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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 1997
OR
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from__________________to_____________________
Commission file number 1-11698
KCS ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware 22-2889587
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
379 Thornall Street, Edison, New Jersey 08837
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (732) 632-1770
Securities registered pursuant to Section 12(b) of the Act:
Title of Class Name of each exchange
on which registered
COMMON STOCK, par value $0.01 per share New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Title of class
COMMON STOCK, par value $0.01 per share
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes: |X| No: |_|
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10K. |X|
The aggregate market value of the 25,934,553 shares of the Common Stock held by
non-affiliates of the Registrant at the $17.75 closing price on February 27,
1998 was $460,338,316.
Number of shares of Common Stock outstanding as of the close of business on
February 27, 1998: 29,455,294
Documents Incorporated By Reference
Part III incorporates information by reference to Notice of and Proxy Statement
for the 1998 Annual Meeting of Shareholders to the extent indicated herein.
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KCS ENERGY, INC.
FORM 10-K
Report for the Year Ended December 31, 1997
PART I
Item 1. Business.
General development of business
KCS Energy, Inc. "KCS" or the "Company" is an independent oil and
gas company engaged in the acquisition, exploration, development and production
of oil and gas. The Company was formed in 1988 in connection with the spin-off
of the non-utility operations of NUI Corporation, a New Jersey-based natural gas
distribution company that had been engaged in the oil and gas exploration and
production business since the late 1960s. The Company's operations are primarily
focused in the Rocky Mountain, Gulf Coast, and Mid-Continent/West Texas
regions. Additionally, the Company augments its working interest ownership of
properties with a volumetric production payment ("VPP") program to acquire oil
and gas reserves from properties which to date have been located primarily in
the Gulf of Mexico and Michigan.
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. See Note 10 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.
As of December 31, 1996, the Company completed the arrangements for
the Medallion Acquisition (see Note 3 to Consolidated Financial Statements),
effectively doubling its oil and gas reserves and giving it a substantial
presence in the Mid-Continent/West Texas region.
In January 1997, the Company completed a public offering of six
million shares of common stock. The net proceeds to the Company of approximately
$110.6 million were used to reduce outstanding indebtedness under the Company's
bank credit facilities.
During 1997, the Company sold its principal natural gas
transportation asset, the Texas intrastate pipeline, and its third-party gas
marketing operations realizing proceeds of $28.5 million and an after-tax gain
of $5.4 million. Accordingly, the financial statements included in this annual
report 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
marketing and transportation operations, to a Company focused on exploration and
production, with a portfolio of properties 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
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from the Bob West Field, which in 1995 accounted for 34% of total production and
72% of the Company's oil and gas revenues, accounted for less than 5% of total
production and oil and gas revenue in 1997.
Forward-Looking Statements
The information discussed in this Form 10-K includes
"forward-looking statements" within the meaning of Section 27A of the Securities
Act of 1933, as amended (the "Securities Act"), and Section 21E of the
Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements
other than statements of historical facts included herein regarding planned
capital expenditures, increases in oil and gas production, the number of
anticipated wells to be drilled after the date hereof, the Company's financial
position, business strategy and other plans and objectives for future
operations, are forward-looking statements. Although the Company believes that
the expectations reflected in such forward-looking statements are reasonable,
they do involve certain assumptions, risks and uncertainties, and the Company
can give no assurance that such expectations will prove to have been correct.
The Company's actual results could differ materially from those anticipated in
these forward-looking statements as a result of certain factors, including the
timing and success of the Company's drilling activities, the volatility of
prices and supply and demand for oil and gas, the numerous uncertainties
inherent in estimating quantities of oil and gas reserves and actual future
production rates and associated costs, the usual hazards associated with the oil
and gas industry (including blowouts, cratering, pipe failure, spills,
explosions and other unforeseen hazards), and increases in regulatory
requirements, some of which risks (as well as others) are described more fully
elsewhere in this Form 10-K.
All forward-looking statements attributable to the Company
or persons acting on its behalf are expressly qualified in their entirety by
such factors.
Narrative description of business
Oil and Gas Exploration and Production
All of the Company's exploration and production activities are
located within the United States. The Company competes with major oil and gas
companies, other independent oil and gas concerns and individual producers and
operators in the areas of reserve acquisitions and the exploration, development,
production and marketing of oil and gas, as well as contracting for equipment
and securing personnel. Oil and gas prices have historically been volatile and
are expected 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, the foreign supply of oil
and gas, the price of foreign imports, the level of consumer product demand,
weather conditions, domestic and foreign government regulations and taxes, the
price and availability of alternative fuels and overall economic conditions.
One customer, Tennessee Gas, accounted for approximately 4% and 40%
of the Company's consolidated revenue for the years ended December 31, 1997 and
1996, respectively. No other single customer accounted for more than 10% of the
Company's consolidated revenues in 1997 or 1996.
Development and Production Activities
During the three-year period ended December 31, 1997, the Company
participated in the drilling of 186 development wells with a 86% success rate.
During 1997, the Company substantially increased its level of development
drilling in the Manderson Field, drilling 38 wells, 20 of which have been
completed to date with the balance awaiting completion and tie-in. The Company's
activities are currently focused on the Manderson Field in the Big Horn Basin as
well as the Wind River and Green River Basins of Wyoming, the Langham Creek Area
and Glasscock Ranch Field in Texas and the Laurel Ridge and Elm Grove fields
in Louisiana.
The Company has currently identified over 600 development drilling
and recompletion locations, representing approximately a four-year inventory,
and has initially budgeted $75 million for development activities in 1998. The
Company plans to drill, recomplete or workover as many as 140 wells in 1998 and
focus its development drilling program primarily in the Rocky Mountain and
onshore Gulf Coast regions discussed above and in the Sawyer Canyon Field, the
Elm Grove Field and several other prospects in the Mid-Continent/West Texas
region.
Exploration Activities
During the three-year period ended December 31, 1997, the Company
participated in the drilling of 75 exploratory wells with a 43% success rate.
Discoveries included wells in the Langham Creek Area, the Franklin Deep Field in
Louisiana and Laurel Ridge Field. During 1997, the Company participated in the
drilling of 33 exploratory wells and completed 13 wells.
The Company's policy is to commit no more than 25% of its cash flow
to exploration activities and generally no more than $750,000 for any single
well. The company has established an initial budget of $20 million for
exploration in 1998 and intends to participate in drilling a wide variety of
prospects, including both low-risk and high-risk, high-potential prospects in
order to maintain a balanced program with the potential for significant reserve
additions.
During 1998, the Company plans to participate in the drilling of up
to 40 exploratory prospects and to continue 3-D and 2-D seismic data acquisition
and analysis.
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Volumetric Production Payment Program
The Company augments its working interest ownership of properties
with a VPP program, a method of acquiring oil and gas reserves scheduled to be
delivered in the future at a discount to the current market price in exchange
for an up-front cash payment. A VPP 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 VPPs 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 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 VPP are substantially greater than the specified
reserve volumes required to be delivered pursuant to the production payment.
Since the inception of the VPP program in August 1994 through
December 31, 1997, the Company had invested $124.5 million under the VPP
program and had acquired proved reserves of 70.1 Bcf of gas and 1.6 million
barrels of oil through 27 separate transactions. The Company has recovered
approximately $85.6 million in revenue from the sale of oil and gas acquired
under the program, with 37.4 Bcf of gas and 1.0 million barrels of oil
scheduled for future deliveries.
Raw Materials
The Company obtains its raw materials (principally natural gas and
oil) from various sources, which are presently considered adequate. While the
Company regards the various sources as important, it does not consider any one
source to be essential to its business as a whole.
Patents and Licenses
There are no patents, trademarks, licenses, franchises or
concessions held by the Company, the expiration of which would have a material
adverse effect on its business.
Seasonality
Demand for natural gas and oil is seasonal, principally related to
weather conditions and access to pipeline transportation.
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.
The Company believes that its operations comply in all material
respects with all applicable laws and regulations and that the existence and
enforcement of such laws and regulations have no more restrictive effect on the
Company's method of operations than on other similar companies in the energy
industry.
The following discussion contains summaries of certain laws and
regulations and is qualified in its entirety by the foregoing.
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
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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.
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 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
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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 and Indian oil and gas leases,
which are subject to the regulation of the United States Minerals Management
Service ("MMS"). The MMS has proposed 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 federal
royalty oil in 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 MMS
believes better reflects its market value. MMS has also issued a notice of
proposed rulemaking in which it proposes similar changes to regulations
establishing the value for royalty purposes of oil produced from Indian leases.
The Company cannot predict what action the MMS will take on these matters, nor
can it predict how the Company will be affected by any change to these
regulations.
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
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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 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 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
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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 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.
Employees
The Company and its subsidiaries employed a total of 229 persons on
December 31, 1997.
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Item 2. Properties.
Oil and Gas Properties
The following table sets forth data as of December 31, 1997
regarding the number of gross producing wells and the estimated quantities of
proved oil and gas reserves attributable to the Company's principal properties.
<TABLE>
<CAPTION>
Estimated Proved Reserves
Gross -------------------------
Producing Oil Natural Gas Total
Location Wells (Mbbls) (MMcf) (MMcfe)
--------- ------- ------- ---------
<S> <C> <C> <C> <C>
Rocky Mountain Region:
Manderson Field, Wyoming 15 8,163 85,643 134,621
Ignacio Blanco Field, Colorado 37 -- 6,708 6,708
Fourteen Mile Field, Wyoming 3 987 2,772 8,694
Dragon Trail Field, Colorado 163 321 3,131 5,057
Others 988 3,065 17,795 36,185
------- ------- ------- -------
Total 1,206 12,536 116,049 191,265
Gulf Coast Region:
Bob West Field, Texas 48 -- 16,267 16,267
Langham Creek Area, Texas 19 270 28,634 30,254
Others 321 1,289 29,927 37,661
------- ------- ------- -------
Total 388 1,559 74,828 84,182
Mid-Continent/West Texas Region:
Sawyer Canyon Field, Texas 346 28 43,675 43,843
Elm Grove Field, Louisiana 24 12 13,649 13,721
Mills Ranch Field, Texas 22 91 4,709 5,255
Others 579 2,354 31,552 45,676
------- ------- ------- -------
Total 971 2,485 93,585 108,495
Other Regions:
Newhall-Potrero Field, California 39 1,307 1,453 9,295
Mayfield/Hayes Properties, Michigan 8 148 2,552 3,440
Others 19 44 337 601
------- ------- ------- -------
Total 66 1,499 4,342 13,336
Total Working Interest Properties 2,631 18,079 288,804 397,278
Volumetric Production Payments (VPP):
Niagaran Reef Trend, Michigan 95 598 8,584 12,172
Gulf of Mexico 19 318 28,752 30,660
Others 91 68 28 436
------- ------- ------- -------
Total VPP Properties 205 984 37,364 43,268
------- ------- ------- -------
Total Company 2,836 19,063 326,168 440,546
======= ======= ======= =======
</TABLE>
- --------------------------------------------------------------------------------
8
<PAGE> 10
Set forth below are descriptions of certain of the Company's
significant oil and gas producing properties and those targeted for significant
drilling activity in 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.
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 proved oil and gas reserves and acreage
holdings as well as 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 518,248 gross (408,718
net) developed and undeveloped acres as of December 31, 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 acquisition to 64,257 gross (60,698
net) acres at December 31, 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,
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. The Phosphoria and Tensleep produce sour oil and gas.
Through December 31, 1997, the Company had drilled a total of 63 wells
in the field. Based on drilling and production results, coupled with the
acquisition and interpretation of additional seismic data, the Company believes
that the seven 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. Of the 63 wells the
Company had drilled, 50 wells targeted the Phosphoria. 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 were shut-in for extended periods of time awaiting completion of
a sour gas processing facility (amine plant) and an associated acid gas
injection system which was completed and put into service in December 1997. As
of December 31, 1997, nine wells were completed and producing or ready to
produce, nine wells had been plugged back to the shallower Octh Louie or Muddy
formations due to well bore damage caused by being shut-in, 12 wells were
awaiting completion, 18 wells were awaiting stimulation or remediation, one
well had been completed as a full-stream re-injection well and one well had
been completed as a water disposal well. Through December 31, 1997, the
9
<PAGE> 11
Company also drilled 13 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, four wells were in the process of being completed and
one well had been completed as an acid gas injection well.
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 process
sour gas in late July 1997. Prior to its completion in December 1997, operation
of the amine plant had been severely limited due to delays in receipt of acid
gas disposal equipment. The plant has the 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 capacity, assuming treatment to pipeline specifications, would permit
oil production from the Manderson Field at up to 14,000 barrels 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.
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 obtained permits for 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 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 December 31, 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 barrels
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. Based 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.
Other Big Horn Basin Properties
In addition to its holdings in the Manderson Field, the Company also
has interests in approximately 100,000 gross acres on other producing
properties with many of the same formations as the Manderson Field area in the
Big Horn Basin. 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
acres.
Gulf Coast Region
The Company's Gulf Coast Region operations are and comprised
primarily of onshore properties in Texas and Louisiana, including the Langham
Creek Area near Houston, Texas and the Bob West Field in south Texas. The
Company also owns non-operated interests in the Gulf of Mexico.
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
10
<PAGE> 12
the Wilcox formation from 9,000 to 16,500 feet.
The Company acquired additional working interests in the Langham
Creek Area 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 100% in 19 wells in this area, representing an average net revenue interest
of approximately 46%. 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. In
addition, the Company has initiated a 3-D seismic survey to better delineate
potential drilling locations not only for the known productive horizons, but
also for a deeper, high potential exploration prospect. Results of the 3-D
seismic survey are expected to be completed during the second quarter of 1998
and could change the number of potential drilling locations.
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 had been the Company's most significant producing property,
accounting for approximately 34% of gas production and 61% of oil and gas
revenues during the six-year period ended December 31, 1996. In 1997, production
from the Bob West Field accounted for less than 5% of total production and oil
and gas revenue. 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 32 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.
Gulf of Mexico
The Company has working interests ranging from 1% to 14% in 12
offshore fields (including blocks located in the Eugene Island, Ship Shoal,
South Timbalier, Vermilion and East and West Cameron areas) which are operated
by others. The Company has an average working interest of approximately 8% in
50 wells.
These fields produce from various Pleistocene, Pliocene and Miocene
sands ranging from 6,000 feet to 15,000 feet in depth. The Company continues to
participate in the development of the properties where it already owns leases
but is not currently participating in new leasehold acquisitions.
The Company also has acquired substantial reserves in the Gulf of
Mexico under its VPP program. See "-- Volumetric Production Payment Program."
Mid-Continent/West Texas Region
General
In the Mid-Continent/West Texas Region, the Company has active
drilling programs in the Anadarko, Ardmore, Arklatex, Arkoma, and Permian
Basins.
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. 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
11
<PAGE> 13
gas 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 10% of the Company's proved reserves as of December
31, 1997. The Company owns interests in 346 gross (314 net) wells, of which it
operates 323. The Company's average working interest in this field was 91%, and
its leasehold position at December 31, 1997 consisted of approximately 36,807
gross (35,759 net) acres.
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 has continued to optimize the field's production and
cash flow performance by maintaining close well, compressor and operating
expense surveillance. The Company believes that additional proved reserves may
ultimately be attributed to many of the 30 or more 40-acre drilling locations
remaining on the property. In addition to exploiting these Canyon sand
development opportunities, the Company intends to evaluate portions of the
Sawyer Canyon Field for potential in the shallower Wolfcamp and deeper Strawn
formations which have been found to be productive in the area.
Elm Grove Field
The Company has interests in approximately 5,760 gross (5,545 net)
acres in the Elm Grove Field, Bossier Parish, Louisiana. 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 December 31, 1997, the
Company owned an interest in 24 gross (23.7 net) wells, all of which were
operated by the Company.
Other Regions
Newhall-Potrero Field
The Company's Newhall-Potrero Field is located in Los Angeles
County, California, outside the city of Valencia. The Company is the operator
and owns a 100% working interest in 39 active wells. 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 working interests averaging 20% in 24 active
producing wells located in the northern Niagaran Reef trend of Michigan. 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"). During 1997, the Company began expanding its
involvement in the area by participating 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 and where per well cumulative
productions have exceeded 450 Mbbls of oil. This project is currently in the
final stages of leasing. Drilling of the first 10 prospects is expected to
commence by mid-year 1998.
12
<PAGE> 14
Volumetric Production Payment and Underlying Principal Properties
The following table shows, as of December 31, 1997 the oil and gas
deliveries to the Company that are scheduled to be made pursuant to its VPP
program over the period from 1998 through 2006.
<TABLE>
<CAPTION>
Cumulative
Natural Gas Oil Total Total
Period (MMcf) (Mbbls) (MMcfe) (MMcfe)
---------- --------- --------- --------- ---------
<S> <C> <C> <C> <C>
1998 19,110 412 21,584 21,584
1999 11,501 183 12,598 34,182
2000 2,616 117 3,316 37,498
2001 1,690 110 2,348 39,846
2002 888 57 1,227 41,073
2003-2006 1,557 107 2,201 43,274
</TABLE>
The properties underlying the VPP program are principally located in
two major regions, the Gulf of Mexico and the Niagaran Reef trend in Michigan.
Gulf of Mexico VPP Properties
Hall-Houston Oil Company Properties. The Company has acquired
interests in 11 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
the 1994 through 1997 period 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 2,169
MMcf during 1997 and is scheduled to receive deliveries totaling 7,164 MMcf in
1998, and 4,922 MMcf in 1999.
On January 27, 1998 the Company entered into its eleventh VPP
transaction with HHOC. Under terms of the agreement, KCS acquired 10.8 billion
cubic feet (Bcf) of proved natural gas reserves scheduled to be produced and
delivered during the 1998-2000 period.
ATP Oil & Gas Properties. The Company has acquired interests in
eight blocks off the coast of Louisiana, one block off the coast of Texas and
one onshore property in Texas through VPP contracts with ATP Oil & Gas Co. of
Houston, Texas ("ATP"), which is the operator of all of the blocks. The blocks
contain 11 wells drilled during 1996 and 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
555 MMcfe during 1997 and is scheduled to receive deliveries totaling 11,030
MMcfe in 1998, and 5,263 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.
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. The
Niagaran Reef reservoirs are typically found at depths between 4,000 and 6,500
feet. Of the remaining 8,684 MMcf and 597.9 Mbbls to be delivered under the
VPP program, the Company is scheduled to receive 2,195 MMcf
and 161.6 Mbbls in 1998, with the balance to be delivered between 1999 and 2006.
13
<PAGE> 15
Other VPP Properties
The Company is also scheduled to receive deliveries totaling 444
MMcfe from 1998 to 2000 from several smaller VPPs.
Oil and Gas Reserves
All information in this Form 10-K relating to estimates of the
Company's proved reserves is based on reports prepared by KCS and other
independent petroleum engineers. The reports for the KCS Medallion Resources,
Inc.; KCS Mountain Resources, Inc.; KCS Resources, Inc.; and KCS Michigan
Resources, Inc. properties, which collectively represent 90% of total KCS proved
reserves at December 31, 1997, were audited by Netherland, Sewell & Associates,
Inc. pursuant to the principles set forth in the Standards Pertaining to the
Estimating and Auditing of Oil and Gas Reserve Information promulgated by the
Society of Petroleum Engineers. The 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.
The following table sets forth, as of December 31, 1997, summary
information with respect to (i) the estimates of the Company's proved oil and
gas reserves attributable to working interests and (ii) the reserve amounts
contracted for pursuant to the agreements relating to VPP's. The present value
of future net revenues in the table should not be construed to be the current
market value of the estimated oil and gas reserves owned by the Company.
<TABLE>
<CAPTION>
December 31, 1997
----------------
<S> <C>
Proved reserves:
Oil (Mbbls) 19,063
Natural gas (MMcf) 326,168
Total (MMcfe) 440,546
Future net revenues ($000s) $653,935
Present value of future net revenues ($000s) $410,506
Proved developed reserves:
Oil (Mbbls) 13,008
Natural gas (MMcf) 234,091
Total (MMcfe) 312,139
Future net revenues ($000s) $486,026
Present value of future net revenues ($000s) $339,144
</TABLE>
There are numerous uncertainties inherent in estimating quantities
of proved oil and gas reserves and in projecting future rates of production and
future amounts and timing of development expenditures, including underground
accumulations of crude oil and natural gas that cannot be measured in an exact
manner, and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Estimates of proved undeveloped reserves are inherently less certain than
estimates of proved developed reserves. The quantities of oil and gas that are
ultimately recovered, production and operating costs, the amount and timing of
future development expenditures, geologic success and future oil and gas sales
prices may all differ from those assumed in these estimates. In addition, the
Company's reserves may be subject to downward or upward revision based upon
production history, purchases or sales of properties, results of future
development, prevailing oil and gas prices and other factors. Therefore, the
present value shown above should not be construed as the current market value of
the estimated oil and gas reserves attributable to the Company's properties.
In accordance with SEC guidelines, the estimates of future net
revenues from the Company's proved reserves and the present value thereof are
made using oil and gas sales prices in effect as of the dates of such estimates
and are held constant throughout the life of the properties except where such
guidelines permit alternate treatment, including, in the case of natural gas
contracts, the use of fixed and determinable contractual price escalations.
Other than gas sold under contractual arrangements including swaps, futures
contracts and options, gas prices were $2.50 per Mcf and oil prices were $15.15
per barrel at December 31, 1997. The prices for natural gas and, to a lesser
extent, oil, are subject to substantial seasonal fluctuations, and prices for
each are subject to
14
<PAGE> 16
substantial fluctuations as a result of numerous other factors. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
Acreage
The following table sets forth certain information with respect to
the Company's developed and undeveloped leased acreage as of December 31, 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.
<TABLE>
<CAPTION>
Developed Acres Undeveloped Acres
------------------------- ------------------------
State Gross Net Gross Net
- --------------- ----------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Wyoming 335,869 253,031 55,880 50,548
Texas 123,224 71,578 44,380 23,184
Montana 88,880 47,163 38,500 28,675
Louisiana 114,827 28,093 18,716 11,694
Oklahoma 50,284 23,440 10,962 6,321
Colorado 30,201 13,461 10,000 5,250
Other 64,285 11,570 83,474 26,054
----------- ---------- ---------- ----------
Total 807,570 448,336 261,912 151,726
=========== ========== ========== ==========
</TABLE>
Drilling Activities
All of the Company's drilling activities are conducted through
arrangements with independent contractors. Certain information with regard to
the Company's drilling activities during the years ended December 31, 1997, 1996
and 1995, is set forth below.
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1997 1996 1995
------------ ------------ ------------
Type of Well Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Development:
Oil 33 33.0 43 40.9 1 0.4
Natural gas 42 29.2 22 10.9 19 7.4
Non-productive 18 16.4 8 5.8 -- --
-- ---- -- ---- -- ----
Total 93 78.6 73 57.6 20 7.8
== ==== == ==== == ====
Exploratory:
Oil 1 1.0 1 1.0 1 0.4
Natural gas 12 7.2 5 3.0 12 4.3
Non-productive 20 13.9 15 10.5 8 5.3
-- ---- -- ---- -- ----
Total 33 22.1 21 14.5 21 10.0
== ==== == ==== == ====
</TABLE>
At December 31, 1997, the Company was participating in the drilling
or completion of 30 gross (21.35 net) wells.
15
<PAGE> 17
Production and Sales
The following table presents certain information with respect to oil
and gas production attributable to the Company's properties and average sales
prices during the three years ended December 31, 1997, 1996 and 1995.
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------
1997 1996 1995
---------- ---------- ----------
<S> <C> <C> <C>
Production:
Oil (Mbbl) 1,696 758 196
Liquids (Mbbl) 128 -- --
Gas (MMcf) 43,700 25,581 19,129
Total (MMcfe) 54,644 30,129 20,305
Average price:
Oil (per bbl) $ 18.57 $ 20.69 $ 17.28
Liquids (per bbl) 11.02 -- --
Gas (per Mcf) 2.40 3.61 4.29
Total (per Mcfe) 2.52 3.59 4.27
</TABLE>
Other Facilities
Principal offices of the Company and its operating subsidiaries are
leased in modern office buildings in Edison, New Jersey (10,000 square feet),
Houston, Texas (25,000 square feet) and Tulsa, Oklahoma (17,000 square feet). In
Worland, Wyoming, the Rocky Mountain operations are based in a 10,000 square
foot Company-owned facility.
The Company believes that all of its property, plant and equipment
are well maintained, in good operating condition and suitable for the purposes
for which they are used.
16
<PAGE> 18
Item 3. Legal Proceedings.
Information with respect to this Item is contained in Note 10 to the
Consolidated Financial Statements on pages 38 and 39 of this Form 10-K.
Item 4. Submission of Matters to a Vote of Security Holders.
No matter was submitted to a vote of security holders through the
solicitation of proxies or otherwise during the three months ended December 31,
1997.
17
<PAGE> 19
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters.
The Company's Common Stock is traded on the New York Stock Exchange.
Listed below are the high and low closing sales prices for the periods
indicated:
<TABLE>
<CAPTION>
1997
--------------------------------------------------------------
Jan. - Mar. Apr. - June July - Sept. Oct. - Dec.
------------- ------------- -------------- -------------
<S> <C> <C> <C> <C>
Market Price
High $ 21.81 $ 21.19 $ 30.00 $ 29.94
Low 15.75 13.31 19.63 19.75
<CAPTION>
1996
--------------------------------------------------------------
Jan. - Mar. Apr. - June July - Sept. Oct. - Dec.
------------- ------------- -------------- -------------
<S> <C> <C> <C> <C>
Market Price
High $ 7.88 $ 14.38 $ 17.81 $ 22.06
Low 6.69 7.81 13.38 14.44
</TABLE>
There were 1,114 stockholders of record of the Company's Common
Stock on February 27, 1998.
The Company pays dividends on a quarterly basis. The aggregate
amount of dividends declared were $2,204,000 and $1,388,000 in 1997 and 1996,
respectively.
Item 6. Selected Financial Data.
The following table sets forth the Company's selected Financial Data
for each of the five years ended December 31, 1997.
<TABLE>
<CAPTION>
Dollars in thousands
(except per share data) 1997 1996 1995 1994 1993
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Revenue $ 143,689 $ 108,374 $ 87,115 $ 67,400 $ 41,428
Income (loss) from
continuing operations (97,385)(a) 21,717 23,405 23,603 17,529
Income (loss) from
discontinued operations 5,302 (1,845) (2,099) 554 1,082
Net income (loss) (92,083)(a) 19,872 21,306 24,157 18,611
Total assets 502,414 511,820 306,564 176,179 117,640
Long-term debt 292,445 310,347 165,529 61,970 36,289
Stockholders' equity 145,070 125,622 101,576 80,668 59,765
Per common share (Basic):
Income (loss) from
continuing operations (3.37)(a) 0.94 1.02 1.03 0.79
Income (loss) from
discontinued operations 0.18 (0.08) (0.09) 0.02 0.05
Net income (loss) (3.19)(a) 0.86 0.93 1.05 0.84
Per common share (Diluted)
Income (loss) from
continuing operations (3.37)(a) 0.92 1.00 1.01 0.76
Income (loss) from
discontinued operations 0.18 (0.08) (0.09) 0.02 0.05
Net income (loss) (3.19)(a) 0.84 0.91 1.03 0.81
Per common share:
Stockholders' equity 4.93 5.42 4.42 3.52 2.60
Dividends 0.075 0.06 0.06 0.045 0.03
</TABLE>
(a) includes a $165,149 pretax, $107,347 after-tax, or $3.72 per share,
non-cash ceiling writedown of oil and gas assets.
18
<PAGE> 20
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.
General
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
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.
See Note 10 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.
As of December 31, 1996, the Company completed the arrangements for
the Medallion Acquisition (see Note 3 to Consolidated Financial Statements),
effectively doubling its oil and gas reserves and giving it a substantial
presence in the Mid-Continent/West Texas region.
In January 1997, the Company completed a public offering of six
million shares of common stock. The net proceeds to the Company of approximately
$110.6 million were used to reduce outstanding indebtedness under the Company's
bank credit facilities.
During 1997, the Company sold its principal natural gas
transportation asset, the Texas intrastate pipeline, and its third-party gas
marketing operations, realizing proceeds of $28.5 million and an after-tax gain
of $5.4 million. Accordingly, the financial statements included in this annual
report 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 gas
marketing and transportation operations, to a Company focused on exploration and
production, with a portfolio of properties 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 1995
accounted for 34% of total production and 72% of the Company's oil and gas
revenues, accounted for less than 5% of production and revenues in 1997.
All references in the following discussion related to earnings per
share are based upon the Company's basic earnings per share.
Results of Operations for the Years Ended December 31, 1997, 1996 and 1995
Results of Operations
Net loss for the year ended December 31, 1997 was $92.1 million, or
$3.19 per share, compared to net income of $19.9 million, or $0.86 per share,
for the year ended December 31, 1996. Loss from continuing operations was $97.4
million, or $3.37 per share, for the year ended December 31, 1997, compared to
income of $21.7 million, or $0.94 per share, for the year ended December 31,
1996. The loss in 1997 resulted from a non-cash ceiling test provision of $165.1
million ($107.3 million after tax). Excluding the effect of the ceiling test
provision, income from continuing operations was $9.9 million, or $0.35 per
share. Significantly higher oil and gas production during 1997 was more than
offset by the impact of the termination of the Tennessee Gas Contract, which
contributed premium revenue of $32.8 million in 1996, and higher net interest
costs. Income from discontinued operations in 1997 was $5.3 million, or $0.18
per share (primarily the net gain on disposition), compared to a loss of $1.8
million, or $0.08 per share, in 1996.
Net income for the year ended December 31, 1996 was $19.9 million,
or $0.86 per share, compared to $21.3 million, or $0.93 per share, for the year
ended December 31, 1995. Income from continuing operations was $21.7 million, or
$0.94 per share, for 1996, compared to $23.4 million, or $1.02 per share, for
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
19
<PAGE> 21
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.
Revenue
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Production:
Oil (Mbbl) 1,696 758 196
Liquids (Mbbl) 128 -- --
Gas (MMcf) 43,700 25,581 19,129
Total (MMcfe) 54,644 30,129 20,305
Average Price:
Oil (per bbl) $ 18.57 $ 20.69 $ 17.28
Liquids (per bbl) 11.02 -- --
Gas (per Mcf) 2.40 3.61 4.29
Total (per Mcfe) 2.52 3.59 4.27
Revenue:
Oil $ 31,491 $ 15,684 $ 3,387
Liquids 1,414 -- --
Gas 104,932 92,331 83,242
-------- -------- --------
Total $137,837 $108,015 $ 86,629
</TABLE>
Oil and Gas Production. The Company's oil and gas production during
1997 increased 81% to 54.6 Bcfe, compared to 30.1 Bcfe produced during 1996. Oil
and liquids production increased 141% to 1,824 Mbbls and gas production
increased 71% to 43.7 Bcf. The production increases were primarily a result of
the Medallion Acquisition.
Oil and gas production during 1996 increased 48% to 30.1 Bcfe,
compared to 20.3 Bcfe in 1995, primarily due to higher gas and oil volumes
delivered under the Company's VPP program.
Gas Revenue. In 1997, gas revenue increased $12.6 million to $104.9
million. Production gains added $43.8 million of gas revenue in 1997. This
increase was partially offset by the termination of the Tennessee Gas Contract
which provided $32.8 million in premium over corresponding spot market prices in
1996. Average realized prices for gas not covered by the Tennessee Gas Contract
were $2.40 and $2.35 per Mcf in the years ended 1997 and 1996, respectively.
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. The Company utilizes commodity price swaps, futures and options
(see Note 9 to Consolidated Financial Statements) to help mitigate the impact of
fluctuations in the price of a portion of its natural gas and oil production.
Gas revenue in 1996 increased $9.1 million to $92.3 million. Higher
production from properties not covered by the Tennessee Gas Contract along with
higher 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 in 1995, largely due to normal production declines in 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 percentage of production covered by
the Tennessee Gas Contract. Average non-Tennessee Gas Contract prices were $2.35
in 1996, compared to $1.62 in 1995. Natural gas sales prices under the Tennessee
Gas Contract, excluding severance tax reimbursements, were $8.40 in 1996,
compared to $7.90 in 1995.
20
<PAGE> 22
Oil and Liquids Revenue. In 1997, oil and liquids revenue increased
$17.2 million to $32.9 million, compared to 1996. Production gains added $18.8
million of oil and liquids revenue, partially offset by lower average realized
prices. The production gains were primarily due to the Medallion Acquisition.
In 1996, oil and liquids revenue increased $12.3 million to $15.7
million mainly due to higher production in the Rocky Mountain region.
Other Revenue, net. Other revenue in 1997 included $2.5 million
related to severance tax settlements in connection with the Tennessee Gas
Contract and $1.3 million from the settlement of a gas sales contract dispute.
The remainder of the increase in 1997, compared to 1996, reflected certain
marketing and gathering revenues primarily as a result of the Medallion
Acquisition.
Lease Operating Expenses
As a result of the substantial increase in oil and gas production,
lease operating expenses increased $20.2 million to $29.4 million, or $0.54 per
Mcfe, for the year ended December 31, 1997, compared to $9.2 million, or $0.30
per Mcfe, in 1996. Approximately $17.6 million of this increase was related to
the Medallion properties, with the remainder of the increase primarily due to
expanded operations in the Rocky Mountain region, especially in the Manderson
Field. The increase in the per Mcfe rate reflects a lower percentage of
production from the VPP program, which does not bear any lease operating
expenses, in 1997 compared to 1996, as well as start up costs of expanding
operations in the Manderson Field.
For the year ended December 31, 1996, lease operating expenses
increased $3.0 million to $9.2 million, or $0.30 per Mcfe, compared to $6.2
million, or $0.30 per Mcfe, in 1995 primarily due to production increases in the
Rocky Mountain region.
Production Taxes
Production taxes, which are generally based on a fixed percentage of
revenue, increased 133% to $5.9 million in 1997, compared to $2.5 million in
1996. In addition to the effect of higher oil and gas revenue during 1997, 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.
Production taxes increased $2.1 million to $2.5 million in 1996 over
1995 primarily due to increased revenue and, to a lesser extent, an increase in
average production tax rates which are higher in the Rocky Mountain region
compared to the Gulf Coast region. In addition, a larger percentage of the
Company's revenue was subject to production taxes in 1996, compared to 1995, due
to the decline in production covered under the Tennessee Gas Contract.
General and Administrative Expenses
For the year ended December 31, 1997, general and administrative
expenses increased $2.9 million to $10.8 million, compared to 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.
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.
Depreciation, Depletion and Amortization
For the year ended December 31, 1997, depreciation, depletion and
amortization ("DD&A") increased $15.1 million over 1996 to $60.6 million due
primarily to the increase in oil and gas revenue, which accounted for $12.7
million of the increase. The balance was attributable to the DD&A rate
increasing to 42.4% from 41.7% and the expansion of the Company's operations in
the Mid-Continent and Rocky Mountain regions.
For the year ended December 31, 1996, DD&A increased $7.2 million
over 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.
21
<PAGE> 23
Writedown of Oil and Gas Properties
At December 31, 1997, the Company, in accordance with the full cost
accounting method and procedures prescribed by the Securities and Exchange
Commission ("SEC"), recorded a $165.1 million ($107.3 million net of tax)
non-cash ceiling writedown of its oil and gas properties. A portion of this
writedown reflects price declines during the first part of 1998. Under the SEC
accounting procedures, capitalized oil and gas property costs are limited to the
present value of future net revenues from estimated production of proved oil and
gas reserves at current prices, discounted at 10%, plus the value of unproved
properties ("SEC PV10 value"). To the extent that the capitalized costs exceed
the estimated SEC PV10 value at the end of any fiscal quarter, such excess
costs are written down with a corresponding charge to income. The decrease in
the 1997 SEC PV10 value was largely attributable to significantly lower oil and
gas prices, but was also impacted by delays in start up of the Manderson Field.
The SEC PV10 value of the Company's proved reserves at December 31, 1997 was
$410.5 million. Other than gas sold under contractual arrangements including
swaps, futures contracts and options, gas prices were $2.50 and $3.54 at
December 31, 1997 and 1996, respectively, and oil prices were $15.15 and $22.45
at December 31, 1997 and 1996, respectively.
Further price declines, if not offset by increases in proved oil and
gas reserves, could result in future ceiling writedowns.
Interest and Other Income, net
Interest and other income was $0.5 million for the year ended
December 31, 1997, compared to $5.1 million in 1996. The decrease in 1997 was
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 and other income was $5.1 million in 1996, compared to $4.5
million in 1995. Included in these amounts were $4.4 million and $3.1 million
for 1996 and 1995, respectively related to interest income accrued on the
Tennessee Gas receivable. These amounts were included in the September 30, 1996
cash payment received from Tennessee Gas.
Interest Expense
Interest expense increased $7.8 million to $21.9 million for the
year ended December 31, 1997, compared to the same period in 1996. Higher
average borrowings in 1997 due to the expansion of the Company's 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.
Interest expense was $14.1 million in 1996, compared to $6.8 million
in 1995. The increase in 1996 was due to higher average borrowings, along with
higher average interest rates, principally resulting from the sale of $150
million of 11% Senior Notes in January 1996. Higher average borrowings in 1996,
compared to 1995, were used to expand the Company's operations. The increase in
interest expense during 1996 was partially offset by the increase in interest
income as discussed above.
Income Taxes
The income tax benefit was $52.1 million in 1997, representing an
effective tax rate benefit of 34.8%, compared to effective rate provisions of
36.9% and 33.6% in 1996 and 1995, respectively. A substantial portion of the
income taxes reflected in the Company's income statements during these periods
is deferred to future years.
The Company recognized a net deferred tax asset in the amount of
$16.6 million at December 31, 1997. Deferred tax assets relate primarily to the
Company's net loss and alternative minimum tax credit carryforwards. See Note 8
to Consolidated Financial Statements.
Liquidity and Capital Resources
Cash Flow From Operating Activities
Net income adjusted for non-cash charges increased to $77.6 million
for the year ended December 31, 1997, compared to $75.8 million in 1996. The
increase reflects cash flow from the properties acquired as part of the
Medallion Acquisition, which more than offset the 1996 premium over market
prices received prior to the termination of the Tennessee Gas Contract of $32.8
million. Net cash provided by operating activities was $100.2 million during
1997, compared to $121.3 million for the year ended 1996. The 1996 period
included the receipt of approximately $70 million from Tennessee Gas for past
underpayments and interest.
22
<PAGE> 24
The reductions in trade accounts receivable ($51.8 million) and in accounts
payable and accrued liabilities ($34.1 million) in 1997 were largely related to
the discontinuance of the natural gas transportation and marketing operations,
offset by increases due to the overall growth of the Company's 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 year ended December 31, 1997 were
$226.6 million, of which $107.4 million was for development drilling, $49.5
million for the acquisition of proved reserves under the Company's VPP program,
$54.3 million for lease acquisitions, seismic surveys and exploratory drilling
and $15.4 million for other assets including $10.7 million for Manderson Field
infrastructure.
During 1997, the Company sold its principal natural gas
transportation asset and its third-party gas marketing operations realizing
proceeds of $28.5 million, which were used to reduce indebtedness under its bank
credit facilities, and an after-tax gain of $5.4 million.
The Company has established for 1998 a preliminary capital
expenditure budget of $160 million, consisting of $75 million for development
drilling, $20 million for exploration, $55 million for VPP transactions and $10
million for working interest acquisitions and other. The program is expected to
be funded by cash flow from operations, the sale of non-strategic assets and
borrowings under the Company's bank credit facilities.
Capital expenditures in 1996 were $282.2 million, of which $183.1
million was related to the Medallion Acquisition (see Note 3 to Consolidated
Financial Statements), $54.9 million to development drilling, $15.9 million to
the purchase of proved reserves under the Company's VPP program and $18.2
million to 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, $33 million was for the Rocky Mountain Acquisition and $26.9 million
was for development drilling. The remainder was largely for lease acquisitions,
seismic evaluations and exploratory drilling. The Company funded its capital
expenditures through a combination of internally generated cash and additional
borrowings under its credit facilities.
Debt Financing
On January 15, 1998, the Company completed a public offering of $125
million senior subordinated notes at an interest rate of 8.875% due January 15,
2008. The net proceeds of approximately $121 million were used to pay down
borrowings under the Company's bank credit facilities.
Credit Facility
The Company's revolving credit facility ("Credit Facility"), which
matures September 30, 2000, 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 currently limited to $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 December 31, 1997,
the weighted average interest rate under the Credit Facility was 7.0% and $74.5
million was outstanding.
Revolving Credit Agreement
Simultaneous with the consummation of the Medallion Acquisition, 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, a pledge of the Medallion entities' common stock and certain VPP
assets. The borrowing base, which is a function of the lenders' determination of
the value of the collateral, is currently $90 million. The Revolving Credit
Agreement permits the Company to borrow at interest rates based upon the
23
<PAGE> 25
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 December 31, 1997, the weighted average interest rate under the
Revolving Credit Agreement was 7.4% and $68.4 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.
Year 2000 Issue
The year 2000 issue is the result of computer programs written using
two digits rather than four to define the applicable year. Without corrective
action, programs with time-sensitive software could potentially recognize a date
ending in "00" as the year 1900 rather than the year 2000, causing many computer
applications to fail or create erroneous results.
Assessment and remediation of the Company's business computer
systems, production control systems and other embedded-chip devices for
compliance with the year 2000 is underway. As a result of modifications or
upgrades planned or already completed, the Company believes that the year 2000
issue will not pose significant problems for the Company's business, operations,
or operating systems. The Company expects that any additional modifications or
upgrades of software or hardware required for year 2000 compatibility will be
accomplished using existing resources and will not have a material impact on the
Company's financial position or results of operations in future periods.
The Company has identified and will be contacting customers,
suppliers and other critical business partners to determine whether entities
with which the Company transacts business have an effective plan in place to
address the year 2000 issue. Contingency plans will be developed as needed.
24
<PAGE> 26
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, 1997
and 1996, and the related statements of consolidated operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1997. 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, 1997 and 1996, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997 in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
New York, New York
March 26, 1998
25
<PAGE> 27
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED OPERATIONS
(amounts in thousands, except per share data)
<TABLE>
<CAPTION>
For the Year Ended December 31,
-----------------------------------
1997 1996 1995
--------- --------- ---------
<S> <C> <C> <C>
Oil and gas revenue $ 137,837 $ 108,015 $ 86,629
Other revenue, net 5,852 359 486
--------- --------- ---------
Total revenue 143,689 108,374 87,115
Operating costs and expenses
Lease operating expenses 29,393 9,167 6,156
Production taxes 5,873 2,526 467
General and administrative expenses 10,753 7,825 4,704
Depreciation, depletion and amortization 60,554 45,460 38,231
Writedown of oil and gas properties 165,149 -- --
--------- --------- ---------
Total operating costs and expenses 271,722 64,978 49,558
--------- --------- ---------
Operating income (loss) (128,033) 43,396 37,557
Interest and other income, net 476 5,086 4,472
Interest expense (21,883) (14,085) (6,807)
--------- --------- ---------
Income (loss) from continuing operations
before income taxes (149,440) 34,397 35,222
Federal and state income taxes (benefit) (52,055) 12,680 11,817
--------- --------- ---------
Income (loss) from continuing operations (97,385) 21,717 23,405
Discontinued operations
Net loss from operations (72) (1,845) (2,099)
Net gain on disposition 5,374 -- --
--------- --------- ---------
Net income (loss) $ (92,083) $ 19,872 $ 21,306
========= ========= =========
Basic earnings per share of common stock
Continuing operations $ (3.37) $ 0.94 $ 1.02
Discontinued operations 0.18 (0.08) (0.09)
--------- --------- ---------
$ (3.19) $ 0.86 $ 0.93
========= ========= =========
Diluted earnings per share of common stock
Continuing operations $ (3.37) $ 0.92 $ 1.00
Discontinued operations 0.18 (0.08) (0.09)
--------- --------- ---------
$ (3.19) $ 0.84 $ 0.91
========= ========= =========
Weighted average shares outstanding 28,856 23,114 22,960
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
26
<PAGE> 28
KCS ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
<TABLE>
<CAPTION>
December 31,
----------------------
1997 1996
--------- ---------
<S> <C> <C>
ASSETS
Current assets
Cash and cash equivalents $ 4,802 $ 5,100
Trade accounts receivable 40,115 30,307
Net assets of discontinued operations -- 26,658
Other current assets 6,752 8,392
--------- ---------
Current assets 51,669 70,457
--------- ---------
Property, plant and equipment
Oil and gas properties, full cost method, less
accumulated DD&A - 1997 $356,877; 1996 $133,263 403,754 421,524
Other property, plant and equipment, at cost less
accumulated depreciation - 1997 $3,408; 1996 $1,145 22,579 8,829
--------- ---------
Property, plant and equipment, net 426,333 430,353
--------- ---------
Other assets
Investments and other assets 7,815 11,010
Deferred federal and state income taxes 16,597 --
--------- ---------
Other assets 24,412 11,010
--------- ---------
$ 502,414 $ 511,820
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable $ 39,500 $ 24,144
Accrued liabilities 24,524 15,558
--------- ---------
Current liabilities 64,024 39,702
--------- ---------
Deferred credits and other liabilities
Deferred federal and state income taxes -- 34,097
Other 875 2,052
--------- ---------
Deferred credits and other liabilities 875 36,149
--------- ---------
Long-term debt 292,445 310,347
--------- ---------
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 31,229,890 and 24,976,340,
respectively 312 249
Additional paid-in capital 144,135 30,463
Retained earnings 4,011 98,298
Less treasury stock, 1,801,496 shares, at cost (3,388) (3,388)
--------- ---------
Stockholders' equity 145,070 125,622
--------- ---------
$ 502,414 $ 511,820
========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
27
<PAGE> 29
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, 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 60 110,527 -- -- 110,587
Stock issuances - option and benefit plans 3 2,073 -- -- 2,076
Tax benefit on stock option exercises -- 1,072 -- -- 1,072
Net loss -- -- (92,083) -- (92,083)
Dividends ($0.075 per share) -- -- (2,204) -- (2,204)
------------- -------------- ------------- ------------- ---------------
Balance at December 31, 1997 $ 312 $ 144,135 $ 4,011 $ (3,388) $ 145,070
============= ============== ============= ============= ===============
</TABLE>
The accompanying notes are an integral part of these financial statements.
28
<PAGE> 30
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(dollars in thousands)
<TABLE>
<CAPTION>
For the Year Ended December 31,
---------------------------------------------------
1997 1996 1995
-------------- -------------- ---------------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income (loss) $ (92,083) $ 19,872 $ 21,306
Non-cash charges (credits):
Depreciation, depletion and amortization 60,554 46,611 39,209
Writedown of oil and gas properties 165,149 - -
Deferred income taxes (52,106) 7,925 9,756
Gain on sale of discontinued operations (5,374) - -
Other non-cash charges and credits, net 1,466 1,440 820
-------------- -------------- ---------------
77,606 75,848 71,091
Net changes in assets and liabilities:
Trade accounts receivable 51,824 (33,887) (11,672)
Receivable from Tennessee Gas - 56,437 (42,868)
Other current assets 2,630 (7,060) 2,217
Accounts payable and accrued liabilities (34,100) 34,732 14,163
Federal and state income taxes 1,563 (2,572) 178
Other, net 698 (2,150) (2,999)
-------------- -------------- ---------------
Net cash provided by operating activities 100,221 121,348 30,110
-------------- -------------- ---------------
Cash flows from investing activities:
Investment in oil and gas properties(1) (211,228) (267,133) (121,265)
Proceeds from the sale of oil and gas properties 4,940 16,634 4,069
Proceeds from the sale of pipeline assets 27,907 - -
Investment in other property, plant and
equipment, net (15,341) (10,085) (7,434)
-------------- -------------- ---------------
Net cash used in investing activities (193,722) (260,584) (124,630)
-------------- -------------- ---------------
Cash flows from financing activities:
Proceeds from long-term debt 156,800 325,636 141,298
Repayments of long-term debt (174,791) (180,900) (38,774)
Issuance of common stock 112,663 683 189
Issuance of stock warrants - - 626
Repurchase of stock warrants - (668) -
Tax benefit on stock option exercises 1,072 665 201
Purchase of treasury stock - (116) (37)
Dividends paid (1,962) (1,388) (1,377)
Deferred financing costs and other, net (579) (5,422) (2,748)
-------------- -------------- ---------------
Net cash provided by financing activities 93,203 138,490 99,378
-------------- -------------- ---------------
Increase (decrease) in cash and cash equivalents (298) (746) 4,858
Cash and cash equivalents at beginning of year 5,100 5,846 988
-------------- -------------- ---------------
Cash and cash equivalents at end of year $ 4,802 $ 5,100 $ 5,846
============== ============== ===============
</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.
29
<PAGE> 31
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 9 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 production 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 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
SEC, capitalized oil and gas property costs are limited to the present value of
future net revenues from estimated production of proved oil and gas reserves
discounted at 10%, plus the value of unproved properties.
30
<PAGE> 32
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. At December 31, 1997, the
Company recorded a $165.1 million ($107.3 million net of tax) non-cash ceiling
writedown of its oil and gas properties. A portion of this write down reflects
price declines during the first part of 1998. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations".
Unevaluated properties and associated costs not currently being amortized
and included in oil and gas properties were $21.1 million and $10.6 million at
December 31, 1997 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 $1,072,000,
$665,000 and $201,000 in 1997, 1996 and 1995, respectively.
Earnings Per Share
Basic earnings per share were computed by dividing net income by the
weighted average number of common shares outstanding during the year as required
by FASB Statement No. 128, "Earnings per Share" ("SFAS 128"). Diluted earnings
per share have been computed by dividing net income by the weighted average
number of common shares outstanding plus the incremental shares that would have
been outstanding assuming the exercise of stock options and stock warrants as
applicable. A reconciliation of shares used for basic earnings per share and
those used for diluted earnings per share is as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------
1997 1996 1995
------ ------ ------
(amounts in thousands)
<S> <C> <C> <C>
Average common stock outstanding 28,856 23,114 22,960
Common stock equivalents 515 453 365
------ ------ ------
Average common stock and common
stock equivalents outstanding 29,371 23,567 23,325
====== ====== ======
</TABLE>
Common stock equivalents are not applicable for 1997 earnings per share as
they would be anti-dilutive.
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 these financial statements and notes
thereto related to the number of common shares and per share amounts reflect the
stock split.
2. Discontinued Operations
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.
During 1997, the Company sold its Texas intrastate natural gas pipeline system
and its third-party natural gas marketing operations, realizing proceeds of
$28.5 million and an after-tax gain of $5.4 million. Income taxes associated
with the discontinued operations were $2.8 million.
31
<PAGE> 33
The results for the transportation and marketing operations have been
classified as discontinued operations for all periods presented in the
Statements of Consolidated Operations. The assets and liabilities of the
discontinued operations have been classified in the Consolidated Balance Sheets
as "Net assets of discontinued operations". By December 31, 1997, all assets of
the discontinued operations were disposed of. Net assets of the Company's
discontinued operations at December 31, 1996 were as follows:
<TABLE>
<CAPTION>
December 31,
1996
------------
<S> <C>
(thousands of dollars)
Assets
Current Assets $64,627
Net property, plant and equipment and other 19,941
-------
Total assets 84,568
Liabilities
Current liabilities 55,701
Noncurrent liabilities 2,209
-------
Total liabilities 57,910
-------
Net assets of discontinued operations $26,658
=======
</TABLE>
Summarized results of operations of the Company's discontinued operations are as
follows:
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------
1997 1996 1995
--------- --------- ---------
(thousands of dollars)
<S> <C> <C> <C>
Revenues $ 22,015 $ 274,323 $ 360,627
Costs and expenses * 22,129 277,237 363,968
--------- --------- ---------
(Loss) before income taxes (114) (2,914) (3,341)
(Benefit) for income taxes (42) (1,069) (1,242)
--------- --------- ---------
(Loss) from discontinued operations $ (72) $ (1,845) $ (2,099)
========= ========= =========
Gain on disposal before income taxes $ 8,198 $ -- $ --
Provision for income taxes 2,824 -- --
--------- --------- ---------
Net gain on disposal $ 5,374 $ -- $ --
========= ========= =========
</TABLE>
* Includes allocated net interest expense of $0.1 million, $3.8 million and
$1.1 million for the years ended December 31, 1997, 1996 and 1995,
respectively.
Discontinued operations have not been segregated in the Statements of
Consolidated Cash Flows and, therefore, amounts for certain captions will not
agree with the respective Statements of Consolidated Operations and Consolidated
Balance Sheets.
3. 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
Medallion), 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 as of December 31, 1996, were proved oil and
gas reserves of 187.5 Bcfe consisting of 140.3 Bcf of natural gas and 7.9 MMbbls
of oil and liquids. The Company also acquired a natural gas
32
<PAGE> 34
gathering system as well as oil and gas equipment and supplies. The Medallion
Acquisition doubled the Company's reserve and production base at December 31,
1996.
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.
The above 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. Pro forma
revenue, net income and earnings per share giving effect to the Medallion
Acquisition for the year ended December 31, 1996, as if the transaction had
occurred on January 1, 1996, is $180.1 million, $35.1 million and $1.18,
respectively. Such unaudited pro forma financial data does not purport to be
indicative of the results of operations that would actually have occurred if the
transaction had occurred as presented or that may be obtained in the future.
4. Retirement Benefit Plans
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 the
employee's annual base salary). The Savings Plan also contains a profit-sharing
component whereby the Board of Directors may declare annual discretionary
profit-sharing contributions. Profit-sharing contributions are allocated to
eligible employees based upon their pro-rata share of total eligible
compensation. Employee and profit-sharing contributions are invested at the
direction of the employee in one or more funds or can be directed to purchase
common stock of the Company at fair market value. Company matching
contributions are invested in shares of KCS common stock. Eligible employees
vest in both the Company matching and discretionary profit-sharing
contributions over a four-year period based upon their years of service with
the Company. Company contributions to the Savings Plan were $420,090 in 1997,
$102,455 in 1996 and $253,666 in 1995.
5. Stock Option and Incentive Plans
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.
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, 1997. Restricted stock
totaling 29,200 shares was outstanding under the Employee Incentive Plans at
December 31, 1997.
At December 31, 1997, 1,018,074 shares were available for future grants
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
33
<PAGE> 35
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 14,520, 15,326 and 13,794 during 1997, 1996 and 1995, respectively.
At December 31, 1997, there were 857,544 shares available for issuance under the
Program.
As permitted under SFAS 123, the Company has elected to continue to
account for stock-based compensation under the provisions of APB Opinion No. 25.
Had compensation cost for the following plans been determined consistent with
SFAS 123, the impact on the Company's net income would have been $0.7 million in
1997 and $0.1 million in 1996. The impact on basic earnings per share would have
been $0.02 in 1997. There would have been no effect on earnings per share in
1996 and 1995.
As required under SFAS 123, a summary of the status of the stock options
under the Employee Incentive Plans and the 1994 Directors' Stock Plan at
December 31, 1997, 1996 and 1995 and changes during the years then ended is
presented in the table and narrative below:
<TABLE>
<CAPTION>
1997 1996 1995
----------------------------- ----------------------------- ------------------------------
Weighted Average Weighted Average Weighted Average
Shares Exercise Price Shares Exercise Price Shares Exercise Price
---------- ---------------- ---------- ---------------- ---------- -----------------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of year 1,059,150 $ 5.46 1,265,600 $ 4.95 1,107,000 $ 4.50
Granted 349,400 16.82 12,000 11.44 210,000 6.58
Exercised (236,250) 8.04 (183,000) 1.81 (45,200) 0.81
Forfeited (108,900) 13.83 (35,450) 7.85 (6,200) 12.09
---------- ---------------- ---------- ---------------- ---------- -----------------
Outstanding at end of year 1,063,400 7.76 1,059,150 5.46 1,265,600 4.95
---------- ---------------- ---------- ---------------- ---------- -----------------
Exercisable at end of year 697,300 $ 4.58 779,812 $ 4.68 777,600 $ 3.30
---------- ---------------- ---------- ---------------- ---------- -----------------
Weighted average fair value of
options granted $ 8.79 $ 4.36 $ 2.41
================ ================ =================
</TABLE>
The following table summarizes information about stock options outstanding
at December 31, 1997:
<TABLE>
<CAPTION>
Number Weighted Average Weighted Number Weighted
Range of Outstanding at Remaining Average Exercisable at Average
Exercise Prices December 31, 1997 Contractual Life Exercise Price December 31, 1997 Exercise Price
- ----------------- -------------------- --------------------- ---------------- --------------------- ---------------
<S> <C> <C> <C> <C> <C>
$0.92 - $3.12 360,000 3.02 $ 0.98 360,000 $ 0.98
3.13 - 4.68 60,000 4.92 3.13 60,000 3.13
4.69 - 7.01 125,000 7.91 6.50 55,000 6.50
7.02 - 10.52 125,000 6.93 7.32 87,500 7.34
10.53 - 18.81 393,400 8.23 15.21 134,800 12.24
- ----------------- -------------------- --------------------- ---------------- --------------------- ---------------
$0.92 - $18.81 1,063,400 6.09 $ 7.76 697,300 $ 4.58
================= ==================== ===================== ================ ===================== ===============
</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 1997, 1996 and 1995, respectively: risk-free
interest rates of 6.39%, 6.52% and 5.73%; expected dividend yield of 0.46%,
0.33% and 0.33%; expected lives of 5.6 years, 5.1 years and 5.1 years; expected
stock price volatility of 50.1%, 30.0% and 30.0%.
34
<PAGE> 36
6. Long-Term Debt
Long-term debt consists of the following:
<TABLE>
<CAPTION>
December 31,
-------------------------
1997 1996
-------- --------
(dollars in thousands)
<S> <C> <C>
11% Senior Notes Due 2003 $149,545 $149,456
Revolving Credit Agreement 68,400 105,000
Credit Facility 74,500 55,600
Other -- 291
-------- --------
292,445 310,347
Less current maturities -- --
-------- --------
Long-term debt $292,445 $310,347
======== ========
</TABLE>
Subordinated Notes
On January 15, 1998, KCS Energy, Inc. (the "Parent") completed a public
offering of $125 million senior subordinated notes at an interest rate of 8.875%
due January 15, 2008 (the "Subordinated Notes"). The Subordinated Notes are
noncallable for five years and are unsecured subordinated obligations of the
Parent. Prior to January 15, 2001, the Parent may use proceeds from a public
equity offering to redeem up to 33-1/3% of the Subordinated Notes. The
subsidiaries of the Parent have guaranteed the Subordinated Notes on an
unsecured subordinated basis. The net proceeds of approximately $121 million
were used to reduce the outstanding indebtedness under the credit agreements
discussed below.
The Subordinated Notes contain certain restrictive covenants which, among
other things, limit the Company's ability to incur additional indebtedness,
require the repurchase of the Subordinated Notes upon a change of control and
restrict the aggregate cash dividends paid to 50% of the Company's cumulative
net income, as defined in the indenture, during the period beginning October 1,
1997. A ceiling writedown is not a charge against net income as defined in the
indenture.
Senior Notes
KCS Energy, Inc. 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"). The Senior Notes mature on January
15, 2003 and bear interest at the rate of 11% per annum. The Senior Notes are
redeemable at the option of the Parent, in whole or in part, commencing January
15, 2000, at pre-determined redemption prices set forth within the Senior Notes
indenture. 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 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, as
defined in the indenture, during the period beginning October 1, 1995. A ceiling
writedown is not a charge against net income as defined in the indenture.
Revolving Credit Agreement
Simultaneous with the consummation of the Medallion Acquisition, the
Company entered into a revolving credit agreement ("Revolving Credit Agreement")
with a group of banks which will mature on September 30, 2000. The Revolving
Credit Agreement is used for general corporate purposes, including working
capital and to support the Company's capital expenditure program. As of December
31, 1997, the Revolving Credit Agreement had a borrowing base of $90 million.
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 obligations under the Revolving Credit Agreement are secured by
substantially all of the oil and gas reserves acquired in the Medallion
Acquisition, a pledge of the Medallion entities' common stock and certain VPP
assets.
The Revolving Credit Agreement permits the borrowers under this facility
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
35
<PAGE> 37
interest rate during 1997 was 7.8%. As of December 31, 1997, the weighted
average interest rate under the Revolving Credit Agreement was 7.4% and $68.4
million was outstanding.
Proceeds from the January 1998 sale of the Subordinated Notes were used to
decrease the amount then outstanding under the Revolving Credit Agreement to
$1.0 million. The borrowing base of the Revolving Credit Agreement was
unaffected by the sale of the Subordinated Notes.
Credit Facility
The Company's revolving credit facility ("Credit Facility"), which matures
on September 30, 2000, is used for general corporate purposes, including working
capital and to support the Company's capital expenditure program. On December
31, 1997, the borrowing base, or actual availability under the Credit Facility,
was 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.
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 during 1997 was 7.0%. As of December 31, 1997, the
weighted average interest rate under the Credit Facility was 7.0% and $74.5
million was outstanding.
Following the application of the proceeds from the January 1998 sale of
the Subordinated Notes the amount then outstanding under the Credit Facility was
$30.5 million. The borrowing base of the Credit Facility was unaffected by the
sale of the Subordinated Notes.
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, as amended effective December 31, 1997, contain certain
restrictive covenants which, among other things, require the Company to maintain
minimum levels of cash flow and tangible net worth, as defined in the
agreements. In addition, the Company is restricted from incurring secured
indebtedness 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, $165 million, is estimated
based upon the December 31, 1997 quoted market price of $110.00 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.
Prior to the January 1998 issuance of the Subordinated Notes, the
scheduled maturities of long-term debt during the next five years are as
follows: 1998 $-0- million, 1999 $-0- million, 2000 $142.9 million, 2001 $-0-
million and 2002 $-0- million. Interest payments were $22.5 million in 1997,
$10.9 million in 1996 and $6.8 million in 1995.
7. Leases
Future minimum lease payments under non-cancelable operating leases are as
follows: $787,000 in 1998, $602,000 in 1999, $556,000 in 2000, $491,000 in 2001
and $197,000 in 2002. Lease payments charged to operating expenses amounted to
$796,000, $564,000 and $466,000 during 1997, 1996 and 1995, respectively.
36
<PAGE> 38
8. Income Taxes
Federal and state income tax expense (benefit) includes the following
components:
<TABLE>
<CAPTION>
For the Year Ended December 31,
-----------------------------------
1997 1996 1995
--------- --------- ---------
(dollars in thousands)
<S> <C> <C> <C>
Current provision $ -- $ 3,800 $ 2,545
Deferred provision (benefit), net (52,406) 7,028 8,096
--------- --------- ---------
Federal income tax expense (benefit) (52,406) 10,828 10,641
State income taxes (deferred provision $300 in
1997, $578 in 1996, and $1,460 in 1995) 351 1,852 1,176
--------- --------- ---------
$ (52,055) $ 12,680 $ 11,817
========= ========= =========
Reconciliation of federal income tax expense (benefit)
at statutory rate to provision for income taxes:
Income (loss) before income taxes $(149,440) $ 34,397 $ 35,222
--------- --------- ---------
Tax provision (benefit) at 35% statutory rate (52,304) 12,039 12,328
State income tax, net of federal income tax benefit 228 1,204 764
Statutory depletion (23) (475) (676)
Section 29 credits -- -- (425)
Other, net 44 (88) (174)
--------- --------- ---------
$ (52,055) $ 12,680 $ 11,817
========= ========= =========
</TABLE>
The primary differences giving rise to the Company's deferred tax assets and
liabilities are as follows:
<TABLE>
<CAPTION>
December 31, 1997
---------------------
Assets Liabilities
------ -----------
(dollars in thousands)
<S> <C> <C>
Income tax effects of:
Accelerated DD&A and other property related items $13,646
Deferred revenue 5,354
Alternative minimum tax credit carry forwards $ 1,923
Net operating loss carry forward 33,412
Other, net 262
------- -------
$35,597 $19,000
======= =======
</TABLE>
Income tax payments were $0.5 million in 1997 and $5.6 million in 1996. No
income tax payments were made in 1995.
Deferred tax assets relate primarily to the Company's tax net operating
loss and alternative minimum tax credit carryforwards. The Company had tax net
operating losses ("NOLs") of approximately $95.5 million available to offset
future taxable income (assuming it elects to forego its right to carryback
approximately $18.0 which it currently could carryback to prior periods) of
which approximately $14.5 million will expire in 2011 and approximately $81.0
will expire in 2012. SFAS 109 requires that the tax benefit of such NOLs be
recorded as an asset to the extent that management assesses the realization of
such NOLs to be "more likely than not". Management has concluded that operating
income of the Company will more likely than not be sufficient to fully utilize
the $95.5 million of NOLs prior to their expiration in the year 2012. In
assessing the likelihood of utilization of existing NOLs, management considered,
among other things, the historical operating earnings of KCS prior to the $165.1
million writedown in 1997 of its oil and gas properties. This writedown was
largely attributable to significant oil and gas price declines, but was also
impacted by delays in the start up of the Manderson Field. The deferred tax
assets will be monitored for potential adjustments as future events so indicate.
37
<PAGE> 39
9. 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.
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 gas revenue in the period in which the
underlying natural gas is produced. These agreements do not impose cash margin
requirements on the Company. At December 31, 1997, the Company was party to
commodity price swap agreements covering approximately 4.8 million MMBtu, 3.9
million MMBtu and 13.8 million MMBtu of natural gas production for the years
1998 and 1999 and for the period 2000 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 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, 1997, the Company's hedging activities consisted of 219
short contracts at an average price of $2.46 per MMBtu maturing through 1998,
covering 2,190 MMBtu of natural gas. At December 31, 1996, the Company's hedging
activities consisted of 157 short contracts at an average price of $2.31 per
MMBtu maturing through 1997 covering 1,570 MMBtu 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 $0.5 million at December 31, 1997. Deferred losses, net of deferred
gains, were $0.1 million at December 31, 1996.
10. 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. On December 23, 1996, the Company and
Tennessee Gas entered into a comprehensive 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 two pending lawsuits that had been filed in Zapata County,
Texas, thereby concluding all matters of litigation between them. The December
1996 settlement did not affect the Company's successful conclusion earlier in
the year of the litigation that was decided by the Texas Supreme Court relating
to the validity and pricing provisions of the Tennessee Gas Contract or the
Company's 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 Tennessee Gas Contract.
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 certain rights in the Tennessee Gas
Contract. 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
judgments 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.
Initially, there were three Royalty Basis Suits, one in Dallas County,
Texas, in which the Company is a co-
38
<PAGE> 40
plaintiff and two subsequently filed suits in Zapata County, Texas, in which the
Company is a co-defendant (the "Las Blancas Suit" and the "Gonzalez Suit"). The
Dallas suit was subsequently split into four separate lawsuits, based on issues
concerning (1) the dedicated acreage in the Guerra "A" and Guerra "B" Units (the
"Los Santos Suit"), (2) the non-dedicated acreage in those Units (the "Collins
Suit"), in which the Company has no interests, (3) the Jesus Yzaguirre Unit,
which consists entirely of dedicated acreage owned only by the Company (the
"Jesus Yzaguirre Suit"), and (4) the overriding royalty interest in the
dedicated acreage (the "Matthews Suit").
On March 4, 1997, the holder of an overriding royalty interest filed a
claim against the Company and its co-lessees in the Matthews Suit, alleging
breach of duties arising from the termination of the Tennessee Gas Contract and
for certain tortious acts. Effective January 23, 1998, the Company and the
royalty holder settled their disputes. On February 3, 1998, the Company and its
co-lessees were dismissed from the Matthews Suit. In addition, in May 1997, the
Gonzalez Suit was dismissed and in October 1997 the Las Blancas Suit was
dismissed.
The Los Santos Suit and the Jesus Yzaguirre Suit 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. In
early 1997, the summary judgment in the Los Santos Suit was appealed to the
Fifth Court of Appeals in Dallas by the royalty holders, 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.
In the Jesus Yzaguirre 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. On May 30,
1997, the Company and these royalty owners reached a settlement of the lease
termination claims, and on June 2, 1997, this issue was dismissed from the Jesus
Yzaguirre Suit. On June 17, 1997, the Company and the royalty owners moved for
summary judgment on the issue of the effect of division orders. The trial judge
granted the Company's motion and denied the competing motion on August 12, 1997.
On October 29, 1997, a final judgment was signed, and on November 19, 1997, the
royalty owners gave notice of their appeal to the Fifth Court of Appeals in
Dallas, Texas. The appellate record has been filed and the royalty owners' brief
was filed with the Fifth Court of Appeals on March 18, 1998. The Company will
file its brief in response to the royalty owners' various points of error and
legal arguments early in the second quarter of 1998.
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 the appeals from the summary judgments and
evidentiary rulings in the Los Santos Suit and the Jesus Yzaguirre Suit,
inasmuch as the Appellants in each appeal can obtain a reversal and remand for
plenary trial upon showing that summary judgment was improper because there
exists an issue of material fact.
The aggregate amount at issue in the Los Santos and Jesus Yzaguirre 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 January 1, 1997 (the date
of the termination of the Tennessee Gas Contract) 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, plus interest thereon, at December 31, 1997.
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 or results of
operations of the Company.
39
<PAGE> 41
11. Quarterly Financial Data (unaudited)
<TABLE>
<CAPTION>
Quarters
---------------------------------------------------------
First Second Third Fourth
----------- ----------- ----------- -----------
(dollars in thousands, except per share data)
<S> <C> <C> <C> <C>
1997
Revenue $ 39,879 $ 32,551 $ 31,668 $ 39,591
Operating income (loss) 13,717 8,025 7,744 (157,519)*
Income (loss) from continuing operations 5,405 2,292 1,579 (106,661)*
Discontinued operations 5,389 -- -- (87)
Net income (loss) $ 10,794 $ 2,292 $ 1,579 $ (106,748)*
Basic earnings per common share:
Continuing operations $ 0.20 $ 0.08 $ 0.05 $ (3.63)*
Discontinued operations 0.19 -- -- --
----------- ----------- ----------- -----------
Basic earnings per common share $ 0.39 $ 0.08 $ 0.05 $ (3.63)*
=========== =========== =========== ===========
Diluted earnings per common share:
Continuing operations $ 0.20 $ 0.08 $ 0.05 $ (3.63)*
Discontinued operations 0.19 -- -- --
----------- ----------- ----------- -----------
Diluted earnings per common share $ 0.39 $ 0.08 $ 0.05 $ (3.63)*
=========== =========== =========== ===========
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
Basic earnings per common share:
Continuing operations $ 0.26 $ 0.24 $ 0.23 $ 0.21
Discontinued operations (0.01) (0.02) (0.06) 0.01
----------- ----------- ----------- -----------
Basic earnings per common share $ 0.25 $ 0.22 $ 0.17 $ 0.22
=========== =========== =========== ===========
Diluted earnings per common share:
Continuing operations $ 0.26 $ 0.23 $ 0.22 $ 0.21
Discontinued operations (0.01) (0.02) (0.05) --
----------- ----------- ----------- -----------
Diluted earnings per common share $ 0.25 $ 0.21 $ 0.17 $ 0.21
=========== =========== =========== ===========
</TABLE>
* Includes a $165,149 pretax, $107,347 after-tax, or $3.65 per share non-cash
ceiling write down of oil and gas assets.
The total of the earnings per share for the quarters does not equal the
earnings per share elsewhere in the Consolidated Financial Statements as a
result of the Company's issuance of additional shares of common stock during the
year.
40
<PAGE> 42
12. 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.
Except where otherwise provided by contractual agreement, future cash
inflows are estimated using year-end prices. Oil and gas prices at December 31,
1997 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 $2.50 and $3.54 at
December 31, 1997 and 1996, respectively, and oil prices were $15.15 and $22.45
at December 31, 1997 and 1996, respectively.
VPP volumes represent oil and gas reserves purchased from third parties
which generally entitle the Company to a specified volume of oil and gas to be
delivered over a stated time period. The related volumes stated herein reflect
scheduled amounts of oil and gas to be delivered to the Company at agreed
delivery points and future cash inflows are estimated at year-end prices.
Although specific terms of the Company's VPPs vary, the Company is generally
entitled to receive delivery of its scheduled oil and gas volumes, free of
drilling and lease operating costs and, in certain cases, free of state
severance taxes.
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 Year Ended December 31,
-----------------------------------
1997 1996 1995
--------- --------- ---------
(dollars in thousands)
<S> <C> <C> <C>
Revenue $ 137,837 $ 107,959 $ 85,424
Production (lifting) costs 35,266 11,693 6,623
Technical support and other 6,978 4,401 2,373
Depreciation, depletion and amortization 58,465 44,565 37,859
Writedown of oil and gas properties 165,149 -- --
--------- --------- ---------
Total expenses 265,858 60,659 46,855
--------- --------- ---------
Pretax income (loss) from producing activities (128,021) 47,300 38,569
Income tax provision (benefit) (48,344) 17,381 12,549
--------- --------- ---------
Results of oil and gas producing activities
(excluding corporate overhead and interest) $ (79,677) $ 29,919 $ 26,020
========= ========= =========
Capitalized costs incurred:
Property acquisition $ 70,364 $ 198,927 $ 77,515
Exploration 33,440 18,315 16,891
Development 107,424 54,889 26,859
--------- --------- ---------
Total capitalized costs incurred $ 211,228 $ 272,131 $ 121,265
========= ========= =========
Capitalized costs at year-end:
Proved properties $ 739,551 $ 544,213 $ 284,597
Unproved properties 21,080 10,574 7,297
--------- --------- ---------
760,631 554,787 291,894
Less accumulated depreciation, depletion and
amortization (356,877) (133,263) (86,936)
--------- --------- ---------
Net investment in oil and gas properties $ 403,754 $ 421,524 $ 204,958
========= ========= =========
</TABLE>
- --------------------------------------------------------------------------------
41
<PAGE> 43
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.
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
<TABLE>
<CAPTION>
December 31,
--------------------------
1997 1996
=========== ===========
(dollars in thousands)
<S> <C> <C>
Future cash inflows $ 1,092,271 $ 1,213,604
Future costs:
Production (371,762) (320,457)
Development (66,574) (43,882)
Discount - 10% annually (243,429) (291,653)
----------- -----------
Present value of future net revenues 410,506 557,612
Future income taxes, discounted at 10% (35,624) (120,013)
----------- -----------
Standardized measure of discounted future net cash flows $ 374,882 $ 437,599
=========== ===========
</TABLE>
Changes in Discounted Future Net Cash Flows From Proved Reserve Quantities
<TABLE>
<CAPTION>
For the Year Ended December 31,
-----------------------------------
1997 1996 1995
--------- --------- ---------
(dollars in thousands)
<S> <C> <C> <C>
Balance, beginning of year $ 437,599 $ 231,763 $ 179,660
Increases (decreases)
Sales, net of production costs (102,571) (96,266) (78,801)
Net change in prices, net of production costs (201,580) 50,328 9,593
Discoveries and extensions, net of future production and
development costs 101,004 67,791 22,417
Changes in estimated future development costs (18,912) 2,005 (862)
Change due to acquisition of reserves in place 40,509 292,557 108,798
Development costs incurred during the period 34,674 10,411 9,672
Revisions of quantity estimates (19,160) (45,003) (19,256)
Accretion of discount 55,761 29,108 24,033
Net change in income taxes 84,390 (60,691) 2,021
Sales of reserves in place (2,225) (11,507) (1,931)
Changes in production rates (timing) and other (34,607) (32,897) (23,581)
--------- --------- ---------
Net increase / (decrease) (62,717) 205,836 52,103
--------- --------- ---------
Balance, end of year $ 374,882 $ 437,599 $ 231,763
========= ========= =========
</TABLE>
- --------------------------------------------------------------------------------
42
<PAGE> 44
Reserve Information (Unaudited)
The following information with respect to the Company's 1997 net proved
oil and gas reserves are estimates based on reports prepared by KCS and other
independent petroleum engineers. The reports for the KCS Medallion Resources,
Inc.; KCS Mountain Resources, Inc.; KCS Resources, Inc.; and KCS Michigan
Resources, Inc. properties, which collectively represent 90% of total KCS
proved reserves at December 31, 1997, were audited by Netherland, Sewell &
Associates, Inc. pursuant to the principles set forth in the Standards
Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information
promulgated by the Society of Petroleum Engineers. 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>
1997 1996 1995
-------------------- -------------------- --------------------
Gas Oil Gas Oil Gas Oil
MMcf Mbbl MMcf Mbbl MMcf Mbbl
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Proved developed and undeveloped reserves
Balance, beginning of year 268,025 14,631 140,963 7,517 89,184 2,319
Production (43,700) (1,824) (25,581) (758) (19,129) (196)
Discoveries, extensions, ect 110,010 6,172 21,998 2,196 10,399 202
Acquisition of reserves in place 23,281 155 157,051 7,245 71,560 5,449
Sales of reserves in place (698) (23) (9,224) (492) (3,751) (3)
Revisions of estimates (30,750) (48) (17,182) (1,077) (7,300) (254)
-------- -------- -------- -------- -------- --------
Balance, end of year 326,168 19,063 268,025 14,631 140,963 7,517
======== ======== ======== ======== ======== ========
Proved developed reserves
Balance, beginning of year 236,454 12,133 121,987 3,808 74,215 1,336
-------- -------- -------- -------- -------- --------
Balance, end of year 234,091 13,008 236,454 12,133 121,987 3,808
======== ======== ======== ======== ======== ========
</TABLE>
13. Subsequent Events
On January 15, 1998, the Company completed a public offering of $125
million Senior Subordinated Notes at an interest rate of 8.875% due January 15,
2008. The net proceeds of approximately $121 million were used to pay down
borrowings under the bank credit facilities (See Note 6).
43
<PAGE> 45
PART III
Item 10 - Directors and Executive Officers of the Registrant, Item 11
Executive Compensation, Item 12 - Security Ownership of Certain Beneficial
Owners and Management, and Item 13 - Certain Relationships and Related
Transactions are incorporated by reference from the Company's definitive proxy
statement relating to its 1998 Annual Meeting of Stockholders.
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) Financial statements, financial statement schedules, and exhibits.
(1) The following consolidated financial statements of KCS and its
subsidiaries are presented in Item 8 of this Form 10-K.
Page
----
Report of Independent Public Accountants................................25
Statements of Consolidated Operations for the years ended
December 31, 1997, 1996 and 1995........................................26
Consolidated Balance Sheets at December 31, 1997 and 1996...............27
Statements of Consolidated Stockholders' Equity for the years
ended December 31, 1997, 1996 and 1995..................................28
Statements of Consolidated Cash Flows for the years ended
December 31, 1997, 1996 and 1995........................................29
Notes to Consolidated Financial Statements.........................30 - 43
(3) Exhibits
See "Exhibit Index" located on page 46 of this Form 10-K for a
listing of all exhibits filed herein or incorporated by reference to a
previously filed registration statement or report with the Securities
and Exchange Commission ("SEC").
(b) Reports on Form 8-K.
There were no reports on Form 8-K filed during the three months
ended December 31, 1997.
44
<PAGE> 46
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly
authorized.
KCS ENERGY, INC.
--------------------
(Registrant)
Date: 3/27/98 By: /s/ Frederick Dwyer
------- -----------------------
Frederick Dwyer
Vice President and Controller
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the Registrant and in the capacities on the dates indicated.
3/27/98 /s/ James W. Christmas
------- -------------------------------------
Date James W. Christmas, President
& Chief Executive Officer & Director
3/27/98 /s/ Stewart B. Kean
------- -------------------------------------
Date Stewart B. Kean, Chairman and Director
3/28/98 /s/ G. Stanton Geary
------- -------------------------------------
Date G. Stanton Geary, Director
3/26/98 /s/ James E. Murphy
------- -------------------------------------
Date James E. Murphy, Director
3/27/98 /s/ Robert G. Raynolds
------- -------------------------------------
Date Robert G. Raynolds, Director
3/27/98 /s/ Joel D. Siegel
------- -------------------------------------
Date Joel D. Siegel, Director
3/30/98 /s/ Christopher A. Viggiano
------- -------------------------------------
Date Christopher A. Viggiano, Director
/s/ Frederick Dwyer 3/27/98
- ------------------------------ -------
Frederick Dwyer Date
Vice President and Controller
45
<PAGE> 47
Exhibit Index
Exhibit
No. Description
------ -----------
(3) i Certificate of Incorporation of KCS filed as Exhibit 4.3
to Form S-8 Registration Statement No. 33-63982 filed with
SEC June 8, 1993.
ii By-Laws of KCS filed as Exhibit 4.4 to Form S-8
Registration Statement No. 33-63982 filed with SEC June 8,
1993.
(4) i Form of Common Stock Certificate, $0.01 Par Value, filed
as Exhibit 4 of Registrant's Form 10-K Report for Fiscal
1988.
ii Form of Common Stock Certificate, $0.01 Par Value, filed
as Exhibit 5 of Registrant's Form 8-A Registration
Statement No. 1-11698 filed with the SEC, January 27,
1993.
iii Indenture dated as of January 15, 1996 between KCS,
certain of its subsidiaries and Fleet National Bank of
Connecticut, Trustee, filed as Exhibit 4 to Current Report
on Form 8-K dated January 25, 1996.
iv Form of 11% Senior Note due 2003 (included in Exhibit (4)
(iii)).
(10) i Performance Unit Plan filed as Exhibit 10B of Registrant's
Form 10 filed with the SEC May 13, 1988.*
ii 1988 KCS Group, Inc. Employee Stock Purchase Program filed
as Exhibit 4.1 to Form S-8 Registration Statement No.
33-24147 filed with the SEC on September 1, 1988.*
iii Amendments to 1988 KCS Energy, Inc. Employee Stock
Purchase Program filed as Exhibit 4.2 to Form S-8
Registration Statement No. 33-63982 filed with SEC June 8,
1993.*
iv 1988 Stock Plan filed as Exhibit 10A of Registrant's Form
10 filed with the SEC May 13, 1988 and as Exhibit 4.1 to
Form S-8 Registration Statement No. 33-25707 filed with
the SEC on November 21, 1988.*
v KCS Group, Inc. Savings and Investment Plan filed as
Exhibit 4.1 to Form S-8 Registration Statement No.
33-28899 filed with the SEC on May 16, 1989.*
vi 1992 Stock Plan filed as Exhibit 4.1 to Form S-8
Registration Statement No. 33-45923 filed with the SEC on
February 24, 1992.*
vii Purchase and Sale Agreement dated as of November 30, 1995
between the Company and Hawkins Oil of Michigan, Inc.
(formerly Savoy Oil & Gas, Inc.), Conveyance of Production
Payment dated as of November 30, 1995, Production and
Delivery Agreement dated as of November 30, 1995, Option
Agreement dated as of November 30, 1995, Drilling
Participation Agreement dated December 7, 1995, Assignment
and Bill of Sale (Working Interests) filed with the SEC as
Exhibits 2.1 through 2.6 to Form 8-K on December 22, 1995.
viii Purchase and Sale Agreement dated September 8, 1995 by and
between Natural Gas Processing Co., a Wyoming corporation,
and KCS Resources, Inc., a Delaware corporation filed with
the SEC as Exhibit 2.1 to Form 8-K on November 22, 1995.
46
<PAGE> 48
ix Credit Agreement among KCS Resources, Inc., KCS Pipeline
Systems, Inc., KCS Michigan Resources, Inc. and KCS Energy
Marketing, Inc., Canadian Imperial Bank of Commerce, New
Agency, as Agent, CIBC Inc., as Collateral Agent, Bank
One, Texas, National Association, as Co-Agent, NationsBank
of Texas, N.A. as Co-Agent dated September 25, 1996.
x Guaranty by KCS Energy, Inc. in Favor of Canadian Imperial
Bank of Commerce, New York Agency, as Agent dated
September 25, 1996.
xi Stock Purchase Agreement by, between and among KCS Energy,
Inc., InterCoast Energy Company, and InterCoast Gas
Services Company dated November 14, 1996 filed with the
SEC as Exhibit 2.1 to Form 8-K/A on November 15, 1996.
xii Credit Agreement among KCS Medallion Resources, Inc., KCS
Energy, Inc., KCS Energy Services, Inc., Medallion Gas
Services, Inc., and GED Energy Services, Inc. and Canadian
Imperial Bank of Commerce, New York Agency, as Agent, CIBC
Inc., as Collateral Agent, NationsBank of Texas, N.A. as
Co-Agent dated January 2, 1997.
(21) Subsidiaries of the Registrant - filed herewith .
(23) i Consent of Arthur Andersen LLP - filed herewith.
ii Consent of Netherland, Sewell and Associates, Inc. - filed
herewith.
- ----------
* Management contract or compensatory plan or arrangement required to be filed
as an exhibit.
47
<PAGE> 1
Exhibit 21
KCS ENERGY, INC.
LIST OF WHOLLY-OWNED SUBSIDIARIES
KCS Resources, Inc.
National Enerdrill Corporation
Proliq, Inc.
KCS Energy Marketing, Inc.
KCS Michigan Resources, Inc.
KCS Energy Services, Inc.
KCS Medallion Resources, Inc.
Medallion California Properties, Inc.
Medallion Gas Services Company
48
<PAGE> 1
Exhibit 23(i)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our
report included in this Form 10-K, into KCS Energy, Inc.'s previously filed
Registration Statement File Nos. 33-25707, 33-28899, 33-45923 and 33-63982.
Arthur Andersen LLP
New York, New York
March 26, 1998
49
<PAGE> 1
Exhibit 23(ii)
CONSENT OF INDEPENDENT PETROLEUM ENGINEER
We hereby consent to the references to our firm and to our audit letter dated
March 13, 1998, of the estimates of the proved reserves of KCS Energy, Inc. in
the KCS Medallion Resources, Inc.; KCS Mountain Resources, Inc.; KCS Resources,
Inc.; and KCS Michigan Resources, Inc. properties, as of January 1, 1998 in the
Annual Report Form 10-K of KCS Energy, Inc. for the year ended December 31,
1997.
Netherland, Sewell and Associates, Inc.
Houston, Texas
March 30, 1998
50
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<CASH> 4,802
<SECURITIES> 0
<RECEIVABLES> 40,115
<ALLOWANCES> 0
<INVENTORY> 2,241
<CURRENT-ASSETS> 51,669
<PP&E> 786,618
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0
0
<COMMON> 312
<OTHER-SE> 144,758
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<SALES> 143,689
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<INCOME-PRETAX> (149,440)
<INCOME-TAX> (52,055)
<INCOME-CONTINUING> (97,385)
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<CHANGES> 0
<NET-INCOME> (92,083)
<EPS-PRIMARY> (3.19)
<EPS-DILUTED> (3.19)
</TABLE>
