guarantor or any
other Restricted Subsidiary to the entry of a decree or order for relief in
respect thereof in an involuntary case or proceeding under any applicable
federal or state bankruptcy, insolvency, reorganization or other similar law or
to the commencement of any bankruptcy or insolvency case or proceeding against
it, or the filing by the Company or any Subsidiary Guarantor or any other
Restricted Subsidiary of a petition or consent seeking reorganization or relief
under any applicable federal or state law, or the consent by it under any such
law to the filing of any such petition or to the appointment of or taking
possession by a custodian, receiver, liquidator, assignee, trustee or
sequestrator (or other similar official) of the Company or any Subsidiary
Guarantor or any other Restricted Subsidiary or of any substantial part of its
consolidated assets, or the making by it of an assignment for the benefit of
creditors under any such law, or the admission by it in writing of its inability
to pay its debts generally as they become due or taking of corporate action by
the Company or any Subsidiary Guarantor or any other Restricted Subsidiary in
furtherance of any such action.
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If an Event of Default (other than as specified in clause (viii) or (ix) above)
shall occur and be continuing, the Trustee, by written notice to the Company, or
the Holders of at least 25% in aggregate principal amount of the Notes then
outstanding, by written notice to the Trustee and the Company, may, and the
Trustee upon the request of the Holders of not less than 25% in aggregate
principal amount of the Notes then outstanding shall, declare the principal of,
premium, if any, and accrued and unpaid interest on all of the Notes due and
payable immediately, upon which declaration all amounts payable in respect of
the Notes shall be immediately due and payable. If an Event of Default specified
in clause (viii) or (ix) above occurs and is continuing, then the principal of,
premium, if any, and accrued and unpaid interest on all of the Notes shall
become and be immediately due and payable without any declaration, notice or
other act on the part of the Trustee or any Holder of Notes.
After a declaration of acceleration under the Indenture, but before a
judgment or decree for payment of the money due has been obtained by the
Trustee, the Holders of a majority in aggregate principal amount of the
outstanding Notes, by written notice to the Company, the Subsidiary Guarantors
and the Trustee, may rescind and annul such declaration if (a) the Company or
any Subsidiary Guarantor has paid or deposited with the Trustee a sum sufficient
to pay (i) all sums paid or advanced by the Trustee under the Indenture and the
reasonable compensation, expenses, disbursements and advances of the Trustee,
its agents and counsel, (ii) all overdue interest on all Notes, (iii) the
principal of and premium, if any, on any Notes which have become due otherwise
than by such declaration of acceleration and interest thereon at the rate borne
by the Notes, and (iv) to the extent that payment of such interest is lawful,
interest upon overdue interest and overdue principal at the rate borne by the
Notes (without duplication of any amount paid or deposited pursuant to clause
(ii) or (iii)); (b) the rescission would not conflict with any judgment or
decree of a court of competent jurisdiction; and (c) all Events of Default,
other than the non-payment of principal of, premium, if any, or interest on the
Notes that has become due solely by such declaration of acceleration, have been
cured or waived.
No Holder will have any right to institute any proceeding with respect to
the Indenture or any remedy thereunder, unless such Holder has notified the
Trustee of a continuing Event of Default and the Holders of at least 25% in
aggregate principal amount of the outstanding Notes have made written request,
and offered reasonable indemnity, to the Trustee to institute such proceeding as
Trustee under the Notes and the Indenture, the Trustee has failed to institute
such proceeding within 60 days after receipt of such notice and the Trustee,
within such 60-day period, has not received directions inconsistent with such
written request by Holders of a majority in aggregate principal amount of the
outstanding Notes. Such limitations will not apply, however, to a suit
instituted by the Holder of a Note for the enforcement of the payment of the
principal of, premium, if any, or interest on such Note on or after the
respective due dates expressed in such Note.
During the existence of an Event of Default, the Trustee will be required
to exercise such rights and powers vested in it under the Indenture and use the
same degree of care and skill in its exercise thereof as a prudent person would
exercise under the circumstances in the conduct of such person's own affairs.
Subject to the provisions of the Indenture relating to the duties of the Trustee
in case an Event of Default shall occur and be continuing, the Trustee will not
be under any obligation to exercise any of its rights or powers under the
Indenture at the request or direction of any of the Holders unless such Holders
shall have offered to the Trustee reasonable security or indemnity. Subject to
certain provisions concerning the rights of the Trustee, the Holders of a
majority in aggregate principal amount of the outstanding Notes will have the
right to direct the time, method and place of conducting any proceeding for any
remedy available to the Trustee, or exercising any trust or power conferred on
the Trustee under the Indenture.
If a Default or an Event of Default occurs and is continuing and is known
to the Trustee, the Trustee shall mail to each Holder notice of the Default or
Event of Default within 60 days after the occurrence thereof. Except in the case
of a Default or an Event of Default in payment of principal of, premium, if any,
or interest on any Notes, the Trustee may withhold the notice to the Holders of
the Notes if the Trustee determines in good faith that withholding the notice is
in the interest of the Holders of the Notes.
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The Company will be required to furnish to the Trustee annual and quarterly
statements as to the performance by the Company of its obligations under the
Indenture and as to any default in such performance. The Company is also
required to notify the Trustee within 10 days of any Default or Event of
Default.
LEGAL DEFEASANCE OR COVENANT DEFEASANCE OF INDENTURE
The Company may, at its option and at any time, terminate the obligations
of the Company and the Subsidiary Guarantors with respect to the outstanding
Notes (such action being a "legal defeasance"). Such legal defeasance means that
the Company and the Subsidiary Guarantors shall be deemed to have paid and
discharged the entire Indebtedness represented by the outstanding Notes and to
have been discharged from all their other obligations with respect to the Notes
and the Subsidiary Guarantees, except for, among other things, (i) the rights of
Holders of outstanding Notes to receive payment in respect of the principal of,
premium, if any, and interest on such Notes when such payments are due, (ii) the
Company's obligations to replace any temporary Notes, register the transfer or
exchange of any Notes, replace mutilated, destroyed, lost or stolen Notes and
maintain an office or agency for payments in respect of the Notes, (iii) the
rights, powers, trusts, duties and immunities of the Trustee, and (iv) the
defeasance provisions of the Indenture. In addition, the Company may, at its
option and at any time, elect to terminate the obligations of the Company and
each Subsidiary Guarantor with respect to certain covenants that are set forth
in the Indenture, some of which are described under "-- Certain Covenants"
above, and any omission to comply with such obligations shall not constitute a
Default or an Event of Default with respect to the Notes (such action being a
"covenant defeasance").
In order to exercise either legal defeasance or covenant defeasance, (i)
the Company or any Subsidiary Guarantor must irrevocably deposit with the
Trustee, in trust, for the benefit of the Holders of the Notes, cash in United
States dollars, U.S. Government Obligations (as defined in the Indenture), or a
combination thereof, in such amounts as will be sufficient, in the opinion of a
nationally recognized firm of independent public accountants, to pay the
principal of, premium, if any, and interest on the outstanding Notes to
redemption or maturity; (ii) the Company shall have delivered to the Trustee an
Opinion of Counsel to the effect that the Holders of the outstanding Notes will
not recognize income, gain or loss for federal income tax purposes as a result
of such legal defeasance or covenant defeasance and will be subject to federal
income tax on the same amounts, in the same manner and at the same times as
would have been the case if such legal defeasance or covenant defeasance had not
occurred (in the case of legal defeasance, such opinion must refer to and be
based upon a published ruling of the Internal Revenue Service or a change in
applicable federal income tax laws); (iii) no Default or Event of Default shall
have occurred and be continuing on the date of such deposit or insofar as
clauses (viii) and (ix) under the first paragraph of "Events of Default" are
concerned, at any time during the period ending on the 91st day after the date
of deposit; (iv) such legal defeasance or covenant defeasance shall not cause
the Trustee to have a conflicting interest under the Indenture or the Trust
Indenture Act with respect to any securities of the Company or any Subsidiary
Guarantor; (v) such legal defeasance or covenant defeasance shall not result in
a breach or violation of, or constitute a default under, any material agreement
or instrument to which the Company or any Subsidiary Guarantor is a party or by
which it is bound; and (vi) the Company shall have delivered to the Trustee an
Officers' Certificate and an Opinion of Counsel satisfactory to the Trustee,
which, taken together, state that all conditions precedent under the Indenture
to either legal defeasance or covenant defeasance, as the case may be, have been
complied with.
SATISFACTION AND DISCHARGE
The Indenture will be discharged and will cease to be of further effect
(except as to surviving rights of registration of transfer or exchange of the
Notes, as expressly provided for in the Indenture) as to all outstanding Notes
when (i) either (a) all the Notes theretofore authenticated and delivered
(except lost, stolen, mutilated or destroyed Notes which have been replaced or
paid and Notes for whose payment money or certain United States government
obligations have theretofore been deposited in trust or segregated and held in
trust by the Company and thereafter repaid to the Company or discharged from
such trust) have been delivered to the Trustee for cancellation or (b) all Notes
not theretofore delivered to the Trustee for
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cancellation have become due and payable or will become due and payable at their
Stated Maturity within one year, or are to be called for redemption within one
year under arrangements satisfactory to the Trustee for the serving of notice of
redemption by the Trustee in the name, and at the expense, of the Company, and
the Company has irrevocably deposited or caused to be deposited with the Trustee
funds in an amount sufficient to pay and discharge the entire Indebtedness on
the Notes not theretofore delivered to the Trustee for cancellation, for
principal of, premium, if any, and interest on the Notes to the date of deposit
(in the case of Notes which have become due and payable) or to the Stated
Maturity or Redemption Date, as the case may be, together with instructions from
the Company irrevocably directing the Trustee to apply such funds to the payment
thereof at maturity or redemption, as the case may be; (ii) the Company has paid
all other sums payable under the Indenture by the Company; and (iii) the Company
has delivered to the Trustee an Officers' Certificate and an Opinion of Counsel
which, taken together, state that all conditions precedent under the Indenture
relating to the satisfaction and discharge of the Indenture have been complied
with.
AMENDMENTS AND WAIVERS
From time to time, the Company, the Subsidiary Guarantors and the Trustee
may, without the consent of the Holders of the Notes, amend or supplement the
Indenture or the Notes for certain specified purposes, including, among other
things, curing ambiguities, defects or inconsistencies, qualifying, or
maintaining the qualification of, the Indenture under the Trust Indenture Act,
adding or releasing any Subsidiary Guarantor pursuant to the terms of the
Indenture, or making any change that does not materially adversely affect the
rights of any Holder of Notes. Other amendments and modifications of the
Indenture or the Notes may be made by the Company, the Subsidiary Guarantors and
the Trustee with the consent of the Holders of not less than a majority of the
aggregate principal amount of the outstanding Notes; provided, however, that no
such modification or amendment may, without the consent of the Holder of each
outstanding Note affected thereby, (a) change the Stated Maturity of the
principal of, or any installment of interest on, any Note, (b) reduce the
principal amount of, premium, if any, or interest on any Note, (c) change the
coin or currency of payment of principal of, premium, if any, or interest on,
any Note, (d) impair the right to institute suit for the enforcement of any
payment on or with respect to any Note, (e) reduce the above-stated percentage
of aggregate principal amount of outstanding Notes necessary to modify or amend
the Indenture, (f) reduce the percentage of aggregate principal amount of
outstanding Notes necessary for waiver of compliance with certain provisions of
the Indenture or for waiver of certain defaults, (g) modify any provisions of
the Indenture relating to the modification and amendment of the Indenture or the
waiver of past defaults or covenants, except as otherwise specified, (h) modify
any provisions of the Indenture relating to subordination of the Notes or the
Subsidiary Guarantees in a manner adverse to the Holders or (i) amend, change or
modify the obligation of the Company to make and consummate a Change of Control
Offer in the event of a Change of Control or make and consummate a Net Proceeds
Offer with respect to any Asset Sale or modify any of the provisions or
definitions with respect thereto.
The Holders of not less than a majority in aggregate principal amount of
the outstanding Notes may, on behalf of the Holders of all Notes, waive any past
default under the Indenture, except a default in the payment of principal of,
premium, if any, or interest on the Notes, or in respect of a covenant or
provision which under the Indenture cannot be modified or amended without the
consent of the Holder of each Note outstanding.
THE TRUSTEE
State Street Bank and Trust Company will serve as trustee under the
Indenture.
The Indenture (including provisions of the Trust Indenture Act incorporated
by reference therein) will contain limitations on the rights of the Trustee
thereunder, should it become a creditor of the Company, to obtain payment of
claims in certain cases or to realize on certain property received by it in
respect of any such claims, as security or otherwise. The Indenture will permit
the Trustee to engage in other transactions; provided, however, if it acquires
any conflicting interest (as defined in the Trust Indenture Act) it must
eliminate such conflict or resign.
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State Street Bank and Trust Company is also the trustee under the Senior
Notes Indenture. Pursuant to the Trust Indenture Act, should a default occur
with respect to either the Senior Notes or the Notes, State Street Bank and
Trust Company would be required to resign as trustee under one of the indentures
within 90 days of such default, unless such default were cured, duly waived or
otherwise eliminated.
GOVERNING LAW
The Indenture, the Notes and the Subsidiary Guarantees will be governed by,
and construed and enforced in accordance with, the laws of the State of New
York.
CERTAIN DEFINITIONS
"Acquired Indebtedness" means Indebtedness of a Person (a) existing at the
time such Person becomes a Restricted Subsidiary or (b) assumed in connection
with acquisitions of properties or assets from such Person (other than any
Indebtedness incurred in connection with, or in contemplation of, such Person
becoming a Restricted Subsidiary or such acquisition). Acquired Indebtedness
shall be deemed to be incurred on the date the acquired Person becomes a
Restricted Subsidiary or the date of the related acquisition of properties or
assets from such Person.
"Adjusted Net Assets" of a Subsidiary Guarantor at any date shall mean the
amount by which the fair value of the properties and assets of such Subsidiary
Guarantor exceeds the total amount of liabilities, including, without
limitation, contingent liabilities (after giving effect to all other fixed and
contingent liabilities incurred or assumed on such date), but excluding
liabilities under its Subsidiary Guarantee, of such Subsidiary Guarantor at such
date.
"Affiliate" means, with respect to any specified Person, any other Person
directly or indirectly controlling or controlled by or under direct or indirect
common control with such specified Person. For the purposes of this definition,
"control," when used with respect to any Person, means the power to direct the
management and policies of such Person, directly or indirectly, whether through
the ownership of voting securities, by contract or otherwise; and the terms
"controlling" and "controlled" have meanings correlative to the foregoing. For
purposes of this definition, beneficial ownership of 10% or more of the voting
common equity (on a fully diluted basis) or options or warrants to purchase such
equity (but only if exercisable at the date of determination or within 60 days
thereof) of a Person shall be deemed to constitute control of such Person.
"Asset Sale" means any sale, issuance, conveyance, transfer, lease or other
disposition to any Person other than the Company or any of its Restricted
Subsidiaries (including, without limitation, by means of a merger or
consolidation) (collectively, for purposes of this definition, a "transfer"),
directly or indirectly, in one or a series of related transactions, of (a) any
Capital Stock of any Restricted Subsidiary held by the Company or any Restricted
Subsidiary, (b) all or substantially all of the properties and assets of any
division or line of business of the Company or any of its Restricted
Subsidiaries or (c) any other properties or assets of the Company or any of its
Restricted Subsidiaries other than (i) a transfer of cash, Cash Equivalents,
hydrocarbons or other mineral products in the ordinary course of business or
(ii) any lease, abandonment, disposition, relinquishment or farm-out of any oil
and gas properties in the ordinary course of business. For the purposes of this
definition, the term "Asset Sale" also shall not include (i) any transfer of
properties or assets (including Capital Stock) that is governed by, and made in
accordance with, the provisions described under "-- Merger, Consolidation and
Sale of Assets"; (ii) any transfer of properties or assets to an Unrestricted
Subsidiary, if permitted under the "Limitation on Restricted Payments" covenant;
or (iii) any transfer of properties or assets (including Capital Stock) having a
fair market value of less than $2 million.
"Average Life" means, with respect to any Indebtedness, as at any date of
determination, the quotient obtained by dividing (a) the sum of the products of
(i) the number of years (and any portion thereof) from the date of determination
to the date or dates of each successive scheduled principal payment (including,
without limitation, any sinking fund or mandatory redemption payment
requirements) of such Indebtedness multiplied by (ii) the amount of each such
principal payment by (b) the sum of all such principal payments.
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"Bank Credit Facilities" means (i) that certain Credit Agreement dated
effective as of September 25, 1996, as amended, among KCS Resources, Inc., KCS
Pipeline Systems, Inc., KCS Michigan Resources, Inc., and KCS Energy Marketing,
Inc., as Borrowers, KCS Energy, Inc., as Guarantor, and Canadian Imperial Bank
of Commerce, New York Agency, as Agent, CIBC, Inc., as Collateral Agent, Bank
One, Texas, N.A., as Co-Agent, and NationsBank of Texas, N.A., as Co-Agent, and
(ii) that certain Credit Agreement dated as of January 2, 1997, as amended,
among KCS Medallion Resources, Inc., KCS Energy, Inc., KCS Energy Services, Inc.
and Medallion Gas Services, Inc., as Borrowers, and Canadian Imperial Bank of
Commerce, New York Agency, as Agent, and CIBC, Inc., as Collateral Agent, in
each case as the same may be amended, modified, supplemented, extended,
restated, replaced, renewed or refinanced from time to time in one or more
credit agreements, loan agreements, instruments or similar agreements, as such
may be further amended, modified, supplemented, extended, restated, replaced,
renewed or refinanced.
"Capital Stock" means, with respect to any Person, any and all shares,
interests, participations, rights or other equivalents in the equity interests
(however designated) in such Person, and any rights (other than debt securities
convertible into an equity interest), warrants or options exercisable for,
exchangeable for or convertible into such an equity interest in such Person.
"Capitalized Lease Obligation" means any obligation to pay rent or other
amounts under a lease of (or other agreement conveying the right to use) any
property (whether real, personal or mixed) that is required to be classified and
accounted for as a capital lease obligation under GAAP, and, for the purpose of
the Indenture, the amount of such obligation at any date shall be the
capitalized amount thereof at such date, determined in accordance with GAAP.
"Cash Equivalents" means (i) any evidence of Indebtedness with a maturity
of 180 days or less issued or directly and fully guaranteed or insured by the
United States of America or any agency or instrumentality thereof (provided that
the full faith and credit of the United States of America is pledged in support
thereof); (ii) demand and time deposits and certificates of deposit or
acceptances with a maturity of 180 days or less of any financial institution
that is a member of the Federal Reserve System having combined capital and
surplus and undivided profits of not less than $500 million; (iii) commercial
paper with a maturity of 180 days or less issued by a corporation that is not an
Affiliate of the Company and is organized under the laws of any state of the
United States or the District of Columbia and rated at least A-l by S&P or at
least P-l by Moody's; (iv) repurchase obligations with a term of not more than
seven days for underlying securities of the types described in clause (i) above
entered into with any commercial bank meeting the specifications of clause (ii)
above; (v) overnight bank deposits and bankers acceptances at any commercial
bank meeting the qualifications specified in clause (ii) above; (vi) deposits
available for withdrawal on demand with any commercial bank not meeting the
qualifications specified in clause (ii) above but which is a lending bank under
any of the Bank Credit Facilities, provided all such deposits do not exceed $5
million in the aggregate at any one time; (vii) demand and time deposits and
certificates of deposit with any commercial bank organized in the United States
not meeting the qualifications specified in clause (ii) above, provided that
such deposits and certificates support bond, letter of credit and other similar
types of obligations incurred in the ordinary course of business; and (viii)
investments in money market or other mutual funds substantially all of whose
assets comprise securities of the types described in clauses (i) through (v)
above.
"Change of Control" means the occurrence of any event or series of events
by which: (a) any "person" or "group" (as such terms are used in Sections 13(d)
and 14(d) of the Exchange Act) is or becomes the beneficial owner (as defined in
Rule 13d-3 under the Exchange Act), directly or indirectly, of more than 50% of
the total Voting Stock of the Company; (b) the Company consolidates with or
merges into another Person or any Person consolidates with, or merges into, the
Company, in any such event pursuant to a transaction in which the outstanding
Voting Stock of the Company is changed into or exchanged for cash, securities or
other property, other than any such transaction where (i) the outstanding Voting
Stock of the Company is changed into or exchanged for Voting Stock of the
surviving or resulting Person that is Qualified Capital Stock and (ii) the
holders of the Voting Stock of the Company immediately prior to such transaction
own, directly or indirectly, not less than a majority of the Voting Stock of the
surviving or resulting Person immediately after such transaction; (c) the
Company, either individually or in conjunction with one or more Restricted
Subsidiaries, sells, assigns, conveys, transfers, leases or otherwise disposes
of, or the Restricted Subsidiaries
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sell, assign, convey, transfer, lease or otherwise dispose of, all or
substantially all of the properties and assets of the Company and such
Restricted Subsidiaries, taken as a whole (either in one transaction or a series
of related transactions), including Capital Stock of the Restricted
Subsidiaries, to any Person (other than the Company or a Restricted Subsidiary);
(d) during any consecutive two-year period, individuals who at the beginning of
such period constituted the Board of Directors of the Company (together with any
new directors whose election by such Board of Directors or whose nomination for
election by the stockholders of the Company was approved by a vote of 66 2/3% of
the directors then still in office who were either directors at the beginning of
such period or whose election or nomination for election was previously so
approved) cease for any reason to constitute a majority of the Board of
Directors of the Company then in office; or (e) the liquidation or dissolution
of the Company.
"Common Stock" of any Person means Capital Stock of such Person that does
not rank prior, as to the payment of dividends or as to the distribution of
assets upon any voluntary or involuntary liquidation, dissolution or winding up
of such Person, to shares of Capital Stock of any other class of such Person.
"Consolidated EBITDA Coverage Ratio" means, for any period, the ratio on a
pro forma basis of (a) the sum of Consolidated Net Income, Consolidated Interest
Expense, Consolidated Income Tax Expense and Consolidated Non-cash Charges
deducted in computing Consolidated Net Income, in each case, for such period, of
the Company and its Restricted Subsidiaries on a consolidated basis, all
determined in accordance with GAAP, decreased (to the extent included in
determining Consolidated Net Income) by the sum of (x) the amount of deferred
revenues that are amortized during such period and are attributable to reserves
that are subject to Volumetric Production Payments and (y) amounts recorded in
accordance with GAAP as repayments of principal and interest pursuant to
Dollar-Denominated Production Payments, to (b) the sum of such Consolidated
Interest Expense for such period; provided, however, that (i) the Consolidated
EBITDA Coverage Ratio shall be calculated on a pro forma basis assuming that (A)
the Indebtedness to be incurred (and all other Indebtedness incurred after the
first day of such period of four full fiscal quarters referred to in the
covenant described under "-- Certain Covenants -- Limitation on Indebtedness and
Disqualified Capital Stock" through and including the date of determination),
and (if applicable) the application of the net proceeds therefrom (and from any
other such Indebtedness), including to refinance other Indebtedness, had been
incurred on the first day of such four-quarter period and, in the case of
Acquired Indebtedness, on the assumption that the related transaction (whether
by means of purchase, merger or otherwise) also had occurred on such date with
the appropriate adjustments with respect to such acquisition being included in
such pro forma calculation and (B) any acquisition or disposition by the Company
or any Restricted Subsidiary of any properties or assets outside the ordinary
course of business, or any repayment of any principal amount of any Indebtedness
of the Company or any Restricted Subsidiary prior to the Stated Maturity
thereof, in either case since the first day of such period of four full fiscal
quarters through and including the date of determination, had been consummated
on such first day of such four-quarter period, (ii) in making such computation,
the Consolidated Interest Expense attributable to interest on any Indebtedness
required to be computed on a pro forma basis in accordance with the covenant
described under "-- Certain Covenants -- Limitation on Indebtedness and
Disqualified Capital Stock" and (A) bearing a floating interest rate shall be
computed as if the rate in effect on the date of computation had been the
applicable rate for the entire period and (B) which was not outstanding during
the period for which the computation is being made but which bears, at the
option of the Company, a fixed or floating rate of interest, shall be computed
by applying, at the option of the Company, either the fixed or floating rate,
(iii) in making such computation, the Consolidated Interest Expense attributable
to interest on any Indebtedness under a revolving credit facility required to be
computed on a pro forma basis in accordance with the covenant described under
"-- Certain Covenants -- Limitation on Indebtedness and Disqualified Capital
Stock" shall be computed based upon the average daily balance of such
Indebtedness during the applicable period, provided that such average daily
balance shall be reduced by the amount of any repayment of Indebtedness under a
revolving credit facility during the applicable period, which repayment
permanently reduced the commitments or amounts available to be reborrowed under
such facility, (iv) notwithstanding clauses (ii) and (iii) of this proviso,
interest on Indebtedness determined on a fluctuating basis, to the extent such
interest is covered by agreements relating to Interest Rate Protection
Obligations, shall be deemed to have accrued at the rate per annum resulting
after giving effect to the operation of such agreements, (v) in making such
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calculation, Consolidated Interest Expense shall exclude interest attributable
to Dollar-Denominated Production Payments, and (vi) if after the first day of
the period referred to in clause (a) of this definition the Company has
permanently retired any Indebtedness out of the Net Cash Proceeds of the
issuance and sale of shares of Qualified Capital Stock of the Company within 30
days of such issuance and sale, Consolidated Interest Expense shall be
calculated on a pro forma basis as if such Indebtedness had been retired on the
first day of such period.
"Consolidated Income Tax Expense" means, for any period, the provision for
federal, state, local and foreign income taxes (including state franchise taxes
accounted for as income taxes in accordance with GAAP) of the Company and its
Restricted Subsidiaries for such period as determined on a consolidated basis in
accordance with GAAP.
"Consolidated Interest Expense" means, for any period, without duplication,
the sum of (i) the interest expense of the Company and its Restricted
Subsidiaries for such period as determined on a consolidated basis in accordance
with GAAP, including, without limitation, (a) any amortization of debt discount,
(b) the net cost under Interest Rate Protection Obligations (including any
amortization of discounts), (c) the interest portion of any deferred payment
obligation constituting Indebtedness, (d) all commissions, discounts and other
fees and charges owed with respect to letters of credit and bankers' acceptance
financing and (e) all accrued interest, in each case to the extent attributable
to such period, (ii) to the extent any Indebtedness of any Person (other than
the Company or a Restricted Subsidiary) is guaranteed by the Company or any
Restricted Subsidiary, the aggregate amount of interest paid (to the extent not
accrued in a prior period) or accrued by such other Person during such period
attributable to any such Indebtedness, in each case to the extent attributable
to that period, (iii) the aggregate amount of the interest component of
Capitalized Lease Obligations paid (to the extent not accrued in a prior
period), accrued or scheduled to be paid or accrued by the Company and its
Restricted Subsidiaries during such period as determined on a consolidated basis
in accordance with GAAP and (iv) the aggregate amount of dividends paid (to the
extent not accrued in a prior period) or accrued on Preferred Stock or
Disqualified Capital Stock of the Company and its Restricted Subsidiaries, to
the extent such Preferred Stock or Disqualified Capital Stock is owned by
Persons other than Restricted Subsidiaries, less, to the extent included in any
of clauses (i) through (iv), amortization of capitalized debt issuance costs of
the Company and its Restricted Subsidiaries during such period.
"Consolidated Net Income" means, for any period, the consolidated net
income (or loss) of the Company and its Restricted Subsidiaries for such period
as determined in accordance with GAAP, adjusted by excluding (a) net after-tax
extraordinary gains or losses (less all fees and expenses relating thereto), (b)
net after-tax gains or losses (less all fees and expenses relating thereto)
attributable to Asset Sales, (c) the net income (or net loss) of any Person
(other than the Company or any of its Restricted Subsidiaries), in which the
Company or any of its Restricted Subsidiaries has an ownership interest, except
to the extent of the amount of dividends or other distributions actually paid to
the Company or any of its Restricted Subsidiaries in cash by such other Person
during such period (regardless of whether such cash dividends or distributions
is attributable to net income (or net loss) of such Person during such period or
during any prior period), (d) net income (or net loss) of any Person combined
with the Company or any of its Restricted Subsidiaries on a "pooling of
interests" basis attributable to any period prior to the date of combination,
(e) the net income of any Restricted Subsidiary to the extent that the
declaration or payment of dividends or similar distributions by that Restricted
Subsidiary is not at the date of determination permitted, directly or
indirectly, by operation of the terms of its charter or any agreement,
instrument, judgment, decree, order, statute, rule or governmental regulation
applicable to that Restricted Subsidiary or its stockholders, (f) income
resulting from transfers of assets received by the Company or any Restricted
Subsidiary from an Unrestricted Subsidiary and (g) any write-downs of
non-current assets, provided, however, that any ceiling limitation writedowns
under Commission guidelines shall be treated as capitalized costs, as if such
writedowns had not occurred.
"Consolidated Net Worth" means, at any date, the consolidated stockholders'
equity of the Company less the amount of such stockholders' equity attributable
to Disqualified Capital Stock or treasury stock of the Company and its
Restricted Subsidiaries, as determined in accordance with GAAP.
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"Consolidated Non-cash Charges" means, for any period, the aggregate
depreciation, depletion, amortization and other non-cash expenses of the Company
and its Restricted Subsidiaries reducing Consolidated Net Income for such
period, determined on a consolidated basis in accordance with GAAP (excluding
any such non-cash charge for which an accrual of or reserve for cash charges for
any future period is required).
"Default" means any event, act or condition that is, or after notice or
passage of time or both would become, an Event of Default.
"Designated Senior Indebtedness" means (i) any Senior Indebtedness under or
in respect of any of the Bank Credit Facilities and the Senior Notes and (ii)
any other Senior Indebtedness permitted under the Indenture the principal amount
of which is $5 million or more and, in the case of this clause (ii), that has
been designated by the Company in an Officers' Certificate delivered to the
Trustee as "Designated Senior Indebtedness."
"Disinterested Director" means, with respect to any transaction or series
of transactions in respect of which the Board of Directors of the Company is
required to deliver a resolution of the Board of Directors under the Indenture,
a member of the Board of Directors of the Company who does not have any material
direct or indirect financial interest (other than an interest arising solely
from the beneficial ownership of Capital Stock of the Company) in or with
respect to such transaction or series of transactions.
"Disqualified Capital Stock" means any Capital Stock that, either by its
terms, by the terms of any security into which it is convertible or exchangeable
or by contract or otherwise, is, or upon the happening of an event or passage of
time would be, required to be redeemed or repurchased prior to the final Stated
Maturity of the Notes or is redeemable at the option of the holder thereof at
any time prior to such final Stated Maturity, or is convertible into or
exchangeable for debt securities at any time prior to such final Stated
Maturity. For purposes of the covenant described under "-- Certain
Covenants -- Limitation on Indebtedness and Disqualified Capital Stock"
covenant, Disqualified Capital Stock shall be valued at the greater of its
voluntary or involuntary maximum fixed redemption or repurchase price plus
accrued and unpaid dividends. For such purposes, the "maximum fixed redemption
or repurchase price" of any Disqualified Capital Stock which does not have a
fixed redemption or repurchase price shall be calculated in accordance with the
terms of such Disqualified Capital Stock as if such Disqualified Capital Stock
were redeemed or repurchased on the date of determination, and if such price is
based upon, or measured by, the fair market value of such Disqualified Capital
Stock, such fair market value shall be determined in good faith by the board of
directors of the issuer of such Disqualified Capital Stock; provided, however,
that if such Disqualified Capital Stock is not at the date of determination
permitted or required to be redeemed or repurchased, the "maximum fixed
redemption or repurchase price" shall be the book value of such Disqualified
Capital Stock.
"Dollar-Denominated Production Payments" means production payment
obligations of the Company or a Restricted Subsidiary recorded as liabilities in
accordance with GAAP, together with all undertakings and obligations in
connection therewith.
"Event of Default" has the meaning set forth above under the caption
"Events of Default."
"GAAP" means generally accepted accounting principles, consistently
applied, that are set forth in the opinions and pronouncements of the Accounting
Principles Board of the American Institute of Certified Public Accountants and
statements and pronouncements of the Financial Accounting Standards Board or in
such other statements by such other entity as may be approved by a significant
segment of the accounting profession of the United States of America, which are
applicable as of the date of the Indenture.
The term "guarantee" means, as applied to any obligation, (i) a guarantee
(other than by endorsement of negotiable instruments for collection in the
ordinary course of business), direct or indirect, in any manner, of any part or
all of such obligation and (ii) an agreement, direct or indirect, contingent or
otherwise, the practical effect of which is to assure in any way the payment or
performance (or payment of damages in the event of non-performance) of all or
any part of such obligation, including, without limiting the foregoing, the
payment of amounts drawn down under letters of credit. When used as a verb,
"guarantee" has a corresponding meaning.
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"Holder" means a Person in whose name a Note is registered in the Note
Register.
"Indebtedness" means, with respect to any Person, without duplication, (a)
all liabilities of such Person, contingent or otherwise, for borrowed money or
for the deferred purchase price of property or services (excluding any trade
accounts payable and other accrued current liabilities incurred in the ordinary
course of business) and all liabilities of such Person incurred in connection
with any agreement to purchase, redeem, exchange, convert or otherwise acquire
for value any Capital Stock of such Person, or any warrants, rights or options
to acquire such Capital Stock, outstanding on the date of the Indenture or
thereafter, if, and to the extent, any of the foregoing would appear as a
liability upon a balance sheet of such Person prepared in accordance with GAAP,
(b) all obligations of such Person evidenced by bonds, notes, debentures or
other similar instruments, if, and to the extent, any of the foregoing would
appear as a liability upon a balance sheet of such Person prepared in accordance
with GAAP, (c) all indebtedness of such Person created or arising under any
conditional sale or other title retention agreement with respect to property
acquired by such Person (even if the rights and remedies of the seller or lender
under such agreement in the event of default are limited to repossession or sale
of such property), but excluding trade accounts payable arising in the ordinary
course of business, (d) all Capitalized Lease Obligations of such Person, (e)
all Indebtedness referred to in the preceding clauses of other Persons and all
dividends of other Persons, the payment of which is secured by (or for which the
holder of such Indebtedness has an existing right, contingent or otherwise, to
be secured by) any Lien upon property (including, without limitation, accounts
and contract rights) owned by such Person, even though such Person has not
assumed or become liable for the payment of such Indebtedness (the amount of
such obligation being deemed to be the lesser of the value of such property or
the amount of the obligation so secured), (f) all guarantees by such Person of
Indebtedness referred to in this definition (including, with respect to any
Production Payment, any warranties or guaranties of production or payment by
such Person with respect to such Production Payment but excluding other
contractual obligations of such Person with respect to such Production Payment)
and (g) all obligations of such Person under or in respect of currency exchange
contracts, oil and natural gas price hedging arrangements and Interest Rate
Protection Obligations. Subject to clause (f) of the first sentence of this
definition, neither Dollar-Denominated Production Payments nor Volumetric
Production Payments shall be deemed to be Indebtedness. In addition,
Disqualified Capital Stock shall not be deemed to be Indebtedness.
"Interest Rate Protection Obligations" means the obligations of any Person
pursuant to any arrangement with any other Person whereby, directly or
indirectly, such Person is entitled to receive from time to time periodic
payments calculated by applying either a floating or a fixed rate of interest on
a stated notional amount in exchange for periodic payments made by such Person
calculated by applying a fixed or a floating rate of interest on the same
notional amount and shall include, without limitation, interest rate swaps,
caps, floors, collars and similar agreements or arrangements designed to protect
against or manage such Person's and any of its Subsidiaries exposure to
fluctuations in interest rates.
"Investment" means, with respect to any Person, any direct or indirect
advance, loan, guarantee of Indebtedness or other extension of credit or capital
contribution to (by means of any transfer of cash or other property or assets to
others or any payment for property, assets or services for the account or use of
others), or any purchase or acquisition by such Person of any Capital Stock,
bonds, notes, debentures or other securities (including derivatives) or
evidences of Indebtedness issued by, any other Person. In addition, the fair
market value of the net assets of any Restricted Subsidiary at the time that
such Restricted Subsidiary is designated an Unrestricted Subsidiary shall be
deemed to be an "Investment" made by the Company in such Unrestricted Subsidiary
at such time. "Investments" shall exclude (a) extensions of trade credit or
other advances to customers on commercially reasonable terms in accordance with
normal trade practices or otherwise in the ordinary course of business, (b)
Interest Rate Protection Obligations entered into in the ordinary course of
business or as required by any Permitted Indebtedness or any Indebtedness
incurred in compliance with the "Limitation on Indebtedness and Disqualified
Capital Stock" covenant, but only to the extent that the notional amounts of
such Interest Rate Protection Obligations do not exceed 105% of the aggregate
principal amount of such Indebtedness to which such Interest Rate Protection
Obligations relate and (c) endorsements of negotiable instruments and documents
in the ordinary course of business.
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"Lien" means any mortgage, charge, pledge, lien (statutory or other),
security interest, hypothecation, assignment for security, claim or similar type
of encumbrance (including, without limitation, any agreement to give or grant
any lease, conditional sale or other title retention agreement having
substantially the same economic effect as any of the foregoing) upon or with
respect to any property of any kind. A Person shall be deemed to own subject to
a Lien any property which such Person has acquired or holds subject to the
interest of a vendor or lessor under any conditional sale agreement, capital
lease or other title retention agreement.
"Maturity" means, with respect to any Note, the date on which any principal
of such Note becomes due and payable as therein or in the Indenture provided,
whether at the Stated Maturity with respect to such principal or by declaration
of acceleration, call for redemption or purchase or otherwise.
"Moody's" means Moody's Investors Service, Inc. and its successors.
"Net Available Proceeds" means, with respect to any Asset Sale, the
proceeds thereof in the form of cash or Cash Equivalents including payments in
respect of deferred payment obligations when received in the form of cash or
Cash Equivalents (except to the extent that such obligations are financed or
sold with recourse to the Company or any Restricted Subsidiary), net of (i)
brokerage commissions and other fees and expenses (including fees and expenses
of legal counsel, accountants and investment banks) related to such Asset Sale,
(ii) provisions for all taxes payable as a result of such Asset Sale, (iii)
amounts required to be paid to any Person (other than the Company or any
Restricted Subsidiary) owning a beneficial interest in the assets subject to the
Asset Sale or having a Lien thereon and (iv) appropriate amounts to be provided
by the Company or any Restricted Subsidiary, as the case may be, as a reserve
required in accordance with GAAP consistently applied against any liabilities
associated with such Asset Sale and retained by the Company or any Restricted
Subsidiary, as the case may be, after such Asset Sale, including, without
limitation, pension and other post-employment benefit liabilities, liabilities
related to environmental matters and liabilities under any indemnification
obligations associated with such Asset Sale, all as reflected in an Officers
Certificate delivered to the Trustee; provided, however, that any amounts
remaining after adjustments, revaluations or liquidations of such reserves shall
constitute Net Available Proceeds.
"Net Cash Proceeds," with respect to any issuance or sale of Qualified
Capital Stock or other securities, means the cash proceeds of such issuance or
sale net of attorneys' fees, accountants' fees, underwriters' or placement
agents' fees, discounts or commissions and brokerage, consultant and other fees
and expenses actually incurred in connection with such issuance or sale and net
of taxes paid or payable as a result thereof.
"Non-Recourse Indebtedness" means Indebtedness or that portion of
Indebtedness of the Company or any Restricted Subsidiary incurred in connection
with the acquisition by the Company or such Restricted Subsidiary of any
property or assets and as to which (a) the holders of such Indebtedness agree
that they will look solely to the property or assets so acquired and securing
such Indebtedness for payment on or in respect of such Indebtedness, and neither
the Company nor any Subsidiary (other than an Unrestricted Subsidiary) (i)
provides credit support, including any undertaking, agreement or instrument
which would constitute Indebtedness or (ii) is directly or indirectly liable for
such Indebtedness, and (b) no default with respect to such Indebtedness would
permit (after notice or passage of time or both), according to the terms
thereof, any holder of any Indebtedness of the Company or a Restricted
Subsidiary to declare a default on such Indebtedness or cause the payment
thereof to be accelerated or payable prior to its Stated Maturity.
"Note Register" means the register maintained by or for the Company in
which the Company shall provide for the registration of the Notes and the
transfer of the Notes.
"Oil and Gas Business" means (i) the acquisition, exploration, development,
operation and disposition of interests in oil, gas and other hydrocarbon
properties, (ii) the gathering, marketing, treating, processing, storage,
refining, selling and transporting of any production from such interests or
properties, (iii) any business relating to or arising from exploration for or
development, production, treatment, processing, storage, refining,
transportation or marketing of oil, gas and other minerals and products produced
in association therewith, and (iv) any activity necessary, appropriate or
incidental to the activities described in the foregoing clauses (i) through
(iii) of this definition.
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"Pari Passu Indebtedness" means (i) Indebtedness of the Company that ranks
pari passu in right of payment to the Notes and (ii) Indebtedness of any
Restricted Subsidiary that ranks pari passu in right of payment to the
Subsidiary Guarantees.
"Permitted Indebtedness" means any of the following:
(i) Indebtedness under the Bank Credit Facilities in an aggregate principal
amount at any one time outstanding not to exceed the greater of $165 million or
the borrowing base thereunder (the "Maximum Credit Amount"), plus all interest
and fees under such facilities and any guarantee of any such Indebtedness;
(ii) Indebtedness under the Offered Notes;
(iii) Indebtedness outstanding or in effect on the date of the Indenture
(and not repaid or defeased with the proceeds of the offering of the Notes);
(iv) obligations pursuant to Interest Rate Protection Obligations, but only
to the extent such obligations do not exceed 105% of the aggregate principal
amount of the Indebtedness covered by such Interest Rate Protection Obligations;
obligations under currency exchange contracts entered into in the ordinary
course of business; hedging arrangements entered into in the ordinary course of
business for the purpose of protecting production, purchases and resales against
fluctuations in oil or natural gas prices; and any guarantee of any of the
foregoing;
(v) the Subsidiary Guarantees of the Notes (and any assumption of the
obligations guaranteed thereby);
(vi) Indebtedness of the Company to any Restricted Subsidiary and
Indebtedness of any Restricted Subsidiary to the Company or any other Restricted
Subsidiary;
(vii) Permitted Refinancing Indebtedness and any guarantee thereof;
(viii) Non-Recourse Indebtedness;
(ix) Indebtedness in respect of bid, performance or surety bonds issued for
the account of the Company or any Restricted Subsidiary in the ordinary course
of business, including guaranties and letters of credit supporting such bid,
performance or surety obligations (in each case other than for an obligation for
money borrowed); and
(x) any additional Indebtedness in an aggregate principal amount not in
excess of $25 million at any one time outstanding and any guarantee thereof.
"Permitted Investments" means any of the following: (i) Investments in Cash
Equivalents; (ii) Investments in the Company or any of its Restricted
Subsidiaries; (iii) Investments in an amount not to exceed $10 million at any
one time outstanding; (iv) Investments by the Company or any of its Restricted
Subsidiaries in another Person, if as a result of such Investment (A) such other
Person becomes a Restricted Subsidiary or (B) such other Person is merged or
consolidated with or into, or transfers or conveys all or substantially all of
its properties and assets to, the Company or a Restricted Subsidiary; (v) entry
into operating agreements, joint ventures, partnership agreements, working
interests, royalty interests, mineral leases, processing agreements, farm-out
agreements, contracts for the sale, transportation or exchange of oil and
natural gas, unitization agreements, pooling arrangements, area of mutual
interest agreements or other similar or customary agreements, transactions,
properties, interests or arrangements, and Investments and expenditures in
connection therewith or pursuant thereto, in each case made or entered into in
the ordinary course of the Oil and Gas Business, excluding, however, Investments
in corporations; (vi) entry into any hedging arrangements in the ordinary course
of business for the purpose of protecting the Company's or any Restricted
Subsidiary's production, purchases and resales against fluctuations in oil or
natural gas prices; (vii) Investments permitted under the "Limitation on Asset
Sales" covenant or the "Limitation on Transactions with Affiliates" covenant;
(viii) entry into any currency exchange contract in the ordinary course of
business; or (ix) Investments in stock, obligations or securities received in
settlement of debts owing to the Company or any Restricted Subsidiary as a
result of bankruptcy or insolvency proceedings or upon the foreclosure,
perfection or enforcement of any Lien in favor of the Company or any Restricted
Subsidiary, in
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each case as to debt owing to the Company or any Restricted Subsidiary that
arose in the ordinary course of business of the Company or any such Restricted
Subsidiary.
"Permitted Liens" means the following types of Liens:
(a) Liens existing as of the date of the Indenture (except to the extent
such Liens secure Indebtedness that is repaid or defeased with proceeds of the
offering of the Notes);
(b) Liens securing the Notes or the Subsidiary Guarantees;
(c) Liens in favor of the Company or any Restricted Subsidiary;
(d) Liens securing Senior Indebtedness that is permitted by the terms of
the Indenture;
(e) Liens for taxes, assessments and governmental charges or claims either
(i) not delinquent or (ii) contested in good faith by appropriate proceedings
and as to which the Company or its Restricted Subsidiaries shall have set aside
on its books such reserves as may be required pursuant to GAAP;
(f) statutory Liens of landlords and Liens of carriers, warehousemen,
mechanics, suppliers, materialmen, repairmen and other Liens imposed by law
incurred in the ordinary course of business for sums not delinquent or being
contested in good faith, if such reserve or other appropriate provision, if any,
as shall be required by GAAP shall have been made in respect thereof;
(g) Liens incurred or deposits made in the ordinary course of business in
connection with workers' compensation, unemployment insurance and other types of
social security, or to secure the payment or performance of tenders, statutory
or regulatory obligations, surety and appeal bonds, bids, government contracts
and leases, performance and return of money bonds and other similar obligations
(exclusive of obligations for the payment of borrowed money but including lessee
or operator obligations under statutes, governmental regulations or instruments
related to the ownership, exploration and production of oil, gas and minerals on
state, Federal or foreign lands or waters);
(h) judgment and attachment Liens not giving rise to an Event of Default so
long as any appropriate legal proceedings which may have been duly initiated for
the review of such judgment shall not have been finally terminated or the period
within which such proceeding may be initiated shall not have expired;
(i) easements, rights-of-way, restrictions and other similar charges or
encumbrances not interfering in any material respect with the ordinary conduct
of the business of the Company or any of its Restricted Subsidiaries;
(j) any interest or title of a lessor under any Capitalized Lease
Obligation or operating lease;
(k) purchase money Liens; provided, however, that (i) the related purchase
money Indebtedness shall not be secured by any property or assets of the Company
or any Restricted Subsidiary other than the property or assets so acquired
(including, without limitation, those acquired indirectly through the
acquisition of stock or other ownership interests) and any proceeds therefrom
and (ii) the Lien securing such Indebtedness shall be created within 90 days of
such acquisition;
(l) Liens securing obligations under hedging agreements that the Company or
any Restricted Subsidiary enters into in the ordinary course of business for the
purpose of protecting its production, purchases and resales against fluctuations
in oil or natural gas prices;
(m) Liens upon specific items of inventory or other goods of any Person
securing such Person's obligations in respect of bankers acceptances issued or
created for the account of such Person to facilitate the purchase, shipment or
storage of such inventory or other goods;
(n) Liens securing reimbursement obligations with respect to commercial
letters of credit which encumber documents and other property or assets relating
to such letters of credit and products and proceeds thereof;
(o) Liens encumbering property or assets under construction arising from
progress or partial payments by a customer of the Company or its Restricted
Subsidiaries relating to such property or assets;
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(p) Liens encumbering deposits made to secure obligations arising from
statutory, regulatory, contractual or warranty requirements of the Company or
any of its Restricted Subsidiaries, including rights of offset and set-off;
(q) Liens securing Interest Rate Protection Obligations which Interest Rate
Protection Obligations relate to Indebtedness that is secured by Liens otherwise
permitted under the Indenture;
(r) Liens on, or related to, properties or assets to secure all or part of
the costs incurred in the ordinary course of business for the exploration,
drilling, development or operation thereof;
(s) Liens on pipeline or pipeline facilities which arise by operation of
law;
(t) Liens arising under operating agreements, joint venture agreements,
partnership agreements, oil and gas leases, farm-out agreements, division
orders, contracts for the sale, transportation or exchange of oil and natural
gas, unitization and pooling declarations and agreements, area of mutual
interest agreements and other agreements which are customary in the Oil and Gas
Business;
(u) Liens reserved in oil and gas mineral leases for bonus or rental
payments or for compliance with the terms of such leases;
(v) Liens constituting survey exceptions, encumbrances, easements, or
reservations of, or rights to others for, rights-of-way, zoning or other
restrictions as to the use of real properties, and minor defects of title which,
in the case of any of the foregoing, were not incurred or created to secure the
payment of borrowed money or the deferred purchase price of property, assets or
services, and in the aggregate do not materially adversely affect the value of
properties and assets of the Company and the Restricted Subsidiaries, taken as a
whole, or materially impair the use of such properties and assets for the
purposes for which such properties and assets are held by the Company or any
Restricted Subsidiaries;
(w) Liens securing Non-Recourse Indebtedness; provided, however, that the
related Non-Recourse Indebtedness shall not be secured by any property or assets
of the Company or any Restricted Subsidiary other than the property and assets
acquired (including, without limitation, those acquired indirectly through the
acquisition of stock or other ownership interests) by the Company or any
Restricted Subsidiary with the proceeds of such Non-Recourse Indebtedness; and
(x) Liens resulting from the deposit of funds or evidences of Indebtedness
in trust for the purpose of defeasing Indebtedness of the Company or any of its
Restricted Subsidiaries.
Notwithstanding anything in clauses (a) through (x) of this definition, the term
"Permitted Liens" does not include any Liens resulting from the creation,
incurrence, issuance, assumption or guarantee of any Production Payments other
than Production Payments that are created, incurred, issued, assumed or
guaranteed in connection with the financing of, and within 30 days after, the
acquisition of the properties or assets that are subject thereto.
"Permitted Refinancing Indebtedness" means Indebtedness of the Company or a
Restricted Subsidiary, the net proceeds of which are used to renew, extend,
refinance, refund or repurchase (including, without limitation, pursuant to a
Change of Control Offer or Net Proceeds Offer) outstanding Indebtedness of the
Company or any Restricted Subsidiary, provided that (a) if the Indebtedness
(including the Notes) being renewed, extended, refinanced, refunded or
repurchased is pari passu with or subordinated in right of payment to either the
Notes or the Subsidiary Guarantees, then such Indebtedness is pari passu with or
subordinated in right of payment to the Notes or the Subsidiary Guarantees, as
the case may be, at least to the same extent as the Indebtedness being renewed,
extended, refinanced, refunded or repurchased, (b) such Indebtedness has a
Stated Maturity for its final scheduled principal payment that is no earlier
than the Stated Maturity for the final scheduled principal payment of the
Indebtedness being renewed, extended, refinanced, refunded or repurchased and
(c) such Indebtedness has an Average Life at the time such Indebtedness is
incurred that is equal to or greater than the Average Life of the Indebtedness
being renewed, extended, refinanced, refunded or repurchased; provided, further,
that such Indebtedness is in an aggregate principal amount (or, if such
Indebtedness is issued at a price less than the principal amount thereof, the
aggregate amount of gross
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proceeds therefrom is) not in excess of the aggregate principal amount then
outstanding of the Indebtedness being renewed, extended, refinanced, refunded or
repurchased (or if the Indebtedness being renewed, extended, refinanced,
refunded or repurchased was issued at a price less than the principal amount
thereof, then not in excess of the amount of liability in respect thereof
determined in accordance with GAAP) plus the amount of any premium required to
be paid in connection with such renewal, extension or refinancing, refunding or
repurchase pursuant to the terms of the Indebtedness being renewed, extended,
refinanced, refunded or repurchased or the amount of any premium reasonably
determined by the Company as necessary to accomplish such renewal, extension,
refinancing, refunding or repurchase, plus the amount of reasonable fees and
expenses incurred by the Company or such Restricted Subsidiary in connection
therewith.
"Person" means any individual, corporation, limited liability company,
partnership, joint venture, association, joint stock company, trust,
unincorporated organization or government or any agency or political subdivision
thereof.
"Preferred Stock" means, with respect to any Person, any and all shares,
interests, participations or other equivalents (however designated) of such
Person's preferred or preference stock, whether now outstanding or issued after
the date of the Indenture, including, without limitation, all classes and series
of preferred or preference stock of such Person.
"Production Payments" means, collectively, Dollar-Denominated Production
Payments and Volumetric Production Payments.
"Public Equity Offering" means an offer and sale of Common Stock of the
Company pursuant to a registration statement that has been declared effective by
the Commission pursuant to the Securities Act (other than a registration
statement on Form S-8 or otherwise relating to equity securities issuable under
any employee benefit plan of the Company).
"Qualified Capital Stock" of any Person means any and all Capital Stock of
such Person other than Disqualified Capital Stock.
"Restricted Investment" means (without duplication) (i) the designation of
a Subsidiary as an Unrestricted Subsidiary in the manner described in the
definition of "Unrestricted Subsidiary" and (ii) any Investment other than a
Permitted Investment.
"Restricted Subsidiary" means any Subsidiary of the Company, whether
existing on or after the date of the Indenture, unless such Subsidiary of the
Company is an Unrestricted Subsidiary or is designated as an Unrestricted
Subsidiary pursuant to the terms of the Indenture.
"S&P" means Standard and Poor's Ratings Services, a division of The
McGraw-Hill Companies, Inc., and its successors.
"Senior Indebtedness" means (i) Indebtedness or other obligations under or
in respect of any of the Bank Credit Facilities, (ii) Indebtedness under or in
respect of the Senior Notes, (iii) any other Indebtedness permitted to be
incurred by the Company or any Restricted Subsidiary under the terms of the
Indenture, unless the instrument under which such Indebtedness is incurred
expressly provides that it is on a parity with or subordinated in right of
payment to the Notes or the Subsidiary Guarantees, as the case may be, (iv) all
interest, fees and other obligations in respect of any Indebtedness referred to
in the foregoing clauses (i) through (iii) and (v) any amounts due to the
Trustee under the Indenture as fees, expenses or indemnities and other amounts.
"Stated Maturity" means, when used with respect to any Indebtedness or any
installment of interest thereon, the date specified in the instrument evidencing
or governing such Indebtedness as the fixed date on which the principal of such
Indebtedness or such installment of interest is due and payable.
"Subordinated Indebtedness" means Indebtedness of the Company or a
Subsidiary Guarantor which is expressly subordinated in right of payment to the
Notes or the Subsidiary Guarantees, as the case may be.
"Subsidiary" means, with respect to any Person, (i) a corporation a
majority of whose Voting Stock is at the time, directly or indirectly, owned by
such Person, by one or more Subsidiaries of such Person or by such
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Person and one or more Subsidiaries thereof or (ii) any other Person (other than
a corporation), including, without limitation, a joint venture, in which such
Person, one or more Subsidiaries thereof or such Person and one or more
Subsidiaries thereof, directly or indirectly, at the date of determination
thereof, have at least majority ownership interest entitled to vote in the
election of directors, managers or trustees thereof (or other Person performing
similar functions).
"Subsidiary Guarantee" means any guarantee of the Notes by any Subsidiary
Guarantor in accordance with the provisions described under "-- Subsidiary
Guarantees of Notes.
"Subsidiary Guarantor" means (i) KCS Resources, Inc., (ii) KCS Michigan
Resources, Inc., (iii) KCS Energy Marketing, Inc., (iv) KCS Medallion Resources,
Inc., (v) KCS Energy Services, Inc., (vi) Medallion California Properties Co.,
(vii) Medallion Gas Services, Inc., (viii) National Enerdrill Corporation, (ix)
Proliq, Inc., (x) each of the Company's other Restricted Subsidiaries, if any,
executing a supplemental indenture in which such Subsidiary agrees to be bound
by the terms of the Indenture and (xi) any Person that becomes a successor
guarantor of the Notes in compliance with the provisions described under
"-- Subsidiary Guarantees of Notes.
"Unrestricted Subsidiary" means (i) any Subsidiary of the Company that at
the time of determination will be designated an Unrestricted Subsidiary by the
Board of Directors of the Company as provided below and (ii) any Subsidiary of
an Unrestricted Subsidiary. The Board of Directors of the Company may designate
any Subsidiary of the Company as an Unrestricted Subsidiary so long as (a)
neither the Company nor any Restricted Subsidiary is directly or indirectly
liable pursuant to the terms of any Indebtedness of such Subsidiary; (b) no
default with respect to any Indebtedness of such Subsidiary would permit (upon
notice, lapse of time or otherwise) any holder of any other Indebtedness of the
Company or any Restricted Subsidiary to declare a default on such other
Indebtedness or cause the payment thereof to be accelerated or payable prior to
its Stated Maturity; (c) such designation as an Unrestricted Subsidiary would be
permitted under the "Limitation on Restricted Payments" covenant; and (d) such
designation shall not result in the creation or imposition of any Lien on any of
the properties or assets of the Company or any Restricted Subsidiary (other than
any Permitted Lien or any Lien the creation or imposition of which shall have
been in compliance with the "Limitation on Liens" covenant); provided, however,
that with respect to clause (a), the Company or a Restricted Subsidiary may be
liable for Indebtedness of an Unrestricted Subsidiary if (x) such liability
constituted a Permitted Investment or a Restricted Payment permitted by the
"Limitation on Restricted Payments" covenant, in each case at the time of
incurrence, or (y) the liability would be a Permitted Investment at the time of
designation of such Subsidiary as an Unrestricted Subsidiary. Any such
designation by the Board of Directors of the Company shall be evidenced to the
Trustee by filing a Board Resolution with the Trustee giving effect to such
designation. The Board of Directors of the Company may designate any
Unrestricted Subsidiary as a Restricted Subsidiary if, immediately after giving
effect to such designation on a pro forma basis, (i) no Default or Event of
Default shall have occurred and be continuing, (ii) the Company could incur
$1.00 of additional Indebtedness (not including the incurrence of Permitted
Indebtedness) under the "Limitation on Indebtedness and Disqualified Capital
Stock" covenant and (iii) if any of the properties and assets of the Company or
any of its Restricted Subsidiaries would upon such designation become subject to
any Lien (other than a Permitted Lien), the creation or imposition of such Lien
shall have been in compliance with the "Limitation on Liens" covenant.
"Volumetric Production Payments" means production payment obligations of
the Company or a Restricted Subsidiary recorded as deferred revenue in
accordance with GAAP, together with all undertakings and obligations in
connection therewith.
"Voting Stock" means any class or classes of Capital Stock pursuant to
which the holders thereof have the general voting power under ordinary
circumstances to elect at least a majority of the board of directors, managers
or trustees of any Person (irrespective of whether or not, at the time, stock of
any other class or classes shall have, or might have, voting power by reason of
the happening of any contingency).
FORM, DENOMINATION AND REGISTRATION
The Notes will be issued in fully registered form, without coupons, in
denominations of $1,000 in principal amount and integral multiples thereof.
80
<PAGE> 81
Global Notes; Book-Entry Form
Except as set forth below, the Notes will initially be issued in the form
of one or more registered Notes in global form (the "Global Notes"). Each Global
Note will be deposited on its issue date with, or on behalf of, DTC and
registered in the name of Cede & Co. ("Cede"), as nominee.
The Holders of Notes may hold their interests in the Global Notes directly
through DTC if such Holder is a participant in DTC, or indirectly through
organizations which are participants in DTC (the "Participants"). Transfers
between Participants will be effected in the ordinary way in accordance with DTC
rules and will be settled in same day funds. The laws of some states require
that certain persons take physical delivery of securities in definitive form.
Consequently, the ability to transfer beneficial interests in the Global Notes
to such persons may be limited.
The Holders of Notes who are not Participants may beneficially own
interests in the Global Notes held by DTC only through Participants or certain
banks, brokers, dealers, trust companies and other parties that clear through or
maintain a custodial relationship with a Participant, either directly or
indirectly ("Indirect Participants"). So long as Cede, as the nominee of DTC, is
the registered owner of the Global Notes, Cede for all purposes will be
considered the sole holder of the Global Notes.
Payment of interest on and the redemption price or Change of Control
Purchase Price (upon redemption at the option of the Company or repurchase at
the option of the Holder upon a Change of Control) of the Global Notes will be
made to Cede, the nominee for DTC, as the registered owner of the Global Notes,
by wire transfer of immediately available funds. Neither the Company, the
Trustee nor any Paying Agent will have any responsibility or liability for any
aspect of the records relating to or payments made on account of beneficial
ownership interests in the Global Notes or for maintaining, supervising or
reviewing any records relating to such beneficial ownership interests.
The Company has been informed by DTC that, with respect to any payment of
interest on and the redemption price or Change of Control Purchase Price (upon
redemption at the option of the Company or repurchase at the option of the
Holder upon a Change of Control) of the Global Notes, DTC's practice is to
credit Participants' accounts on the payment date therefor with payments in
amounts proportionate to their respective beneficial interests in the Notes
represented by the Global Notes as shown on the records of DTC, unless DTC has
reason to believe that it will not receive payment on such payment date.
Payments by Participants to owners of beneficial interests in Notes represented
by the Global Notes held through such Participants will be the responsibility of
such Participants, as is now the case with securities held for the accounts of
customers registered in "street name."
Because DTC can only act on behalf of Participants, who in turn act on
behalf of Indirect Participants and certain banks, the ability of a person
having a beneficial interest in Notes represented by the Global Notes to pledge
such interest to persons or entities that do not participate in the DTC system,
or otherwise take actions in respect of such interest, may be affected by the
lack of a physical certificate evidencing such interest.
Neither the Company nor the Trustee (or any registrar or other agent under
the Indenture) will have any responsibility for the performance by DTC or its
Participants or Indirect Participants of their respective obligations under the
rules and procedures governing their operations. DTC has advised the Company
that it will take any action permitted to be taken by a holder of Notes
(including, without limitation, the presentation of Notes for exchange as
described below), only at the direction of one or more Participants to whose
account with DTC interests in the Global Note are credited, and only in respect
of the principal amount of the Notes represented by the Global Note as to which
such Participant or Participants has or have given such direction.
DTC has advised the Company as follows: DTC is a limited purpose trust
company organized under the New York Banking Law, a "banking organization"
within the meaning of the New York Banking Law, a member of the Federal Reserve
System, a "clearing corporation" within the meaning of the New York Uniform
Commercial Code and a "clearing agency" registered pursuant to the provisions of
Section 17A of the Exchange Act. DTC holds securities that its Participants
deposit with DTC. DTC also facilitates the clearance and settlement of
securities transactions between Participants through electronic book-entry
81
<PAGE> 82
changes to the accounts of its Participants, thereby eliminating the need for
physical movement of certificates. Participants include securities brokers and
dealers, banks, trust companies and clearing corporations. Certain of such
Participants (or their representatives), together with other entities, own DTC.
Indirect access to the DTC system is available to others such as banks, brokers,
dealers and trust companies that clear through, or maintain a custodial
relationship with, a Participant, either directly or indirectly.
Although DTC has agreed to the foregoing procedures in order to facilitate
transfers of interests in each Global Note among Participants, it is under no
obligation to perform or continue to perform such procedures, and such
procedures may be discontinued at any time. If DTC is at any time unwilling or
unable to continue as depositary and a successor depositary is not appointed by
the Company within 90 days, or at the Company's election at any time, the
Company will cause the Notes to be issued in definitive form in exchange for the
Global Notes.
Certificated Notes
Holders of Notes may request that certificated Notes be issued in exchange
for Notes represented by the Global Note. In addition, certificated Notes may be
issued in exchange for Notes represented by the Global Note in the circumstances
described in the paragraph immediately prior to this one.
UNDERWRITING
Under the terms and subject to the conditions contained in the Underwriting
Agreement dated the date hereof (the "Underwriting Agreement"), each of the
underwriters named below (the "Underwriters") has severally agreed to purchase
from the Company the principal amount of Notes set forth opposite the name of
such Underwriter below:
<TABLE>
<CAPTION>
PRINCIPAL AMOUNT
UNDERWRITERS OF NOTES
------------ ----------------
<S> <C>
Salomon Brothers Inc........................................ $ 62,500,000
Prudential Securities Incorporated ......................... 25,000,000
CIBC Oppenheimer Corp. ..................................... 12,500,000
Jefferies and Company, Inc. ................................ 12,500,000
Morgan Keegan & Company, Inc. .............................. 12,500,000
------------
Total............................................. $125,000,000
============
</TABLE>
The Underwriting Agreement provides that the obligations of the several
Underwriters to pay for and accept delivery of the Notes offered hereby are
subject to the approval of certain legal matters by counsel and to certain other
conditions. The Underwriters will be obligated to take and pay for all of the
Notes offered hereby if any of such Notes are purchased.
The Underwriters initially propose to offer part of the Notes offered
hereby directly to the public at the public offering price set forth on the
cover page of this Prospectus and part of the Notes offered hereby to certain
dealers at a price which represents a concession not in excess of 0.5% of the
principal amount per Note under the price to public. The Underwriters may allow,
and such dealers may reallow, a concession not in excess of 0.25% of the
principal amount per Note to certain other dealers. After the Offering, the
public offering price and such concessions may be changed by the Underwriters.
In connection with the Offering and in compliance with applicable law, the
Underwriters may engage in transactions which stabilize or maintain the market
price of the Notes at levels above those which might otherwise prevail in the
open market. For the purposes of covering a syndicate short position or
stabilizing the price of the Notes, the Underwriters may place bids for the
Notes or effect purchases of the Notes in the open market. Finally, the
Underwriters may impose a penalty bid on certain Underwriters and dealers. This
means that the underwriting syndicate may reclaim selling concessions allowed to
an Underwriter or a dealer for distributing the Notes in the Offering if the
syndicate repurchases previously distributed Notes in transactions
82
<PAGE> 83
to cover syndicate short positions, in stabilization transactions or otherwise.
The Underwriters are not required to engage in any of these activities and any
such activities, if commenced, may be discontinued at any time.
The Company and the Underwriters have agreed to indemnify each other
against certain liabilities, including liabilities under the Securities Act.
The Notes have been approved for listing on the NYSE, subject to official
notice of issuance. The Company has been advised by the Underwriters that they
currently intend to make a market in the Notes. However, the Underwriters are
not obligated to do so, and any market making may be discontinued at any time
without any notice. There can be no assurance as to whether an active trading
market for the Notes will develop.
Canadian Imperial Bank of Commerce ("CIBC"), a lender to the Company under
the Bank Credit Facilities, will receive its proportionate share of any
repayment by the Company of amounts outstanding under the Bank Credit Facilities
from the proceeds of the Offering. See "Use of Proceeds" and "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- Debt Financing." CIBC is an
affiliate of CIBC Oppenheimer Corp., a member of the National Association of
Securities Dealers, Inc. ("NASD"), who is participating in the distribution of
the Offering. The Offering is therefore being conducted in accordance with Rule
2710(c)(8) of the NASD's Conduct Rules, and the price at which the Notes will be
distributed to the public will be established pursuant to Rule 2720(c)(3) of the
Conduct Rules. Salomon Brothers Inc is acting as a "qualified independent
underwriter" within the meaning of such rules and is assuming the
responsibilities of acting as such in pricing the Offering and conducting due
diligence. Salomon Brothers Inc will receive no separate fee for its services as
qualified independent underwriter.
Certain of the Underwriters acted as representatives of the underwriters
for the Company's public offering of Common Stock in January 1997 for which they
received customary fees.
CERTAIN LEGAL MATTERS
The validity of the Notes 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 the Notes will be passed upon for the
Underwriters by Vinson & Elkins L.L.P., Houston, Texas.
EXPERTS
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.
Information set forth in this Prospectus relating to the Company's
estimated proved oil and gas reserves at December 31, 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, H.J. Gruy and Associates, Inc., R.A. Lenser and
Associates, Inc. and Netherland, Sewell and Associates, Inc. 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.
83
<PAGE> 84
AVAILABLE INFORMATION
The Company is subject to the information requirements of the Securities
Exchange Act of 1934, as amended (the "Exchange Act"), and, in accordance
therewith, files reports, proxy statements and other information with the
Securities and Exchange Commission (the "SEC" or "Commission"). The reports,
proxy statements and other information may be inspected and copied at the
offices of the Commission as stated above or at its regional offices located in
The Citicorp Center, Suite 1400, 500 West Madison Street, Chicago, Illinois
60661 and Seven World Trade Center, Suite 1300, New York, New York 10048. Copies
of such material also can be obtained from the Public Reference Section of the
Commission, 450 Fifth Street, N.W., Washington, D.C. 20549, at prescribed rates.
In addition, the Commission maintains a web site that contains reports, proxy
and information statements and other information regarding issuers that file
electronically with the Commission at ,http://www.sec.gov.. The Notes have been
approved for listing (subject to official notice of issuance) on, and the Common
Stock, par value $.01 per share, of the Company is traded on, the New York Stock
Exchange, and as a result the reports, proxy statements and other information
concerning the Company may be inspected at the offices of the New York Stock
Exchange, 20 Broad Street, New York, New York 10005.
The Company has filed a Registration Statement on Form S-3, including
amendments thereto, relating to the Notes offered hereby (the "Registration
Statement") with the Commission. This Prospectus does not contain all of the
information set forth in the Registration Statement and the exhibits and
schedules thereto, certain parts of which are omitted in accordance with rules
and regulations of the Commission. Statements contained in this Prospectus as to
the contents of any contract or other document referred to are not necessarily
complete, and in each instance reference is made to the copy of such contract or
other document filed as an exhibit to the Registration Statement or as
previously filed with the Commission and incorporated herein by reference. For
further information with respect to the Company and the Notes offered hereby,
reference is made to such Registration Statement, exhibits and schedules. A copy
of the Registration Statement may be inspected by anyone without charge at the
Commission's principal office at 450 Fifth Street, N.W., Washington, D.C. 20549,
and copies of all or any part thereof may be obtained from the Commission upon
payment of certain fees prescribed by the Commission.
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
The Company's (i) Annual Report on Form 10-K for the year ended December
31, 1996, (ii) Quarterly Report on Form 10-Q for the three months ended March
31, 1997, (iii) Quarterly Report on Form 10-Q for the three months ended June
30, 1997 and (iv) Quarterly Report on Form 10-Q for the three months ended
September 30, 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 Notes 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: (732) 632-1770).
84
<PAGE> 85
GLOSSARY
The following are abbreviations and definitions of oil and gas terms used
throughout this Prospectus.
Amine. An aqueous organic chemical compound that has the ability to absorb
acid gases (i.e. CO(2) and H(2)S) entrained in a natural gas stream that may
then be regenerated by heating to expel these gases.
bbl. Barrel of 42 U.S. gallons of crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet.
Bcfe. Billion cubic 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.
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, less changes in unevaluated costs, 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.
Net Acquisition Cost. An amount per Mcfe equal to the total purchase price
allocated to oil and gas properties divided by the estimated proved reserves
acquired.
Net acres or net wells. The sum of the fractional working interests net to
the Company owned in gross acres or gross wells.
85
<PAGE> 86
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 additions to reserves
from acquisitions, extensions, discoveries and revisions of previous estimates
in a year by total production in that year.
Sour gas. A natural gas stream containing more than 1/4 grain of hydrogen
sulfide per 100 cubic feet of natural gas. 1/4 grain = 0.0003975% or 3.975 ppm
(parts per million).
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.
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.
86
<PAGE> 87
INDEX TO CONSOLIDATED 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, 1994, 1995 and 1996 and for the nine
months ended September 30, 1996 and 1997 (unaudited)... F-3
Consolidated Balance Sheets at December 31, 1995 and 1996
and September 30, 1997 (unaudited)..................... F-4
Statements of Consolidated Stockholders' Equity for the
years ended December 31, 1994, 1995 and 1996 and for
the nine months ended September 30, 1997 (unaudited)... F-5
Statements of Consolidated Cash Flows for the years ended
December 31, 1994, 1995 and 1996 and for the nine
months ended September 30, 1996 and 1997 (unaudited)... F-6
Notes to Consolidated Financial Statements................ F-7
</TABLE>
F-1
<PAGE> 88
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, 1996 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, 1996. 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, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1996 in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
New York, New York
February 26, 1997
F-2
<PAGE> 89
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,
--------------------------------------- -------------------------
1994 1995 1996 1996 1997
----------- ----------- ----------- ----------- -----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenue:
Oil and gas revenue........... $ 66,215 $ 86,629 $ 108,015 $ 79,051 $ 100,396
Other revenue, net............ 1,185 486 359 377 3,702
----------- ----------- ----------- ----------- -----------
Total................. 67,400 87,115 108,374 79,428 104,098
Operating costs and expenses:
Leasing operating expenses.... 6,218 6,156 9,167 6,582 20,470
Production taxes.............. 845 467 2,526 1,671 4,354
General and administrative
expenses................... 4,853 4,704 7,825 5,411 7,302
Depreciation, depletion and
amortization............... 18,783 38,231 45,460 33,128 42,486
----------- ----------- ----------- ----------- -----------
Total................. 30,699 49,558 64,978 46,792 74,612
----------- ----------- ----------- ----------- -----------
Operating income................ 36,701 37,557 43,396 32,636 29,486
Interest and other income,
net........................... 1,175 4,472 5,086 4,820 388
Interest expense................ (2,004) (6,807) (14,085) (11,193) (15,146)
----------- ----------- ----------- ----------- -----------
Income from continuing
operations before income
taxes......................... 35,872 35,222 34,397 26,263 14,728
Federal and state income
taxes......................... 12,269 11,817 12,680 9,483 5,452
----------- ----------- ----------- ----------- -----------
Income from continuing
operations.................... 23,603 23,405 21,717 16,780 9,276
Discontinued operations:
Net income (loss) from
operations................. 554 (2,099) (1,845) (1,974) (72)
Net gain on disposition....... -- -- -- -- 5,461
----------- ----------- ----------- ----------- -----------
Net income...................... $ 24,157 $ 21,306 $ 19,872 $ 14,806 $ 14,665
=========== =========== =========== =========== ===========
Earnings per share:
Continuing operations......... $ 1.00 $ 1.00 $ 0.91 $ 0.70 $ 0.32
Discontinued operations....... 0.02 (0.09) (0.08) (0.08) 0.18
----------- ----------- ----------- ----------- -----------
Total................. $ 1.02 $ 0.91 $ 0.83 $ 0.62 $ 0.50
=========== =========== =========== =========== ===========
Average shares of common stock
and common stock equivalents
outstanding................... 23,609,978 23,521,402 23,810,872 23,772,868 29,449,391
=========== =========== =========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-3
<PAGE> 90
KCS ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------- SEPTEMBER 30,
1995 1996 1997
-------- -------- -------------
(UNAUDITED)
<S> <C> <C> <C>
Current assets
Cash and cash equivalents............................... $ 5,846 $ 5,100 $ 3,858
Trade accounts receivable............................... 13,248 30,307 33,720
Receivable from Tennessee Gas........................... 56,437 -- --
Net assets of discontinued operations................... 14,980 26,658 5,110
Other current assets.................................... 1,798 8,392 7,925
-------- -------- --------
Current assets....................................... 92,309 70,457 50,613
-------- -------- --------
Property, plant and equipment
Oil and gas properties, full cost method, less
accumulated DD&A -- 1995, $86,936; 1996, $131,521 and
September 30, 1997, $172,469......................... 204,958 415,870 540,896
Other property, plant and equipment, at cost less
accumulated depreciation -- 1995, $1,485; 1996,
$2,887 and September 30, 1997, $4,472................ 5,370 14,483 14,510
-------- -------- --------
Property, plant and equipment, net................... 210,328 430,353 555,406
-------- -------- --------
Investments and other assets.............................. 3,927 11,010 8,024
-------- -------- --------
$306,564 $511,820 $614,043
======== ======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable........................................ $ 6,869 $ 24,144 $ 32,953
Accrued liabilities..................................... 3,487 15,558 9,953
-------- -------- --------
Current liabilities.................................. 10,356 39,702 42,906
-------- -------- --------
Deferred credits and other liabilities
Deferred federal and state income taxes................. 26,172 34,097 41,884
Other................................................... 2,931 2,052 1,540
-------- -------- --------
Deferred credits and other liabilities............... 29,103 36,149 43,424
-------- -------- --------
Long-term debt............................................ 165,529 310,347 275,723
-------- -------- --------
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 24,759,770 and 24,976,340
at December 31, 1995 and 1996, respectively and
31,198,390 shares issued at September 30, 1997....... 248 249 312
Additional paid-in capital.............................. 24,786 30,463 143,718
Retained earnings....................................... 79,814 98,298 111,348
Less treasury stock, 1,785,496 and 1,801,496 shares, at
December 31, 1995 and 1996, respectively, and
1,801,496 shares at September 30, 1997,
respectively -- at cost.............................. (3,272) (3,388) (3,388)
-------- -------- --------
Total stockholders' equity...................... 101,576 125,622 251,990
-------- -------- --------
$306,564 $511,820 $614,043
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-4
<PAGE> 91
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, 1993............. $246 $ 23,163 $ 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 ($0.045 per share)........... -- -- (1,033) -- (1,033)
Purchase of treasury stock............. -- -- -- (1,909) (1,909)
---- -------- -------- ------- --------
Balance at December 31, 1994............. 246 23,772 59,885 (3,235) 80,668
Stock issuances -- option and benefit
plans............................... 2 187 -- -- 189
Tax benefit on stock option
exercises........................... -- 201 -- -- 201
Stock warrants issued.................. -- 626 -- -- 626
Net income............................. -- -- 21,306 -- 21,306
Dividends ($0.06 per share)............ -- -- (1,377) -- (1,377)
Purchase of treasury stock............. -- -- -- (37) (37)
---- -------- -------- ------- --------
Balance at December 31, 1995............. 248 24,786 79,814 (3,272) 101,576
Stock issuances -- option and benefit
plans............................... 1 682 -- -- 683
Tax benefit on stock option
exercises........................... -- 665 -- -- 665
Stock warrants issued.................. -- 4,998 -- -- 4,998
Repurchase of stock warrants........... -- (668) -- -- (668)
Net income............................. -- -- 19,872 -- 19,872
Dividends ($0.06 per share)............ -- -- (1,388) -- (1,388)
Purchase of treasury stock............. -- -- -- (116) (116)
---- -------- -------- ------- --------
Balance at December 31, 1996............. 249 30,463 98,298 (3,388) 125,622
Stock issuance -- public offering...... 60 110,572 -- -- 110,632
Stock issuances -- option and benefit
plans............................... 3 1,757 -- -- 1,760
Tax benefit on stock option
exercises........................... -- 926 -- -- 926
Net income............................. -- -- 14,665 -- 14,665
Dividends ($0.05 per share)............ -- -- (1,615) -- (1,615)
---- -------- -------- ------- --------
Balance at September 30, 1997
(unaudited)............................ $312 $143,718 $111,348 $(3,388) $251,990
==== ======== ======== ======= ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-5
<PAGE> 92
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
FOR THE NINE MONTHS ENDED
FOR THE YEARS ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------------- -------------------------
1994 1995 1996 1996 1997
-------- --------- --------- ----------- -----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Cash flows from operating activities:
Net income.................................. $ 24,157 $ 21,306 $ 19,872 $ 14,806 $ 14,665
Non-cash charges (credits):
Depreciation, depletion and
amortization........................... 19,740 39,209 46,611 33,933 42,486
Deferred income taxes.................... 10,896 9,756 7,925 4,195 4,581
Gain on sale of discontinued
operations............................. -- -- -- -- (5,461)
Other non-cash charges and credits,
net.................................... (65) 820 1,440 1,248 1,320
-------- --------- --------- --------- ---------
54,728 71,091 75,848 54,182 57,591
Net changes in assets and liabilities:
Trade accounts receivable................ 19,107 (11,672) (33,887) 18,906 58,054
Receivable from Tennessee Gas............ (13,569) (42,868) 56,437 56,437 --
Fuel inventories......................... (1,126) 1,727 (238) (102) (398)
Other current assets..................... (1,299) 490 (6,822) (1,681) (511)
Accounts payable and accrued
liabilities............................ (10,724) 14,163 34,732 (22,689) (54,579)
Federal and state income taxes........... (119) 178 (2,572) (1,419) 800
Other, net............................... 3,118 (2,999) (2,150) 1,493 938
-------- --------- --------- --------- ---------
Net cash provided by operating activities..... 50,116 30,110 121,348 105,127 61,895
-------- --------- --------- --------- ---------
Cash flows from investing activities:
Investment in oil and gas properties(1)..... (73,682) (121,265) (267,133) (50,552) (169,773)
Proceeds from the sale of oil and gas
properties............................... -- 4,069 16,634 16,384 3,800
Investment in natural gas transportation
systems.................................. (700) (5,969) (6,059) (843) (171)
Proceeds from the sale of pipeline assets... -- -- -- -- 27,907
Investment in other property, plant and
equipment, net........................... (571) (1,465) (4,026) (1,340) (1,940)
-------- --------- --------- --------- ---------
Net cash used in investing activities......... (74,953) (124,630) (260,584) (36,351) (140,177)
-------- --------- --------- --------- ---------
Cash flows from financing activities:
Proceeds from long-term debt................ 49,431 141,298 325,636 165,145 117,300
Repayments of long-term debt................ (26,247) (38,774) (180,900) (180,900) (151,991)
Issuance of common stock.................... 380 189 683 521 112,492
Issuance of stock warrants.................. -- 626 -- -- --
Repurchase of stock warrants................ -- -- (668) -- --
Tax benefit on stock option exercises....... 229 201 665 567 926
Purchase of treasury stock.................. (1,909) (37) (116) (116) --
Dividends paid.............................. (919) (1,377) (1,388) (1,042) (1,374)
Deferred financing costs and other, net..... (509) (2,748) (5,422) (5,200) (313)
-------- --------- --------- --------- ---------
Net cash provided by (used in) financing
activities.................................. 20,456 99,378 138,490 (21,025) 77,040
-------- --------- --------- --------- ---------
Increase (decrease) in cash and cash
equivalents................................. (4,381) 4,858 (746) 47,751 (1,242)
Cash and cash equivalents at beginning of
year........................................ 5,369 988 5,846 5,846 5,100
-------- --------- --------- --------- ---------
Cash and cash equivalents at end of year...... $ 988 $ 5,846 $ 5,100 $ 53,597 $ 3,858
======== ========= ========= ========= =========
</TABLE>
- ---------------
(1) The amount included in the year ended December 31, 1996 does not include
$4,998 (non-cash) related to stock warrants issued in connection with the
1996 Medallion Acquisition.
The accompanying notes are an integral part of these financial statements.
F-6
<PAGE> 93
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
KCS Energy, Inc. is an independent energy company engaged in the
acquisition, exploration, development and production of natural gas and crude
oil.
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.
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. Changes in the market value of these
transactions are deferred until the gain or loss on the underlying item is
recognized. See Note 8 for further discussion of the Company's price risk
management activities.
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.
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
F-7
<PAGE> 94
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 ("SEC"), capitalized oil and gas property
costs are limited to the present value of future net income from estimated
production of proved oil and gas reserves discounted at 10%, plus the value of
unproved properties. 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.
Significant declines in oil and gas prices, like those experienced in early
1997, if not offset by increases in proved oil and gas reserves, could cause the
Company's capitalized oil and gas property costs to exceed the limitation on
such costs, as described above.
Unevaluated properties and associated costs not currently being amortized
and included in oil and gas properties were $7.3 million and $10.6 million at
December 31, 1995 and 1996. Such costs relate to projects which were at such
dates undergoing exploration or development activities or in which the Company
intends to commence such activities in the future. The Company will begin to
amortize these costs when proved reserves are established or impairment is
determined.
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 $229,000, $201,000
and $665,000 in 1994, 1995 and 1996, 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.
Impact of Recently Issued Accounting Standards
The Financial Accounting Standard Board issued Statements of Financial
Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of" and No. 123, "Accounting for
Stock-Based Compensation." SFAS Nos. 121 and 123 are effective for financial
statements for fiscal years beginning after December 15, 1995. SFAS 121 was
adopted as of January 1, 1996 and had no impact on the financial position or
results of operations of the Company. As permitted under SFAS 123, the Company
will continue to account for such compensation under the provisions of APB
Opinion No. 25.
F-8
<PAGE> 95
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In October 1996, the American Institute of Certified Public Accountants
issued Statement of Position 96-1, "Environmental Remediation Liabilities" (the
SOP), which was adopted by the Company in the first quarter of 1997. The SOP
provided guidance concerning the recognition, measurement and disclosure of
environmental remediation liabilities. The adoption of the SOP did not have a
material effect on the Company's financial position or results of operations.
In February, 1997, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 128, "Earnings per Share" (FAS
128). This statement simplifies the computation of earnings per share (EPS).
Basic EPS includes no dilution and is computed by dividing income available to
common stockholders by the weighted average number of shares outstanding for the
period. FAS 128 is effective for periods ending after December 15, 1997.
Pro-forma EPS under the methodology required by FAS 128 is as follows:
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
--------------------------- -----------------
1994 1995 1996 1996 1997
------- ------- ------- ------- -------
DOLLARS IN THOUSANDS
(EXCEPT PER SHARE DATA)
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Income from continuing operations........................... $23,603 $23,405 $21,717 $16,780 $ 9,276
Income (loss) from discontinued operations.................. 554 (2,099) (1,845) (1,974) 5,389
------- ------- ------- ------- -------
Net income.................................................. $24,157 $21,306 $19,872 $14,806 $14,665
======= ======= ======= ======= =======
Average shares of common stock outstanding.................. 22,970 22,960 23,114 23,094 28,670
Pro-forma basic EPS
Continuing operations..................................... $ 1.03 $ 1.02 $ 0.94 $ 0.73 $ 0.32
Discontinued operations................................... 0.02 (0.09) (0.08) (0.09) 0.19
------- ------- ------- ------- -------
$ 1.05 $ 0.93 $ 0.86 $ 0.64 $ 0.51
======= ======= ======= ======= =======
</TABLE>
2. 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), GED Energy
Services, Inc. and InterCoast Gas Services Company (collectively referred to as
the Medallion entities), indirect wholly-owned subsidiaries of MidAmerican
Energy Holdings Company ("MidAmerican"), for a purchase price of approximately
$199.1 million, consisting of a cash payment of $194.1 million and warrants to
purchase 870,000 shares of Common Stock at an exercise price of $22.50 per share
and a four-year term (the "Medallion Acquisition").
Medallion's principal assets are proved oil and gas reserves of 187.5 Bcfe
as of December 31, 1996, consisting of 140.3 Bcf of natural gas and 7.9 MMbbls
of oil and liquids. The Company also acquired a natural gas gathering system as
well as oil and gas equipment and supplies. The Medallion Acquisition more than
doubled the Company's reserve and production base.
Rocky Mountain Acquisition. 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. 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. 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.
F-9
<PAGE> 96
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Michigan Acquisition. On December 7, 1995, the Company acquired 24.6 Bcfe
of proved 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 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.
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.
The following are the unaudited pro forma revenue, net income and earnings
per share of the Company giving effect to the Medallion, Rocky Mountain and
Michigan acquisitions and the January 1997 common stock offering for the years
ended December 31, 1995 and 1996, 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>
PRO FORMA YEARS
ENDED DECEMBER 31,
------------------------
1995 1996
---------- ----------
DOLLARS IN THOUSANDS
(EXCEPT PER SHARE DATA)
<S> <C> <C>
Revenue..................................................... $164,339 $180,112
-------- --------
Net income.................................................. $ 26,652 $ 35,120
-------- --------
Earnings per common share................................... $ 0.91 $ 1.18
-------- --------
</TABLE>
3. RETIREMENT BENEFIT PLANS
The Company had 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 was to make annual contributions that met the minimum
funding requirements of the Employee Retirement Income Security Act of 1974.
The Board of Directors took action to terminate the Plan effective
September 30, 1995. The Company filed all required standard termination
applications with both the Internal Revenue Service and the Pension Benefit
Guaranty Corporation. In July, 1996, the Company completed the termination of
the Plan and satisfied all obligations thereunder, recording a pre-tax expense
of $262,000.
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 based upon
their pro-rata share of total eligible compensation. 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
F-10
<PAGE> 97
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 $293,622 in 1994,
$253,666 in 1995 and $102,455 in 1996.
4. STOCK OPTION AND INCENTIVE PLANS
In October 1995, the Financial Accounting Standards Board issued SFAS 123,
Accounting for Stock-Based Compensation ("SFAS 123"). As permitted under SFAS
123, the Company has elected to continue to account for such compensation under
the provisions of APB Opinion No. 25. The Company has complied with the required
disclosures under SFAS 123. Had compensation cost for the following plans been
determined consistent with SFAS 123, the impact on the Company's net income and
earnings per share would not be material.
Under the 1988 Stock Plan and the 1992 Stock Plan (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 2,000 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, 1996, options for 779,812 shares were exercisable.
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, 1993.................... 959,400 $ 0.69-$11.44
1994 -- Granted........................................... 212,000 $ 7.25-$13.44
-- Exercised........................................ (64,400) $ 0.69-$ 3.13
1995 -- Granted........................................... 210,000 $ 6.50-$ 8.16
-- Exercised........................................ (45,200) $ 0.69-$ 0.99
-- Forfeited........................................ (6,200) $11.44-$13.44
1996 -- Granted........................................... 12,000 $ 11.44
-- Exercised........................................ (183,000) $ 0.75-$11.44
-- Forfeited........................................ (35,450) $ 6.50-$11.44
--------- -------------
Options outstanding, December 31, 1996.................... 1,059,150 $ 0.92-$13.44
========= =============
</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, 1996. Restricted stock
totaling 8,000 shares was outstanding under the Employee Incentive Plans at
December 31, 1996.
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
F-11
<PAGE> 98
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 was
immaterial during the three years ended December 31, 1996. Bonus stock grants
totaling 17,600 shares were outstanding at December 31, 1996.
At December 31, 1996, 212,662 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 determined by
the closing price on the date of purchase. The minimum purchase is 50 shares.
The maximum annual purchase is the number of shares costing no more than 10% of
the eligible employee's annual base salary, and for directors, 6,000 shares. The
number of shares issued in connection with the Program was 14,876, 13,794 and
15,326 during 1994, 1995 and 1996, respectively. At December 31, 1996, there
were 872,064 shares available for issuance under the Program.
A summary of the status of the Employee Incentive Plans and the 1994
Directors' Stock Plan at December 31, 1996 and 1995 and changes during the years
then ended is presented in the table and narrative below:
<TABLE>
<CAPTION>
1995 1996
--------------------- ---------------------
WTD. AVG. WTD. AVG.
SHARES EX. PRICE SHARES EX. PRICE
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Outstanding at beginning of year........... 1,107,000 $ 4.50 1,265,600 $ 4.95
Grant...................................... 210,000 6.58 12,000 11.44
Exercised.................................. (45,200) 0.81 (183,000) 1.81
Forfeited.................................. (6,200) 12.09 (35,450) 7.85
--------- ------ --------- ------
Outstanding at end of year................. 1,265,600 4.95 1,059,150 5.46
--------- ------ --------- ------
Exercisable at end of year................. 777,600 $ 3.30 779,812 $ 4.68
--------- ------ --------- ------
Weighted average fair value of options
granted.................................. $ 2.41 $ 4.36
====== ======
</TABLE>
The following table summarizes information about stock options outstanding
at December 31, 1996:
<TABLE>
<CAPTION>
NUMBER WEIGHTED NUMBER
OUTSTANDING AT AVERAGE WEIGHTED EXERCISABLE AT WEIGHTED
RANGE OF DECEMBER 31, REMAINING AVERAGE DECEMBER 31, AVERAGE
EXERCISE PRICES 1996 CONTRACTUAL LIFE EXERCISE PRICE 1996 EXERCISE PRICE
- --------------- -------------- ---------------- -------------- -------------- --------------
<C> <C> <C> <C> <C> <C>
$ 0.92 -
$ 3.12....... 360,000 4.01 $ 0.98 360,000 $ 0.98
3.12 - 4.68 104,800 5.92 3.13 104,800 3.13
4.69 - 7.01 185,000 8.91 6.50 46,250 6.50
7.02 - 10.52 195,000 7.92 7.74 102,500 7.33
10.53 - 13.44 214,350 7.04 11.53 166,262 11.56
- --------------- --------- ----- ------ ------- ------
$ 0.92 - $13.44 1,059,150 6.38 $ 5.46 779,812 $ 4.68
=============== ========= ===== ====== ======= ======
</TABLE>
The fair value of each option grant is estimated on the date of grant using
the Black-Scholes option pricing model with the following weighted-average
assumptions used for grants in 1995 and 1996, respectively: risk-free interest
rates of 5.73% and 6.52%; expected dividend yield of .33%; expected lives of 5.1
years; expected stock price volatility of 30%.
F-12
<PAGE> 99
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. LONG-TERM DEBT
Long-term debt consists of the following:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------- SEPTEMBER 30,
1995 1996 1997
-------- -------- -------------
(UNAUDITED)
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Master Note Facility............................. $ 76,255 $ -- $ --
Receivables Facility............................. 26,900 -- --
VPP Facility..................................... 38,000 -- --
Note Financing................................... 24,374 -- --
Credit Facility.................................. -- 55,600 74,500
11% Senior Notes Due 2003........................ -- 149,456 149,523
Revolving Credit Agreement....................... -- 105,000 51,700
Other............................................ -- 291 --
-------- -------- --------
165,529 310,347 275,723
Less current maturities.......................... -- -- --
-------- -------- --------
Long-term debt................................... $165,529 $310,347 $275,723
======== ======== ========
</TABLE>
SENIOR NOTES
On January 25, 1996, KCS Energy, Inc. (the "Parent") completed a Rule 144A
private offering of $150 million 11% senior notes 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.
On June 6, 1996, the Parent completed an offer to exchange the $150 million
outstanding Senior Notes for registered notes of the same tenor (the "Registered
Notes") pursuant to a registration statement declared effective by the
Securities and Exchange Commission on May 7. The Registered 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 Registered Notes evidenced the same debt, and were issued under and
entitled to the benefits of the same Indenture, as the Senior Notes.
CREDIT FACILITY
On September 25, 1996, the Company assigned the collateral pledged under
both the Master Note Facility and VPP Facility, described below, and effectively
amended these facilities to create one consolidated revolving credit facility
("Credit Facility") which matures on September 30, 2000. The Credit Facility is
used for general corporate purposes, including working capital and to support
the Company's capital expenditure program. The borrowing base, or actual
availability under the Credit Facility, is currently limited to $75 million
under the terms of the Senior Notes. The borrowing base is reviewed at least
semiannually and may be adjusted based on the lenders' valuation of the
borrowers' oil and gas reserves and other factors.
F-13
<PAGE> 100
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Substantially all of the Company's oil and gas reserves (excluding those pledged
under the Revolving Credit Agreement) have been pledged to secure the Credit
Facility.
The Credit Facility permits the Borrowers to choose interest rate options
based on the bank's prime rate or LIBOR and from maturities ranging up to twelve
months. The applicable spread over the prime rate or LIBOR is determined each
quarter based on KCS' consolidated debt-to-EBITDA ratio. A commitment fee of
0.375% is paid on the unused portion of the borrowing base. The weighted average
effective interest rate for 1996 was 8.71%. As of December 31, 1996, the
weighted average effective interest rate on the outstanding borrowings was
8.25%. Immediately following the Medallion Acquisition, $55.6 million was
outstanding under the Credit Facility.
REVOLVING CREDIT AGREEMENT
Simultaneous with the completion of the Medallion Acquisition, the Company
entered into a revolving credit agreement ("Revolving Credit Agreement") with a
group of banks. The Revolving Credit Agreement is used for general corporate
purposes, including working capital and to support the Company's capital
expenditure program. The Revolving Credit Agreement had an initial borrowing
base of $105 million and matures on September 30, 2000. The obligations under
the Revolving Credit Agreement are secured by substantially all of the oil and
gas reserves of the Medallion entities and a pledge of the Medallion entities'
common stock. The borrowing base is reviewed at least semiannually and may be
adjusted based on the lenders' valuation of the borrowers' oil and gas reserves
and other factors.
The Revolving Credit Agreement permits KCS to borrow at interest rates
based on the bank's prime rate or LIBOR and from maturities ranging up to twelve
months. The applicable spread over the prime rate or LIBOR is determined each
quarter based on KCS' consolidated debt-to-EBITDA ratio. A commitment fee of
0.375% is paid on the unused portion of the borrowing base. Immediately
following the Medallion Acquisition, $105 million was outstanding under the
Revolving Credit Agreement at a weighted average effective interest rate of
7.8%.
Following the completion of the common stock offering (see Note 12), the
amount outstanding under the Revolving Credit Agreement was reduced to $0.2
million. The Revolving Credit Agreement also included a $30 million term loan
component which was never utilized and was terminated on February 18, 1997.
TERMINATED FACILITIES
The Master Note Facility was used primarily to support the oil and gas
exploration and production and natural gas transportation businesses. On
September 25, 1996, the primary collateral pledged to secure the Master Note
Facility was assigned to the Credit Facility described above. Simultaneous with
the collateral assignment, the Company's obligations under the Master Note
Facility were fully satisfied. The weighted average effective interest rate was
7.98% in 1995 and 8.86% in 1996.
The VPP Facility was used primarily to support the natural gas marketing
subsidiary's volumetric production payment program. On September 25, 1996, the
collateral pledged to secure the VPP Facility was assigned to the Credit
Facility described above. Simultaneous with the collateral assignment, the
Company's obligations under the VPP Facility were fully satisfied. The weighted
average effective interest rate was 8.17% in 1995 and 7.94% in 1996.
The Receivable Facility was used primarily to support the natural gas
marketing subsidiary's working capital requirements. In July 1996, the Company
paid all outstanding obligations and terminated the Receivable Facility. The
weighted average effective interest rate was 7.64% in 1995 and 7.69% in 1996.
The Note Financing was used primarily to fund the Company's oil and gas
property acquisitions and for general corporate purposes. In January 1996, the
Company paid all outstanding obligations and terminated the
F-14
<PAGE> 101
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Note Financing. The Company also had issued to the purchaser under the Note
Financing a warrant to purchase 229,366 shares of the Company's common stock. In
October 1996, the Company exercised its option to buy back the warrant at a cost
of $668,000.
OTHER INFORMATION
KCS Energy, Inc. is a borrower under the Revolving Credit Agreement and has
guaranteed the obligations of its subsidiaries under the Credit Facility. 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 Senior Notes Indenture).
This restriction does not apply to purchase money indebtedness. The Company's
ability to pay cash dividends is limited by these agreements.
The fair value of the Company's Senior Notes, $162 million, is estimated
based upon the December 31, 1996 quoted market price of $108.00 for such issue.
The carrying amount of the remaining long-term debt reasonably approximates fair
value because its interest rates are based on current market rates. Interest
payments were $2.1 million in 1994, $6.8 million in 1995 and $10.9 million in
1996.
Scheduled maturities of long-term debt during the next five years are as
follows:
<TABLE>
<CAPTION>
PRO
ACTUAL FORMA(1)
------ --------
(DOLLARS IN THOUSANDS)
<S> <C> <C>
1997................................................. -- --
1998................................................. -- --
1999................................................. -- --
2000................................................. $160,600 $49,900
2001................................................. -- --
</TABLE>
- ---------------
(1) Reflects the issuance of common stock in January 1997 and the repayment of
amounts outstanding under the Credit Facility and the Revolving Credit
Agreement.
6. LEASES
Future minimum lease payments under non-cancelable operating leases are as
follows: $825,000 in 1997, $752,000 in 1998, $578,000 in 1999, $535,000 in 2000
and $484,000 in 2001. Lease payments charged to operating expenses amounted to
$598,000, $466,000 and $564,000 during 1994, 1995 and 1996, respectively.
F-15
<PAGE> 102
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
7. INCOME TAXES
Federal and state income tax expense includes the following components:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED
DECEMBER 31,
---------------------------
1994 1995 1996
------- ------- -------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Currently payable....................................... $ 1,121 $ 2,545 $ 3,800
Deferred provision, net................................. 10,342 8,096 7,028
------- ------- -------
Federal income tax expense.............................. 11,463 10,641 10,828
State income taxes (deferred provision $204 in 1994,
$1,460 in 1995 and $578 in 1996)...................... 806 1,176 1,852
------- ------- -------
$12,269 $11,817 $12,680
======= ======= =======
Sources of deferred federal and state income taxes:
Intangible drilling costs............................. $10,278 $12,619 $16,529
Revenue recognition deferred.......................... 2,343 1,854 1,348
Depreciation, depletion and amortization.............. (2,233) (5,779) (5,134)
Tax credit carry forwards and other, net.............. 158 862 (5,137)
------- ------- -------
$10,546 $ 9,556 $ 7,606
======= ======= =======
Reconciliation of federal income tax expense at
statutory rate to provision for income taxes:
Income before income taxes.............................. $35,872 $35,222 $34,397
------- ------- -------
Tax provision at 35% statutory rate..................... 12,555 12,328 12,039
State income tax, net of federal income tax benefit..... 523 764 1,204
Statutory depletion..................................... (696) (676) (475)
Section 29 credits...................................... (388) (425) --
Other, net.............................................. 275 (174) (88)
------- ------- -------
$12,269 $11,817 $12,680
======= ======= =======
</TABLE>
The primary differences giving rise to the Company's deferred tax assets
and liabilities are as follows:
<TABLE>
<CAPTION>
DECEMBER 31, 1996
-----------------------
ASSETS LIABILITIES
------- ------------
(DOLLARS IN THOUSANDS)
<S> <C> <C>
Income tax effects of:
Accelerated DD&A and other property related items......... $37,340
Deferred revenue.......................................... 6,183
Alternative minimum tax credit carry forwards............. $1,923
Net operating loss carry forward.......................... 6,500
Other, net................................................ 1,003
------ -------
$9,426 $43,523
====== =======
</TABLE>
Income tax payments were $1.3 million in 1994 and $5.6 million in 1996. No
income tax payments were made in 1995.
The Company had tax net operating losses ("NOL") of approximately $18.6
million at December 31, 1996. This NOL expires in 2011. The Company believes it
will generate future taxable income to realize the entire deferred tax asset
prior to the expiration of the NOL.
F-16
<PAGE> 103
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
8. FINANCIAL INSTRUMENTS
The Company has entered into swaps, futures contracts and options to manage
risks associated with fluctuations in the price of its natural gas and oil
production and marketing activities.
Commodity Price Swaps. Commodity price swap agreements require the Company
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
Company accounts for these transactions on a settlement basis and, accordingly,
gains or losses are included in oil and gas revenue in the period in which the
underlying natural gas is produced. These agreements do not impose cash margin
requirements on the Company. As a result of the Medallion Acquisition at
December 31, 1996, the Company was party to commodity price swap agreements
covering approximately 8.5 million MMBtu, 4.8 million MMBtu and 17.8 million
MMBtu of natural gas for the years 1997 and 1998 and for the period 1999 through
2005, respectively.
Futures and Options Contracts. Natural gas futures contracts require the
Company to buy or sell natural gas at a fixed price. The Company uses futures to
hedge price risk on a portion of its oil and gas production and to manage profit
margins on offsetting fixed-price purchase or sale commitments for physical
quantities of natural gas. Futures contracts mandate initial margin
requirements. The Company maintains such margin accounts and funds in cash any
daily settlement requirements relating to futures contracts. Natural gas options
used to hedge price risk only provide the right, not the requirement, to buy or
sell natural gas at a fixed price. The Company uses options to limit overall
price risk exposure.
At December 31, 1996, the Company's hedging activities consisted of 1,500
long contracts at an average price of $2.25 per Mcf and 635 short contracts at
an average price of $2.53 per Mcf maturing through 1999, covering 21,350 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 corresponding physical
transactions. Deferred gains, net of deferred losses, were $1.0 million at
December 31, 1996. Deferred losses, net of deferred gains, were $0.1 million at
December 31, 1995.
Basis Swaps. Basis swap agreements require KCS 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. As a result of the Medallion Acquisition at December 31, 1996, the Company
had basis swap arrangements relating to a total of approximately 2.2 million
MMBtu during 1997.
9. LITIGATION
Tennessee Gas Litigation
Prior to January 1, 1997, most of the Company's natural gas sold from the
Bob West Field in south Texas was covered by the Tennessee Gas Contract which
had been the subject of several lawsuits. The first such suit was filed by
Tennessee Gas in the 57th District Court of Bexar County, Texas, in August,
1990, and two subsequent suits were filed in the 49th District Court of Zapata
County, Texas, in November, 1994, and April, 1995.
In the suit in the District Court of Bexar County, Texas ("District Court")
against the Company and its co-sellers, Tennessee Gas claimed 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
F-17
<PAGE> 104
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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. On
September 15, 1995, the Company filed a request for a rehearing in the Texas
Supreme Court of the Section 2.306 issue.
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.
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"); 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. On June 3, 1996 Tennessee Gas filed a motion requesting
another rehearing 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. 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.
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 pending Zapata
County, Texas, lawsuits including 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
of $37.1 million for estimated future net revenues before income taxes (based
upon a natural gas price of $3.69 per Mcf, the assumed realized spot market
price on December 31, 1996) and $34.7 million for PV-10 as compared to prior
reserve reports prepared as of June 30, 1996.
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 $70 million
of past underpayments (including interest and net of severance taxes and other
payables related to the contract) that had accrued under the contract.
F-18
<PAGE> 105
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Royalty Suits
The Company is a party to six lawsuits in the Texas State Courts involving
various claims asserted by various holders of royalty interests under leases on
the acreage that was dedicated to the Tennessee Gas Contract or pooled
therewith. One suit involves claims by the holder of an overriding royalty
interest in the dedicated acreage. Of the other five (the "Royalty Basis
Suits"), one seeks a declaratory judgment on the royalty payment basis for
non-dedicated acreage in which the Company owns no interest. The other four
suits seek declaratory judgements to determine whether royalties payable to the
holders of landowner royalty interests in the dedicated acreage should be based
on the net proceeds received by the Company for gas sales under the Tennessee
Gas Contract or on the spot market price. The Company paid royalties based upon
the spot market price to the holders of royalty interests (other than the
overriding royalty interest) because the Company's leases, which cover only
dedicated acreage, have market value royalty provisions.
The aggregate amount at issue in the Royalty Basis Suits, apart from
certain tort counterclaims and affirmative defenses alleged by the landowner
royalty holders, is a function of the quantity of natural gas for which
Tennessee Gas paid at the contract price. As of December 31, 1996, the amount of
natural gas taken by Tennessee Gas attributable to the royalty interests
involved in the Royalty Basis Suits was approximately 3.8 Bcf for which
royalties have been paid by the Company at the average price of approximately
$1.63 per Mcf, net of severance tax, compared to the average Tennessee Gas
Contract price of approximately $7.60 per Mcf, net of severance tax.
Consequently, if the Company loses in its litigation with these royalty interest
owners on these claims the Company faces a maximum liability in the Royalty
Basis Suits of approximately $22.7 million at December 31, 1996.
On March 4, 1997, the holder of an overriding royalty interest filed a
claim against the Company and its co-lessees alleging breach of duties arising
from the termination of the Tennessee Gas Contract and for certain tortious acts
yet to be discovered. The allegations are for joint and several liability,
damages exceeding $25 million, return of the 1/64th overriding royalty interest
acquired by the Company in 1990 under allegedly fraudulent circumstances and
unspecified punitive damages. The Company intends to vigorously contest these
claims. Discovery in this matter has not yet begun.
Initially, there were three Royalty Basis Suits, one in Dallas County,
Texas, in which the Company is a co-plaintiff and two subsequently filed suits
in Zapata County, Texas, in which the Company is a co-defendant. The Dallas suit
has been subsequently split into four separate lawsuits, based on issues
concerning (1) the dedicated acreage in the Guerra "A" and Guerra "B" Units, (2)
the non-dedicated acreage in those Units, (3) the Jesus Yzaguirre Unit, which
consists entirely of dedicated acreage owned only by the Company, and (4) the
overriding royalty interest in the dedicated acreage.
The Dallas Royalty Basis Suits involving the dedicated acreage in the
Guerra "A" and Guerra "B" Units and the Jesus Yzaguirre Unit have resulted in
separate summary judgments in favor of the Company's position that royalty
payments based upon the spot market price are all that is required to be paid
under the leases and dismissal of the royalty owners counterclaims and
affirmative defenses. The summary judgment has been appealed to the Fifth Court
of Appeals in Dallas by the royalty holders in the dedicated leases in the
Guerra "A" and Guerra "B" Units, who have requested oral argument on eleven
points of error. These points of error concern the granting of summary judgment
against them on issues of lease provisions on market value royalties;
counterclaims and affirmative defenses of fraud, negligent misrepresentations,
conspiracy and estoppel; denial of their efforts to supplement summary judgment
evidence; denial of efforts to transfer venue to Zapata County; failure to abate
the Dallas lawsuit in favor of the two lawsuits filed by them in Zapata County;
and the entry of final judgment in favor of the Company and its co-plaintiffs.
Given the inherent uncertainties of appellate matters and notwithstanding that
the Company's position on the market value and other issues is based upon
established decisional law in Texas, the Company is unable to provide any
assurance of a favorable outcome of this appeal from the summary judgments and
evidentiary rulings, inasmuch as the Appellants can obtain a reversal and remand
for plenary trial upon showing that summary judgment was
F-19
<PAGE> 106
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
improper because there exists an issue of material fact. Because of other issues
(discussed below) in the Royalty Basis Suit involving the Jesus Yzaguirre Unit,
the summary judgment in favor of the Company in that suit is not yet ripe for
appeal.
In the Jesus Yzaguirre Royalty Basis Suit, certain of the royalty owners
counterclaimed against the Company, asserting that the largest lease contained
therein had terminated in December, 1975, and that they were entitled to the
Tennessee Gas Contract Price because of the execution of certain division orders
in 1992 that allegedly varied the market value royalty provision of their lease.
The Company and these royalty owners have moved for summary judgment on the
issues of lease termination, lease ratification and the effect of division
orders. The trial judge has not yet ruled on these motions. The royalty owners
who have asserted these claims seek a declaratory judgment of their rights and
have not yet specified the amount or basis of the damages being sought. However,
the amount at issue could include the aggregate of the Company's capital costs
in the lease, the lease operating costs and the working interest revenues of the
lease (at market value of the gas production) since 1976.
Royalty Basis Suits -- Recent Events (unaudited)
The claim asserted by certain of the royalty owners in the Jesus Yzaguirre
Royalty Basis suit that the largest lease contained therein had terminated in
December 1975 has been settled, and on June 2, 1997, the trial judge signed an
Order of Dismissal with Prejudice as to that claim. On May 30, 1997, the Zapata
County suit brought by these same royalty owners was dismissed in connection
with this settlement.
On October 22, 1997, the other Zapata County suit was dismissed by the
court on its own motion, inasmuch as the suit had been abated since September
15, 1995 in favor of the earlier-filed suit in Dallas County.
On the issue of the effect of the 1992 division orders raised in the Jesus
Yzaguirre Royalty Basis suit, the trial judge on August 12, 1997 signed an order
granting the Company's motion for summary judgment and denying the royalty
owners' motion. At a hearing on October 29, 1997, the trial court entered a
final judgment in favor of the Company based upon the prior separate summary
judgments in favor of the Company's position on the issues and counterclaims
involved with this lawsuit.
In addition to the appeal filed by the royalty owners in Guerra "A" and
Guerra "B" Units, the royalty owners in the Jesus Yzaguirre Unit have indicated
that they will appeal the trial court's final judgment in that matter in due
course to the Fifth District Court of Appeals in Dallas, Texas.
Other
The Company is also a party to various other lawsuits and governmental
proceedings, all arising in the ordinary course of business. Although the
outcome of all of the above proceedings cannot be predicted with certainty,
management does not expect such matters to have a material adverse effect,
either singly or in the aggregate, on the financial position of the Company.
F-20
<PAGE> 107
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10. QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
QUARTERS
--------------------------------------------
FIRST SECOND THIRD FOURTH
-------- -------- -------- --------
DOLLARS IN THOUSANDS (EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
1995
Revenue................................... $21,475 $21,496 $20,849 $23,295
Operating Income.......................... 9,916 9,520 8,224 9,897
Income From Continuing Operations......... 6,213 5,676 6,366 5,150
Income (Loss) From Discontinued
Operations............................. 7 (299) (2,280) 473
Net Income................................ 6,220 5,377 4,086 5,623
Earnings Per Common Share:
Continuing Operations.................. $ 0.27 $ 0.24 $ 0.27 $ 0.22
Discontinued Operations................ -- (0.01) (0.10) 0.02
------- ------- ------- -------
Earnings Per Common Share................. $ 0.27 $ 0.23 $ 0.17 $ 0.24
======= ======= ======= =======
1996
Revenue................................... $27,284 $26,098 $26,046 $28,946
Operating Income.......................... 11,835 10,721 10,080 10,760
Income From Continuing Operations......... 5,973 5,524 5,283 4,937
Income (Loss) From Discontinued
Operations............................. (118) (537) (1,319) 129
Net Income................................ 5,855 4,987 3,964 5,066
Earnings Per Common Share:
Continuing Operations.................. $ 0.26 $ 0.23 $ 0.22 $ 0.20
Discontinued Operations................ (0.01) (0.02) (0.05) --
------- ------- ------- -------
Earnings Per Common Share................. $ 0.25 $ 0.21 $ 0.17 $ 0.20
======= ======= ======= =======
1997
Revenue................................... $39,879 $32,551 $31,668
Operating Income.......................... 13,717 8,025 7,744
Income From Continuing Operations......... 5,405 2,292 1,579
Discontinued Operations
Net loss from operations............... (72) -- --
Net gain on disposition................ 5,461 -- --
Net Income................................ 10,794 2,292 1,579
Earnings Per Common Share:
Continuing Operations.................. $ 0.19 $ 0.08 $ 0.05
Discontinued Operations................ 0.18 -- --
------- ------- -------
Earnings Per Common Share................. $ 0.37 $ 0.08 $ 0.05
======= ======= =======
</TABLE>
11. 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. As discussed in Note 2, as of December 31,
1996 the Company completed the arrangements for the Medallion Acquisition. As
such, the associated reserves are included in the following tables.
F-21
<PAGE> 108
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,
1996 are not necessarily reflective of the prices the Company expects to receive
in the future. Other than gas sold under contractual arrangements including
swaps, futures contracts and options, gas prices were $3.54 and $2.03 at
December 31, 1996 and 1995, respectively.
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,
---------------------------------
1994 1995 1996
-------- -------- ---------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Revenue........................................... $ 65,773 $ 85,424 $ 107,959
Production (lifting) costs........................ 7,063 6,623 11,693
Technical support and other....................... 2,671 2,373 4,401
Depreciation, depletion and amortization.......... 18,538 37,859 44,565
-------- -------- ---------
Total expenses.......................... 28,272 46,855 60,659
-------- -------- ---------
Pretax income from producing activities........... 37,501 38,569 47,300
Income taxes...................................... 12,041 12,549 17,381
-------- -------- ---------
Results of oil and gas producing activities
(excluding corporate overhead and interest)..... $ 25,460 $ 26,020 $ 29,919
======== ======== =========
Capitalized costs incurred:
Property acquisition............................ $ 27,772 $ 77,515 $ 198,927
Exploration..................................... 12,599 16,891 18,315
Development..................................... 33,311 26,859 54,889
-------- -------- ---------
Total capitalized costs incurred........ $ 73,682 $121,265 $ 272,131
Capitalized costs at year-end:
Proved properties............................... $169,624 $284,597 $ 536,817
Unproved properties............................. 5,074 7,297 10,574
-------- -------- ---------
174,698 291,894 547,391
Less accumulated depreciation, depletion and
amortization.................................... (49,077) (86,936) (131,521)
-------- -------- ---------
Net investment in oil and gas producing
properties...................................... $125,621 $204,958 $ 415,870
======== ======== =========
</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.
F-22
<PAGE> 109
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,
-----------------------
1995 1996
--------- ----------
(DOLLARS IN THOUSANDS)
<S> <C> <C>
Future cash inflows......................................... $ 521,914 $1,213,604
Future costs:
Production................................................ (94,880) (320,457)
Development............................................... (21,985) (43,882)
Discount -- 10% annually.................................. (113,964) (291,653)
--------- ----------
Present value of future net revenues...................... 291,085 557,612
Future income taxes, discounted at 10%.................... (59,322) (120,013)
--------- ----------
Standardized measure of discounted future net cash flows.... $ 231,763 $ 437,599
========= ==========
</TABLE>
CHANGES IN DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVE QUANTITIES
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------
1994 1995 1996
-------- -------- --------
<S> <C> <C> <C>
Balance, beginning of year......................... $160,884 $179,660 $231,763
Increases (decreases)
Sales, net of production costs................... (58,710) (78,801) (96,266)
Net change in prices, net of production costs.... (11,180) 9,593 50,328
Discoveries and extensions, net of future
production and development costs.............. 26,930 22,417 67,791
Changes in estimated future development costs.... (9,622) (862) 2,005
Change due to acquisition of reserves in place... 26,038 108,798 292,557
Development costs incurred during the period..... 13,924 9,672 10,411
Revisions of quantity estimates.................. 1,532 (19,256) (45,003)
Accretion of discount............................ 21,017 24,033 29,108
Net change in income taxes....................... (12,060) 2,021 (60,691)
Sales of reserves in place....................... -- (1,931) (11,507)
Changes in production rates (timing) and other... 20,907 (23,581) (32,897)
-------- -------- --------
Net increase..................................... 18,776 52,103 205,836
-------- -------- --------
Balance, end of year............................... $179,660 $231,763 $437,599
======== ======== ========
</TABLE>
F-23
<PAGE> 110
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
RESERVE INFORMATION (UNAUDITED)
The following information with respect to the Company's net proved oil and
gas reserves are estimates based on reports prepared by independent petroleum
engineers (principally Ryder Scott Company, 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.
<TABLE>
<CAPTION>
1994 1995 1996
--------------- --------------- ----------------
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....... 69,740 2,578 89,184 2,319 140,963 7,517
Production....................... (11,304) (211) (19,129) (196) (25,581) (758)
Discoveries, extensions, etc..... 10,924 33 10,399 202 21,998 2,196
Acquisition of reserves in
place.......................... 18,206 148 71,560 5,449 157,051 7,245
Sales of reserves in place....... -- -- (3,751) (3) (9,224) (492)
Revisions of estimates........... 1,618 (229) (7,300) (254) (17,182) (1,077)
------- ----- ------- ----- ------- ------
Balance, end of year............. 89,184 2,319 140,963 7,517 268,025 14,631
======= ===== ======= ===== ======= ======
Proved developed reserves
Balance, beginning of year..... 61,016 1,579 74,215 1,336 121,987 3,808
------- ----- ------- ----- ------- ------
Balance, end of year........... 74,215 1,336 121,987 3,808 236,454 12,133
======= ===== ======= ===== ======= ======
</TABLE>
12. SUBSEQUENT EVENTS (UNAUDITED)
In January 1997, the Company completed a public offering of 6,000,000
shares (giving effect to the two-for-one stock split effective June 30, 1997) of
its common stock. The net proceeds to the Company of approximately $110.6
million were used to reduce outstanding indebtedness under the bank credit
facilities.
During the first quarter of 1997, the Board of Directors approved a plan to
discontinue the Company's natural gas transportation and marketing operations in
order to focus on the core oil and gas exploration and production operations. As
of March 31, 1997, the Company sold its Texas intrastate natural gas pipeline
system together with related marketing assets and a joint venture gathering
system for a net sales price of $27.9 million, resulting in an after tax gain of
approximately $5.9 million. The proceeds from the sale were used to fund a
portion of the Company's 1997 capital budget.
F-24
<PAGE> 111
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
During the third quarter of 1997, the Company sold its natural gas
marketing operations for a net sale price of $0.5 million and realized an
after-tax gain of $0.3 million. The results for the transportation and marketing
operations have been classified as discontinued operations for all periods
presented in the Statements of Consolidated Income. The assets and liabilities
of discontinued operations have been classified in the Consolidated Balance
Sheets as "Net assets of discontinued operations." Net assets of the Company's
discontinued operations at September 30, 1997 and December 31, 1996 and 1995 are
as follows:
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31, SEPTEMBER 30,
1995 1996 1997
------------ ------------ -------------
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
Assets
Current Assets
Accounts receivable, net.......................... $44,804 $61,632 $ 816
Other............................................. 2,361 2,995 4,200
------- ------- ------
Total current assets......................... 47,165 64,627 5,016
Net property, plant and equipment.................... 18,987 17,977 600
Other noncurrent assets.............................. 2,877 1,964 1,384
------- ------- ------
Total........................................ 69,029 84,568 7,000
Liabilities
Current liabilities.................................. 54,049 55,701 1,890
Noncurrent liabilities............................... -- 2,209 --
------- ------- ------
Total........................................ 54,049 57,910 1,890
------- ------- ------
Net assets of discontinued operations.................. $14,980 $26,658 $5,110
======= ======= ======
</TABLE>
Summarized results of operations of the discontinued transportation and
marketing operations are as follows:
<TABLE>
<CAPTION>
FOR NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------ ----------------------
1994 1995 1996 1996 1997
-------- -------- -------- ---------- ---------
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C> <C>
Revenues................................ $278,590 $360,627 $274,323 $225,438 $22,015
Costs and expenses*..................... 277,748 363,968 277,237 228,528 22,129
-------- -------- -------- -------- -------
Income (loss) before income taxes....... 842 (3,341) (2,914) (3,090) (114)
Provision (benefit) for income taxes.... 288 (1,242) (1,069) (1,116) (42)
-------- -------- -------- -------- -------
Income (loss) from discontinued
operations............................ 554 (2,099) (1,845) (1,974) (72)
======== ======== ======== ======== =======
Gain on disposal before income
taxes**............................... -- -- -- -- 8,668
Provision for income taxes.............. -- -- -- -- 3,207
-------- -------- -------- -------- -------
Net gain on disposal.................... $ -- $ -- $ -- $ -- $ 5,461
======== ======== ======== ======== =======
</TABLE>
- ---------------
* Includes allocated net interest expense of $0.7 million, $1.1 million and
$3.8 million for the years ended December 31, 1994, 1995 and 1996,
respectively and $2.6 million and $0.1 million for the nine-month periods
ended September 30, 1996 and 1997, respectively.
** The nine-month period ended September 30, 1997 includes a $1.1 million
provision for estimated losses during the wind-down period.
On May 6, 1997, the Company's Board of Directors approved a two-for-one
stock split of its common stock effective June 30, 1997 to stockholders of
record on June 3, 1997. All references in the financial statements and notes
thereto included in this Prospectus to the number of common shares and earnings
per share reflect the stock split.
F-25
<PAGE> 112
======================================================
NO DEALER, SALESPERSON OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS NOT CONTAINED IN 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. THIS
PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER
TO BUY ANY OF THE SECURITIES OFFERED HEREBY IN ANY JURISDICTION TO ANY PERSON TO
WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER IN SUCH JURISDICTION. NEITHER THE
DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY
CIRCUMSTANCES, CREATE ANY IMPLICATION THAT INFORMATION CONTAINED HEREIN IS
CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE HEREOF OR THAT THERE HAS BEEN NO
CHANGE IN THE AFFAIRS OF THE COMPANY SINCE THAT DATE.
------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Prospectus Summary..................... 3
Risk Factors........................... 10
Special Note on Forward-Looking
Statements........................... 16
Use of Proceeds........................ 17
Capitalization......................... 17
Selected Historical Financial
Information.......................... 18
Management's Discussion and Analysis of
Financial Condition and Results of
Operations........................... 19
Business and Properties................ 27
Management............................. 48
Security Ownership by Certain
Beneficial Owners and Management..... 50
Description of Existing Indebtedness... 51
Description of the Notes............... 54
Underwriting........................... 82
Certain Legal Matters.................. 83
Experts................................ 83
Available Information.................. 84
Incorporation of Certain Documents by
Reference............................ 84
Glossary............................... 85
Index to Consolidated Financial
Statements........................... F-1
</TABLE>
======================================================
======================================================
$125,000,000
LOGO
KCS ENERGY, INC.
8 7/8% SENIOR
SUBORDINATED NOTES
DUE 2008
------------
PROSPECTUS
JANUARY 15, 1998
------------
SALOMON SMITH BARNEY
PRUDENTIAL SECURITIES INCORPORATED
CIBC OPPENHEIMER
JEFFERIES AND COMPANY, INC.
MORGAN KEEGAN & COMPANY, INC.
======================================================
