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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
/ / ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1995
OR
/x/ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM OCTOBER 1, 1995 TO DECEMBER 31, 1995
(INCLUDING ANNUAL REPORT FOR THE FISCAL YEAR ENDED DECEMBER 31, 1995)
COMMISSION FILE NO. 1-11698
KCS Energy, Inc.
(Exact name of registrant as specified in its charter)
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<S> <C>
DELAWARE 22-2889587
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
</TABLE>
379 THORNALL STREET, EDISON, NEW JERSEY 08837
(Address of principal executive offices) (Zip code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (908) 632-1770
Securities registered pursuant to Section 12(b) of the Act:
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Title of Class Name of each exchange on which registered
-------------- -----------------------------------------
COMMON STOCK, par value $0.01 per share New York Stock Exchange
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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 (Section 229.045 of this chapter) is not contained herein,
and will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K. /x/
The aggregate market value of the 9,212,991 shares of the Common Stock held by
non-affiliates of the Registrant at the $14.50 closing price on March 1, 1996
was $133,588,370.
Number of shares of Common Stock outstanding as of the close of business on
March 1, 1996: 11,522,487
DOCUMENTS INCORPORATED BY REFERENCE
Part III incorporates information by reference to Notice of and Proxy
Statement for the 1996 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, 1995
PART I
Item 1. Business.
(a) General development of business
GENERAL
KCS Energy, Inc., "KCS" or the "Company", is an independent energy
company primarily engaged in the acquisition, exploration, development and
production of natural gas and crude oil. 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 to date have been focused on properties in the onshore Gulf
Coast region. The recently completed Rocky Mountain Acquisition has expanded the
Company's operations into certain major producing basins in Wyoming, Colorado
and Montana. At December 31, 1995, the Company had working interests in 901
producing wells (413 of which it operates). The Company augments its working
interest ownership of properties with a volumetric production payment program
that covers properties located primarily in the offshore Gulf Coast region and
in the Niagaran Reef trend in Michigan. As of December 31, 1995, approximately
76% of the Company's proved reserves were natural gas, of which approximately
78% were classified as proved developed.
The Company's largest single producing field is the Bob West Field in
south Texas, which accounted for approximately 34% of the Company's production
during 1995 from its interests in 48 wells (18 of which it operates).
Substantially all of the Company's natural gas sold from the Bob West Field is
covered by a take-or-pay contract (the "Tennessee Gas Contract") with Tennessee
Gas Pipeline Company that runs through January 1999 and is currently the
subject of litigation (See Item 3).
The Company also operates a natural gas transportation business and an
energy marketing and services business, which together contributed less than 5%
of the Company's operating income during 1995. As of December 31, 1995, the
natural gas transportation business consists of a 150-mile intrastate pipeline
system and related gathering lines located between Houston and Dallas, Texas
and 16 natural gas gathering systems in Texas, Montana and Louisiana. Through
its energy marketing and services business, the Company buys and resells
natural gas directly to industrial and commercial end users and also offers
energy supply, transportation and risk management services.
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BUSINESS STRATEGY
The Company has grown through a balanced strategy of reserve
acquisitions and exploratory and development drilling. The Company plans to
continue to broaden its reserve base and increase production and cash flow
through (i) the acquisition of attractively priced producing properties that
also provide additional development or exploratory potential, (ii) the
acquisition of natural gas and crude oil reserves through its volumetric
production payment program, (iii) the exploitation and development of its
existing asset base, and (iv) the pursuit of a balanced exploration program
that includes a number of high-potential opportunities.
To implement its strategy, the Company intends to take advantage of
several key strengths, including (i) an experienced and capable team of oil and
gas industry professionals with a large financial stake in the success of the
company, (ii) a high quality, diversified oil and gas reserve base, (iii) a
significant inventory of attractive development and exploratory drilling
opportunities within its existing property base and undeveloped acreage
position, (iv) an opportunistic volumetric production payment program, (v)
established relationships with proven industry partners that provide
opportunities to participate in a diverse group of exploration prospects
without having to expend the resources to develop comparable prospects
internally, (vi) a streamlined, efficient administrative and operating
structure that emphasizes a lean staff, operating in an entrepreneurial
environment, and (vii) a strong financial focus which manifests itself not only
in innovative and creative deal making, but in asset risk management and fiscal
discipline.
CHANGE IN FISCAL YEAR-END
The Company's Board of Directors approved a change of the Company's
fiscal year end from September 30 to December 31 in order to enhance
comparability of the Company's results of operations with those of its peers in
the energy industry. Financial statements and other information contained
herein have been recast to reflect calendar years.
RECENT ACQUISITIONS
Two significant acquisitions were completed during the last quarter of
1995. While these acquisitions had only a limited impact on 1995's results,
they are expected to add significantly to operations in 1996. See Note 11 to
Consolidated Financial Statements for further information regarding these
acquisitions.
SENIOR NOTES
On January 25, 1996, the Company completed the private sale of $150
million principal amount of 11% Senior Notes due 2003. The net proceeds to the
Company of approximately $145 million (after deducting expenses of the
offering) were utilized by the Company to reduce the outstanding indebtedness
under its current bank credit facilities and to repay a note recently sold to a
third party.
(b) Financial information about industry segments
Three-year financial data by business segment is contained in Note 9
to the Consolidated Financial Statements on page 35 of this Form 10-K.
(c) 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.
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During the three years ended December 31, 1995, the Company
participated in the drilling of 58 exploratory wells with a 50% success rate.
Discoveries included wells in the Bob West Field, Langham Creek Area and Laurel
Ridge Field. The Company's policy is to commit no more than 35% of its
operating cash flow to exploration activities and generally no more than
$750,000 for any single well. The 1996 budget for these operations is $15
million. The Company intends to drill on a wide variety of prospects, combining
low-risk with high-potential projects in order to maintain a balanced program
with the potential for significant reserve additions. Exploration activities
will focus primarily on properties located in the onshore Gulf Coast regions of
Texas and Louisiana. The Company plans to participate in as many as 30
prospects and continue significant 3- D and 2-D seismic data acquisition and
analysis during 1996. In addition, the Company intends to further analyze the
undeveloped acreage it acquired in the Rocky Mountain Acquisition for possible
exploration prospects as well as to participate in the Michigan exploration
program.
During the three years ended December 31, 1995, the Company
participated in the drilling of 61 development wells with a 98% success rate
that resulted in 60 successful completions. The majority of this development
has been in the Bob West Field in Texas.
The Company's development drilling budget for 1996 is $22 million,
approximately 40% of which is currently earmarked for development activities on
its new Rocky Mountain properties.
The Company is currently forcusing its Gulf Coast development
activities in three areas. The first is on acreage in the Langham Creek Area
in Harris County, Texas. This area produces from the Yegua and upper and
middle Wilcox sands. KCS owns working interests varying from 28% to 65% in a
6,200-acre block on which seven wells have been drilled to date. The
geological and geophysical evidence indicates the potential for as many as 10
to 12 additional drilling locations, with the upper Wilcox sands as the primary
target.
Development efforts are also underway in the Laurel Ridge Field in
Iberville Parish, Louisiana, where KCS made two significant discoveries in
1995, in what appears to be a large Frio field. This KCS-operated prospect has
significant development potential on a 3,800-acre lease block where KCS owns a
35% working interest (28% after payout). The initial discovery well went on
production in August 1995 and a second discovery well in a shallower zone was
completed in December. The Company is presently conducting additional seismic
work in the field and plans to drill a third well as soon as the seismic
evaluation is completed.
The third area of development involves the Glasscock Ranch Field in
Colorado County, Texas. KCS and its partners leased approximately 2,800 acres
and in 1994, drilled and completed the #5 Glasscock as a gas well in the upper
portion of the lower Wilcox sand section, a new reservoir for the field. KCS
has recently increased its working interest to approximately 65% and is
negotiating to acquire additional interests. A development program is planned
for 1996 which could include as many as 8 to 10 wells.
Volumetric Production Payment Program
The Company augments its working interest ownership of properties with
a volumetric production payment program, a method of acquiring oil and gas
reserves scheduled to be delivered in the future at a discount to the current
market price in exchange for an up-front cash payment. A volumetric production
payment is comparable to a term royalty interest in oil and gas properties and
entitles the Company to a priority right to a specified volume of oil and gas
reserves scheduled to be produced and delivered over a stated time period.
Although specific terms of the Company's volumetric production payments vary,
the Company is generally entitled to receive delivery of its scheduled oil and
gas volumes at agreed delivery points, free of drilling and lease operating
costs and, in certain cases, free of state severance taxes. The Company is not
the operator of any of the properties underlying its volumetric production
payments, and it does not bear any development or lease operating expenses.
After delivery of the oil or gas volumes to the Company or its designee, the
Company arranges for further downstream transportation and sells such volumes
to available markets. The Company believes that its volumetric production
payment program diversifies its reserve base and achieves attractive rates of
return while minimizing the Company's exposure to certain development,
operating and reserve volume risks. Typically, the estimated proved reserves of
the properties underlying a volumetric production payment are substantially
greater than the specified reserve volumes required to be delivered pursuant to
the production payment. Through December 31, 1995, the Company had invested
$63.2 million under the volumetric production payment program.
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
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historically been volatile and are expected by the Company to continue to be
volatile in the future. Prices for oil and gas are subject to wide fluctuation
in response to relatively minor changes in the supply of and demand for oil and
gas, market uncertainty and a variety of additional factors that are beyond the
Company's control. These factors include political conditions in the Middle
East and elsewhere, 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 Pipeline Company, accounted for
approximately 75% and 82% of the oil and gas exploration and production
business' revenue and 14% and 16% of the Company's consolidated revenue for the
years ended December 31, 1995 and 1994, respectively. See Item 3 for a
discussion of ongoing litigation with this customer. No other single customer
accounted for more than 10% of the Company's consolidated revenues in 1995 or
1994.
Oil and gas exploration and production operations accounted for 19% of
the Company's consolidated revenues and 96% of operating income for the year
ended December 31, 1995.
NATURAL GAS TRANSPORTATION OPERATIONS
The major asset related to the Company's natural gas transportation
operations is a 150-mile carbon steel intrastate pipeline system and related
gathering facilities (the "Pipeline System") located north of Houston, Texas.
The main line of the Pipeline System is approximately 80 miles long and
consists of 12-inch pipe with a wall thickness of 0.25 inch. The remainder of
the Pipeline System consists of lateral pipelines which connect to producing
wells; interstate and intrastate pipelines; an electric generating plant;
utility distribution systems; industrial and chemical facilities; a natural gas
liquefaction facility and two storage fields. Diameters of these laterals range
from 2 to 12 inches. The Pipeline System, which is connected to 13 intrastate
and interstate pipelines, is pledged as collateral for a bank credit facility.
The Company owns approximately 350 miles of gathering lines generally
associated with its wells, which connect producing fields with various natural
gas transmission lines and local distribution companies. Of the 16 gathering
systems, five are located in the Sweet Grass Arch basin in Montana and account
for 200 miles of the total, ten are located in Texas and one is located in
Louisiana.
The Company's natural gas transportation operations compete with other
pipeline companies for gas supplies and markets in a highly competitive
business.
For the year ended December 31, 1995, natural gas transportation
operations accounted for 6% of the Company's consolidated revenue and 4% of
operating income.
ENERGY MARKETING AND SERVICES OPERATIONS
The Company's energy marketing and services operations consist of three
principal activities: natural gas marketing, energy management services and
energy price risk management. For the year ended December 31, 1995, energy
marketing and services operations accounted for 80% of the Company's
consolidated revenue.
The Company's natural gas marketing operations are engaged in the
direct marketing of natural gas to industrial and commercial end-users. During
1995, the Company served approximately 325 customers in 34 states and Canada,
bought natural gas from over 165 domestic and Canadian suppliers and shipped
natural gas on over 90 different pipelines. Among the wide variety of services
that the Company offers are conventional spot or month-to-month sales, natural
gas storage, firm or high priority interruptible transportation contracts from
the supply region to the customer and long-term contracts. The Company's policy
to hedge or match any sales or purchase contract longer than 30 days. The
Company utilizes the NYMEX natural gas futures contract and swaps as pricing
and risk management tools.
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Through its energy management services operations, the Company offers
natural gas and fuel oil supply and transportation management and consulting
services to the cogeneration industry and to other major users of natural gas.
The Company coordinates transportation on interstate, intrastate and Canadian
pipelines and provides storage and alternate fuel management services.
The energy risk management operation provides assistance to the Company
in managing its energy price risk. It also offers a full range of
natural gas risk management services to its customers, including hedge program
design and consulting services, asset/liability management and brokerage to
natural gas producers, transporters, marketers, utilities and major energy
consumers in the U.S. and Canada.
The natural gas marketing operations compete with other direct marketing
firms, local gas distribution companies, and marketing affiliates of producers
and pipelines on the basis of reliability of supply, performance and price.
Competition is intense, margins are narrow and there continues to be
consolidation in the industry resutling in fewer but larger competitors. Gas
marketing requires liaison with interstate and intrastate pipelines and local
distribution companies to provide sources of competitively priced gas. Many
customers are large users of natural gas who have alternate fuel capability.
Raw Materials
The Company obtains its raw materials (principally natural gas) 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 segments or 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 any of its business segments or its business as a whole.
Seasonality
Demand for natural gas and oil is seasonal, principally related to weather
conditions and access to pipeline transportation.
Environmental Matters
Compliance with federal, state, and local government pollution control
regulations has not had, and is not expected to have, a material effect on the
Company's capital expenditures, earnings, or competitive position.
Employees
The Company and its subsidiaries employed a total of 105 persons on
December, 31, 1995. While certain employees perform duties in more than one
business segment, an approximate breakdown is as follows: Oil and Gas
Exploration and Production, 45; Natural Gas Transportation, 10; Energy
Marketing and Services, 41; and parent company, 9.
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Item 2. Properties.
WORKING INTEREST OIL AND GAS PROPERTIES
The following table sets forth data as of December 31, 1995 regarding
the number of gross producing wells and the estimated quantities of proved oil
and gas reserves attributable to the Company's principal properties in which it
owns working interests.
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ESTIMATED PROVED RESERVES
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GROSS
PRODUCING OIL NATURAL GAS TOTAL
Property/Area WELLS (Mbbls) (MMcf) (MMcfe) % OF TOTAL
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Onshore Gulf Coast:
Bob West Field . . . . . . 48 - 31,693 31,693 21%
Langham Creek Area . . . . 7 94 7,773 8,337 6%
Laurel Ridge Field . . . . 2 160 2,422 3,382 2%
Oletha Field . . . . . . . 7 3 6,038 6,056 4%
San Salvador Field . . . . 11 2 5,021 5,033 3%
Richardson-Mueller Field . 21 954 - 5,724 4%
Salem-McCan Field . . . . 46 176 2,471 3,527 2%
Bloomberg Areas . . . . . 10 39 2,500 2,734 2%
Glasscock Ranch . . . . . 10 83 2,657 3,155 2%
Others . . . . . . . . . 179 656 7,369 11,305 8%
---- --- ----- ------ ---
Subtotal . . . . . . . 341 2,167 67,944 80,946 54%
---- ----- ------ ------ ---
Rocky Mountain:
Big Horn Basin . . . . . 200 3,437 18,991 39,613 26%
San Juan Basin . . . . . 49 - 11,751 11,751 8%
Sweet Grass Arch. . . . . 178 554 1,255 4,579 3%
Green River Basin . . . . 82 35 4,419 4,629 3%
Others . . . . . . . . . 22 113 4,483 5,161 3%
-- --- ----- ----- --
Subtotal . . . . . . . 531 4,139 40,899 65,733 43%
---- ----- ------ ------ ---
Michigan
Niagaran Reef . . . . 29 188 3,136 4,264 3%
-- --- ----- ----- --
Total . . . . . . 901 6,494 111,979 150,943 100%
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Set forth below are descriptions of certain of the Company's
significant oil and gas producing properties.
ONSHORE GULF COAST PROPERTIES
Bob West Field. The Company has interests in approximately 863 gross
(599 net) acres in this field located in Zapata and Starr Counties, Texas. The
field produces natural gas from a series of more than 20 different upper Wilcox
sands with formation depths ranging from 9,500 to 13,500 feet that require
stimulation by hydraulic fracturing to effectively recover the reserves.
Because the majority of this field is situated under Lake Falcon on the Rio
Grande River, most wells must be drilled directionally under the lake from
common lakeshore drill sites. The Company owns interests in two principal areas
in the Bob West Field. Substantially all of this natural gas production is
covered by the Tennessee Gas Contract.
The Company owns a non-operated 25% working interest in production
subject to the Tennessee Gas Contract from the wells on the Guerra "A" and
Guerra "B" units which currently contain 31 producing wells, with one
additional well currently being drilled. Upon expiration of the Tennessee Gas
Contract, the Company will have the equivalent of a 12.5% working interest in
all production from these units.
The Company also owns a 100% working interest in and is the operator
for 511 acres referred to as the Falcon/Bob West property, where there are
currently 18 producing natural gas wells. The majority of the production from
this property is covered under the Tennessee Gas contract.
Langham Creek Area. This area is comprised of the Cypress, Cypress Deep
and Langham Creek Fields in western Harris County, Texas, where the Company has
non-operated interests in approximately 6,200 gross (2,755 net) acres. Multiple
horizons in this area produce natural gas and oil from Eocene age sandstones in
the Yegua formation from 6,000 to 7,500 feet and in the Wilcox formation from
9,000 to 13,000 feet.
The Company has an average net revenue interest of approximately 39% in
the seven wells in this area. The geological and geophysical evidence indicates
the potential for as many as 10 to 12 additional drilling locations, with the
upper Wilcox sands as the primary target.
Laurel Ridge Field. The Company is the operator of this field located
in Iberville Parish, Louisiana and has a 26% net revenue interest in 3,656
gross (1,279 net) acres around two discovery wells. The #1 Claiborne Plantation
was completed in August 1995 in the Cibicides Hazzardi (Frio) sand, and the
second discovery, the #2 Claiborne Plantation, was completed in December 1995
in the shallower Miogyp (Frio) formation. The third well is scheduled to be
spudded in April 1996.
Oletha Field. The Company has interests in 1,384 gross (622 net) acres
in this field located in Limestone County, Texas, which produces from multiple
horizons ranging in depth from 6,500 to 11,700 feet. The productive section of
the Oletha Field covers several thousand feet of normally pressured limestones
and sandstones from which dry natural gas is recovered. The Company's average
net revenue interest in this field is approximately 44%. The Company operates
four wells completed in the Travis Peak and Cotton Valley sands and has small
non-operated interests in five other wells. The Company is currently completing
another well, in which it has a 62% net revenue interest, testing deeper zones
on this acreage.
San Salvador Field. This field, located in Hidalgo County, Texas,
covers 1,000 gross (477 net) acres and produces from a series of multi-pay
lower Frio sands at depths ranging from 6,500 to 9,200 feet. As many as 12
separate reservoirs produce natural gas and condensate from normally pressured
Frio age sandstones. The Company's average net revenue interest is
approximately 36% in ten wells in the field.
Richardson-Mueller Field. The Company has a non-operated net revenue
interest of approximately 27% in this 3,600-acre oil field located in Montague
County, Texas. The field is the largest of four oil fields in the area
producing from the Caddo Lime formation at a depth of approximately 6,100 feet.
The field was discovered in 1943 and production reached a peak during 1952.
Subsequently, the field was depleted to an average reservoir pressure of less
than 300 psig, resulting in most of the original wells being plugged and
abandoned. Based on the historical success of waterflood projects in analogous
Caddo Lime fields, the first phase of an anticipated two phase waterflood
project was initiated in April 1994 by the field's operator. This phase affects
only about one-third of the field's total reservoir space and is located in the
north end of the field. Assuming the currently indicated response continues,
oil production rates from the first phase wells should begin increasing within
the next three to six months and are expected to peak in about three years. If
the first phase proves successful, a second phaseis expected to be initiated to
waterflood the remaining portion of the field to facilitate recovery of the
full volume of anticipated
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reserves.
Salem-McCan Field. This field, located in Victoria County, Texas, was
purchased in 1989 as the Company's first major acquisition. The field produces
oil and natural gas from a series of shallow Miocene and Frio sands at depths
from 600 to 4,000 feet, with the primary production coming from the Miocene.
The Company is the operator of this field and owns a 100% working interest in
2,619 acres, with an average net revenue interest of approximately 74%.
Bloomberg Area. The Company has interests in 1,280 gross (178 net)
acres in this area, which is comprised of the Bloomberg, North Bloomberg, South
Bloomberg, South and West Flores Fields located near the boundary of Starr
County and Hidalgo County, Texas. The producing reservoirs are a series of
Vicksburg sands at depths ranging from 8,400 to 11,000 feet. The production is
natural gas and condensate. Most of the wells require fracture stimulation and
the reservoir drive mechanism is pressure depletion. The Company's net revenue
interest is approximately 11% in ten non-operated wells in this area. One
additional well has been recently drilled and is currently awaiting completion.
Glasscock Ranch Field. Following the recent acquisition of the
interests of another joint interest owner, the Company now operates and owns an
average 67.2% net revenue interest in 10 wells in this field located in
Colorado County, Texas. The Glasscock Ranch wells produce high condensate
yield gas from a multiple series of Wilcox sands at depths ranging from 7,000
to at least 11,600 feet. The deeper sands have been less aggressively
exploited by past operators and will require hydraulic fracture stimulations in
order to achieve commercial production rates. However, the Company believes
these deeper sands hold a greater potential for significant reserve additions,
and has immediate plans to drill several deeper Wilcox test wells in 1996. If
successful, the Company would then anticipate commencing a multi- well drilling
program to more fully develop its 2,455 gross (2,025 net) acreage position
across this field.
ROCKY MOUNTAIN PROPERTIES
Big Horn Basin. The Company's interest in this basin located in Hot
Springs, Washakie, Bighorn and Park Counties, Wyoming covers 71,753 gross
(66,788 net) acres. The Company operates 76 wells and has additional interests
in 124 non-operated wells in a total of 17 fields. The major producing
properties in this basin are the Manderson/Ainsworth, which produces oil at
depths from 6,400 to 7,500 feet, the Golden Eagle, which produces natural gas
and oil at depths from 3,200 to 10,000 feet and the Sellers Draw, which produces
at depths from 10,000 to 19,000 feet. The Company believes that as many as 44
locations in this basin have development potential, but the timing of such
development will be dependent on the availability of capital resources and
market conditions.
San Juan Basin. The Company has an interest in 9,790 gross (5,247 net)
acres in this basin located in La Platta and Archuleta Counties, Colorado and
San Juan County, New Mexico. It operates 31 wells and has an interest in 17
non-operated wells in the Ignacio Field in Colorado as well as an interest in
one non-operated well in the Ute Dome Field in New Mexico. The wells produce
from the Dakota and Mesa Verde sands at depths ranging from 6,000 to 6,800
feet.
Sweet Grass Arch. The Company has an interest in 71,539 gross (46,519
net) acres in this basin, the majority of which is located in Toole County,
Montana. It currently operates 171 wells and has an interest in seven
non-operated wells. The major properties in this area are the Homestake and the
Homestake Unit, with 57 wells currently producing at depths ranging from 800 to
2,000 feet and the Conrad/Devon, with 62 wells currently producing from the Bow
Island sands at depths ranging from 800 to 1,500 feet. The Company has
identified 55
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locations in this basin that it believes have development potential, but the
timing of development will be dependent on the availability of capital
resources and market conditions. In addition to the existing production, the
Company owns five natural gas gathering systems consisting of approximately 200
miles of pipeline that currently gather approximately 1,700 Mcf per day of
third-party natural gas.
Green River Basin. This area is located in Carbon, Sweetwater and
Lincoln Counties, Wyoming and Moffat County, Colorado, where the Company has
an interest in 20,076 gross (16,884 net) acres. It operates 22 wells and has
non-operated interests in 60 wells in four major fields, with production at
depths ranging from 4,500 to 9,200 feet, primarily from the Mesa Verde,
Frontier, Dakota, Cherokee and Shimarup formations. The Company has identified
seven development locations and two recompletion opportunities in this basin,
but the timing of such projects will be dependent on the availability of
capital resources and market conditions.
VOLUMETRIC PRODUCTION PAYMENT AND UNDERLYING PRINCIPAL PROPERTIES
The following table shows as of December 31, 1995 the oil and gas
deliveries to the Company that are scheduled to be made pursuant to its
volumetric production payment program over the period from January 1, 1996
through December 31, 2006. Total future net cash flow to the Company from the
volumetric production payment deliveries scheduled below is estimated to be
$89.4 million based on prices in effect at December 31, 1995.
<TABLE>
<CAPTION>
CUMULATIVE
NATURAL GAS OIL TOTAL TOTAL
PERIOD (MMcf) (Mbbls) (MMcfe) (MMcfe)
------ ------ ------- ------- -------
<S> <C> <C> <C> <C>
1996 . . . . . . . . . . . . . . . . . . . . 11,168 219 12,482 12,482
1997 . . . . . . . . . . . . . . . . . . . . 7,518 205 8,748 21,230
1998 . . . . . . . . . . . . . . . . . . . . 3,907 162 4,879 26,109
1999 . . . . . . . . . . . . . . . . . . . . 1,588 117 2,290 28,399
2000 . . . . . . . . . . . . . . . . . . . . 1,263 86 1,779 30,178
2001 - 2006. . . . . . . . . . . . . . . . . 3,540 234 4,944 35,122
</TABLE>
The properties underlying the volumetric production payment program are
primarily located in two major regions, the offshore Gulf Coast and the
Niagaran Reef trend in northern and southern Michigan.
OFFSHORE GULF COAST PROPERTIES
The Company's offshore Gulf Coast properties are located in seven blocks
off the coast of Texas and Louisiana and two blocks off the coast of Alabama.
The Company's interests in the Texas and Louisiana blocks were all acquired
through volumetric production payment contracts with Hall-Houston Oil Company
("HHOC"), which is the operator. Pursuant to the HHOC volumetric production
payment, the Company received deliveries totaling 6,911 MMcf during 1995 and is
scheduled to receive 8,505 MMcf in 1996, 4,726 MMcf in 1997 and 1,684 MMcf in
1998.
The Company's interest in the two offshore Alabama blocks were acquired
through a volumetric production payment agreement with The Offshore Group,
which operates two wells located on these properties. The Company received
deliveries of 260 MMcf in 1994, 552 MMcf in 1995 and is scheduled to receive
deliveries totaling 616 MMcf in 1996 and 1997.
In addition, the Company is scheduled to receive volumes totaling 308
MMcfe during the period from 1996 to 1998 from several smaller volumetric
production payments covering onshore Gulf Coast and Appalachian properties.
9
<PAGE> 11
NIAGARAN REEF TREND PROPERTIES IN MICHIGAN
The Company's Michigan properties are located in the northern and
southern Niagaran Reef trend in Michigan. The volumetric production payment
reserves are expected to be produced largely from an existing group of 89 wells
located in 49 fields operated by a subsidiary of Hawkins Oil and Gas, Inc.,
("Hawkins"). Additional reserves available to support the production payment may
be derived from a series of recompletions and scheduled during 1996, and from
certain reserves to be developed by Hawkins in an area of mutual interest
covering the Niagaran Reef trend pursuant to an exploration program with a third
party. The Niagaran Reef reservoirs are typically found at depths between 4,000
and 6,500 feet. Of the 13.7 Bcf of natural gas and 1.1 MMbbls of oil covered by
the volumetric production payment, the Company is scheduled to receive 2,137
MMcf and 210 Mbbls in 1996, with the remaining volumes delivered between 1997
and 2006.
OIL AND GAS RESERVES
All information in this Form 10-K relating to estimates of the
Company's proved reserves not associated with the volumetric production payment
program is based on reports prepared by independent petroleum engineers
(principally R.A. Lenser and Associates, Inc. and H. J. Gruy and Associates,
Inc.) each in accordance with the rules and regulations of the Securities and
Exchange Commission. These independent reserve engineers' estimates were based
upon a review of production histories and other geologic, economic, ownership
and engineering data provided by the Company or third party operators.
The following table sets forth, as of December 31, 1995, summary
information with respect to (i) the estimates made by the independent reserve
engineers of the Company's proved oil and gas reserves attributable to working
interests and (ii) the reserve amounts contracted for pursuant to the agreements
relating to each volumetric production payment. 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,
1995
----
<S> <C>
PROVED RESERVES:
Oil (Mbbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,517
Natural gas (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . . 140,963
Total (MMcfe) . . . . . . . . . . . . . . . . . . . . . . . 186,065
Future net revenues ($000s) . . . . . . . . . . . . . . . . . . . . . $405,049
Present value of future net revenues ($000s) . . . . . . . . . . . . $291,085
PROVED DEVELOPED RESERVES:
Oil (Mbbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,808
Natural gas (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . . 121,987
Total (MMcfe) . . . . . . . . . . . . . . . . . . . . . . . 144,835
Future net revenues ($000s) . . . . . . . . . . . . . . . . . . . . . $335,403
Present value of future net revenues ($000s) . . . . . . . . . . . . $250,624
</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
many factors beyond the Company's control. Reserve engineering is a subjective
process of estimating 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.
10
<PAGE> 12
In accordance with SEC guidelines, the reserve engineers' and the
Company's estimates of future net revenues from the Company's proved reserves
and the present value thereof are made using oil and gas sales prices in effect
as of the dates of such estimates and are held constant throughout the life of
the properties except where such guidelines permit alternate treatment,
including, in the case of natural gas contracts, the use of fixed and
determinable contractual price escalations. The present value attributable to
the Company's proved reserves in the Bob West Field has been calculated based
in part on the contract price to be paid by Tennessee Gas. (See Item 3).
ACREAGE
The following table sets forth certain information with respect to the
Company's developed and undeveloped leased acreage as of December 31, 1995.
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
--------------- -----------------
GROSS NET GROSS NET
----- --- ----- ---
<S> <C> <C> <C> <C>
Texas . . . . . . . . . . . . . . . . . . 52,317 51,090 30,892 29,950
Wyoming . . . . . . . . . . . . . . . . . 67,574 60,239 47,139 45,757
Montana . . . . . . . . . . . . . . . . . 58,522 36,872 13,017 9,647
Colorado . . . . . . . . . . . . . . . . 10,990 6,510 - -
Michigan . . . . . . . . . . . . . . . . 2,400 183 - -
Louisiana . . . . . . . . . . . . . . . . 969 307 46,544 43,825
Other . . . . . . . . . . . . . . . . . 1,376 322 - -
----- --- - -
Total . . . . . . . . . . . . . 194,148 155,523 137,592 129,179
======= ======= ======= =======
</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, 1993,
1994 and 1995, is set forth below.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1995 1994 1993
---- ---- ----
TYPE OF WELL GROSS NET GROSS NET GROSS NET
------------ ----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Development:
Oil 1 0.4 - - - -
Natural gas 19 7.4 25 12.8 15 5.7
Non-productive - - - - 1 0.4
- - - - - ---
Total 20 7.8 25 12.8 16 6.1
== === == ==== == ===
Exploratory:
Oil 1 0.4 2 1.4 - -
Natural gas 12 4.3 11 2.6 3 1.2
Non-productive 8 5.3 15 4.1 6 1.8
- --- -- --- - ---
Total 21 10.0 28 8.1 9 3.0
== ==== == === = ===
</TABLE>
At December 31, 1995, the Company was participating in the drilling or
completion of 5 gross (1.9 net) wells.
11
<PAGE> 13
PRODUCTION AND SALES
The following table presents certain information with respect to oil
and gas production attributable to the Company's properties, average sales
prices and average production costs during the three years ended December 31,
1995, 1994 and 1993.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
Net natural gas produced (MMcf):
Tennessee Gas contract . . . . . . . . . 6,924 6,851 4,472
Other . . . . . . . . . . . . . . . . . . 12,205 4,453 2,505
------ ----- -----
Total . . . . . . . . . . . . . . 19,129 11,304 6,977
Average natural gas sales price ($ per Mcf):
Tennessee Gas contract . . . . . . . . . $7.90 $7.49 $7.09
Other . . . . . . . . . . . . . . . . . . $1.62 $1.81 $2.02
Average . . . . . . . . . . . . . . . . . $4.29 $5.54 $5.27
Net oil produced (Mbbls) . . . . . . . . . 196 211 179
Average oil sales price ($ per Bbl) . . . . $17.28 $15.16 $17.57
Gas equivalents produced (MMcfe) . . . . . 20,305 12,570 8,051
Average lifting costs ($ per Mcfe) . . . . $0.33 $0.56 $0.62
</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) and
in Houston, Texas (25,000 square feet). In Worland, Wyoming the Rocky Mountain
operations are based in a (10,000 square foot) Company-owned facility and in
Conroe, Texas, the intrastate transmission system operations are based in an
1,800 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.
Item 3. Legal Proceedings.
Information with respect to this Item is contained in Note 7 to the
Consolidated Financial Statements on pages 33 and 34 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,
1995.
12
<PAGE> 14
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 prices for the periods indicated:
<TABLE>
<CAPTION>
1995
----------------------------------------------------------------------------------------
Jan. - Mar. Apr. - June July - Sept. Oct. - Dec.
----------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Market Price
High $17.25 $22.25 $21.88 $16.75
Low 14.63 15.25 13.75 9.88
----------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
1994
----------------------------------------------------------------------------------------
Jan. - Mar. Apr. - June July - Sept. Oct. - Dec.
----------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Market Price
High $29.00 $26.38 $21.88 $18.75
Low 21.75 19.63 16.13 12.25
----------------------------------------------------------------------------------------
</TABLE>
There were 1,383 stockholders of record of the Company's Common Stock on
March 1, 1996.
The Company pays dividends on a quarterly basis. The aggregate amount
of dividends declared were $1,377,000 and $1,033,000 in 1995 and 1994,
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, 1995.
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------
Dollars in thousands (except
per share data) 1995 1994 1993 1992 1991
-------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Revenue $449,965 $341,713 $304,289 $154,279 $117,227
Net income 21,306 24,157 18,611 4,010 2,574
Total assets 360,609 214,423 165,990 88,220 72,077
Long-term debt 165,529 61,970 36,289 21,637 15,707
Stockholders' equity 101,576 80,668 59,765 30,233 26,317
Per common share:
Net income 1.81 2.05 1.60 0.36 0.24
Stockholders' equity 8.84 7.04 5.19 2.80 2.46
Dividends 0.12 0.09 0.06 0.03 0.01
===========================================================================================
</TABLE>
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.
RESULTS OF OPERATIONS -- CONSOLIDATED
Net income was $21.3 million ($1.81 per share) in 1995, which equates to
a 23.4% return on average equity. This compares to $24.2 million ($2.05 per
share) in 1994 and $18.6 million ($1.60 per share) in 1993. Lower natural gas
prices affected each of the Company's three operating businesses, and combined
with higher net interest costs incurred to fund the growth of the Company's oil
and gas exploration and production operations to reduce 1995 earnings. Milder
than normal winter weather conditions and an oversupply of natural gas during
the winter of 1994/1995 resulted in a 10% decline in average gas prices for the
Company's non-contract production in 1995, which reduced somewhat the benefits
of significantly increased gas production. The mild weather and lower gas
prices particularly affected the Company's energy marketing and services
operations, which posted a significant decline in operating income during 1995.
13
<PAGE> 15
The increase in earnings in 1994 compared to 1993 was due mainly to
increased natural gas production, principally from the Company's acreage in the
Bob West Field dedicated under the Tennessee Gas contract. See Note 7 to
Consolidated Financial Statements for information regarding the Tennessee Gas
contract.
The Company's Board of Directors approved a change of the Company's
fiscal year end from September 30 to December 31 in order to enhance
comparability of the Company's results of operations with those of its peers in
the energy industry. Financial statements have been recast to reflect calendar
years. The following discussion and financial information are based on
December 31 year-end periods.
RESULTS OF OPERATIONS -- BUSINESS SEGMENTS
Segment information reflects all volumes, revenue and expenses,
including those associated with transactions involving affiliates which are
eliminated in consolidation. Each of the Company's business segments was
adversely affected by low natural gas prices during most of 1995. Market prices
for natural gas are influenced by supply and demand factors for gas in the
U.S., Mexico and Canada, as well as prices of competing fuels. Average oil
prices are reflective of the world oil market during the periods. Market prices
for oil and gas, which are volatile in nature, have a significant impact on the
Company's revenue, net income and cash flow.
Oil and Gas Exploration and Production
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1995 1994 1993
-------------------------------------------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Revenue $83,284 $66,076 $40,455
Production (lifting) costs 6,623 7,063 5,011
Depreciation, depletion and amortization 37,988 18,538 7,004
Other operating expenses 1,941 2,671 1,785
----- ----- -----
Operating income $36,732 $37,804 $26,655
======= ======= =======
Oil production (Mbbl) 196 211 179
Natural gas production (MMcf):
Tennessee Gas contract 6,924 6,851 4,472
Non-contract 12,205 4,453 2,505
------ ----- -----
Total natural gas production 19,129 11,304 6,977
====== ====== =====
Average sales price:
Oil (per Bbl) $17.28 $15.16 $17.57
Natural gas (per Mcf) 4.29 5.54 5.27
Average lifting cost (per MMcfe) $ .33 $ .56 $ .62
DD&A as a percent of revenues 45.6% 27.9% 17.3%
===== ===== =====
</TABLE>
The 69% increase in natural gas production in 1995 compared to
1994 was due mainly to newly added properties not covered by the Tennessee Gas
contract. Approximately 7.4 Bcf of the increase in non-contract natural gas
production was attributable to the Company's volumetric production payment
program, with the remainder attributable to increased exploration and
development drilling, partially offset by the natural production decline in
existing wells and the sale of certain properties. Non-contract oil and gas
production accounted for 66% of total production in 1995, compared to 45% in
1994 and 44% in 1993. The increase in non-contract production as a percentage
of total production, while an integral part of the Company's overall growth
strategy, makes the Company more sensitive to fluctuations in the market price
of oil and gas. As such, while total production and revenue were up
significantly in 1995, a 10% decline in average non-contract natural gas prices
hindered the overall profitability of this segment. Average non- contract
natural gas prices were approximately $1.62 in 1995, compared to $1.81 in 1994
and $2.02 in 1993.
14
<PAGE> 16
Tennessee Gas contract production increased slightly in 1995 compared
to 1994 largely as a result of the continued development of the Bob West Field,
which was able to more than offset the normal production decline from existing
wells. With planned development of known producing horizons nearly completed,
the Company anticipates that, absent any new discoveries, it will not be able
to completely offset normal production declines and therefore 1996 production
from this field should be less than in 1995. Average sales prices under the
Tennessee Gas contract, excluding severance tax reimbursements, were $7.90 in
1995, $7.49 in 1994 and $7.09 in 1993. See Note 7 to Consolidated Financial
Statements for information regarding the Tennessee Gas contract.
While production subject to the Tennessee Gas contract is expected to
decline in 1996, the Company currently anticipates 1996 production from all
fields to increase approximately 65%.
The increase in depreciation, depletion and amortization ("DD&A") in
1995 reflected the increase in production, as well as an increase in the DD&A
rate. The DD&A rate reflects, among other things, the higher average oil and
gas property investment in 1995, lower gas prices and a relative increase in
the percentage of total proved reserves not covered by the Tennessee Gas
contract. In addition, the increase in the Company's reserves attributable to
the volumetric production payment program (which bear no lease operating
expenses) as a percentage of total reserves, contributed to the increase in the
DD&A rate. The effect of the higher DD&A rate was partially offset by a 41%
reduction in average lifting costs to $0.33 per Mcfe.
The significant growth of the oil and gas exploration and production
business in 1994 compared to 1993 was largely attributable to increased natural
gas production, principally as a result of the development of the Bob West
Field and as a result of acquisitions and further development of other
producing properties.
The increase in total costs and expenses in 1994 compared to 1993
reflected the significant expansion of oil and gas operations. Production costs
and DD&A increased mainly due to higher natural gas production.
Recent Acquisitions
Two significant acquisitions were completed during the last quarter of
1995 which, while they had only a minor impact on 1995's results, are expected
to add significantly to operations in 1996. See Note 11 to Consolidated
Financial Statements for further information regarding the acquisitions.
15
<PAGE> 17
Natural Gas TRANSPORTATION
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1995 1994 1993
---- ---- ----
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Revenue $26,722 $19,910 $16,480
Cost of natural gas sales 22,273 16,221 13,196
------ ------ ------
Gross margin 4,449 3,689 3,284
Depreciation 948 857 798
Other operating expenses 2,022 1,607 1,245
----- ----- -----
Operating income $1,479 $1,225 $1,241
====== ====== ======
Volume (Bcf) 25.9 20.9 24.3
Gross margin per Mcf $0.172 $0.176 $0.135
====== ====== ======
</TABLE>
The increases in 1995 compared to 1994 were largely due to the
expansion of the Company's existing pipeline and gathering systems, primarily
for the gathering of new natural gas volumes from a horizontal drilling play in
close proximity to the Company's existing pipelines. Higher gathering revenue
from the new system supply and the associated liquids profits was the primary
reason for the increase in operating income in 1995 as compared to 1994.
The increase in other operating expenses in 1995 compared to 1994 was
primarily due to costs associated with the expansion of gathering lines on the
Company's Texas intrastate pipeline and the timing of routine repairs and
maintenance.
The increase in gross margin in 1994 compared to 1993 was due mainly to
an increase in higher-margin transportation volumes from the Company's
gathering systems, along with higher margins on sales and transportation to
certain high-priority, weather-sensitive customers during the 1993/1994 peak
winter heating season. The increase in average per-unit margin more than offset
the effect of the lower volume. The higher costs and expenses in 1994 reflected
the growth in operations.
Energy Marketing and Services
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------
1995 1994 1993
---- ---- ----
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Revenue $359,620 $260,704 $249,017
Cost of natural gas sales 352,893 253,058 241,620
------- ------- -------
Gross margin 6,727 7,646 7,397
Operating expenses 6,642 5,843 5,060
----- ----- -----
Operating income $85 $1,803 $2,337
=== ====== ======
Volume (Bcf) 226.3 153.1 122.9
Gross margin per Mcf $0.030 $0.050 $0.060
Operating expense per Mcf $0.029 $0.038 $0.041
====== ====== ======
</TABLE>
While each of the Company's business segments were adversely
affected by low natural gas prices during most of 1995, the energy marketing
and services segment was impacted the most. The combination of (i) lower
natural gas prices, (ii) increased competitive pressures within the industry
and (iii) the absence of severe weather conditions during the peak 1994/1995
winter heating season and the related opportunities such conditions present
were the primary reasons for the decrease in operating income in 1995,
offsetting the benefit of higher marketing and services volumes. Average
natural gas sales prices for this segment were approximately 15 % lower in 1995
compared to 1994 and average per-unit gross margins were approximately 40%
lower.
16
<PAGE> 18
The increase in revenue in 1994 compared to 1993 was due in part to the
unusually cold 1993/1994 winter in the northeastern part of the United States.
During this period of high demand for natural gas, the Company successfully
obtained supply and transportation at competitive prices and sold a significant
portion of its natural gas in the northeastern markets at "peaking" rates. The
decrease in the gross margin per unit in 1994 reflected the sales to
higher-volume, lower-margin customers and the increase in volumes under
management which, by their nature, provided lower per-unit margins than natural
gas sales.
Operating expenses, while up in 1995 compared to 1994 due to expanded
activities, were significantly lower on a per-Mcf basis ($0.029 per Mcf in
1995 compared to $0.038 per Mcf in 1994).
The increase in operating costs in 1994 compared to 1993 reflected
higher personnel and marketing costs to support the significant growth in
operations.
Interest and Other Income, Net
Interest and other income was $3.7 million in 1995, compared to $1.0
million in 1994 and $0.7 million in 1993. Of the 1995 amount, $3.1 million was
interest income recorded on the difference between the full contract price and
the price paid currently by Tennessee Gas under interim agreements. See "--
Liquidity and Capital Resources" and Note 7 to Consolidated Financial
Statements. In addition, the Company had $0.6 million of income from other
investments. The 1994 increase over 1993 was primarily due to a one-time
receipt of $0.5 million for interest on funds that were previously held by the
operator of the jointly-owned wells covered by the Tennessee Gas contract.
Interest Expense
Interest expense was $7.7 million in 1995, compared to $2.9 million in
1994 and $2.0 million in 1993. These increases were primarily due to higher
average borrowings used to expand the Company's oil and gas exploration and
production operations, including acquisitions under its volumetric production
payment program which began in late 1994. In 1995, the increase in borrowings
was largely the result of interim agreements with Tennessee Gas, whereby the
Company received only partial cash payments from Tennessee Gas for sales of
natural gas production under the Tennessee Gas contract. See "-- Liquidity and
Capital Resources" and Note 7 to Consolidated Financial Statements. In the
interim, the Company has been utilizing its credit facilities to a larger
extent in order to finance its capital spending program. The increase in
interest expense was somewhat mitigated by the increase in interest income as
previously discussed. Higher average interest rates were also a contributing
factor in the year to year increases.
Income Taxes
The income tax provision was $10.6 million in 1995, representing an
effective tax rate of 33.2%, compared to 34.2% and 29.8% in 1994 and 1993,
respectively. See Note 6 to Consolidated Financial Statements for the
reconciliation of the statutory federal income tax rate to the Company's
effective tax rates. A substantial portion of the income taxes provided by the
Company during these periods is deferred to future years.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flow from Operating Activities
Net income adjusted for non-cash charges increased to $71.1 million in
1995, compared to $54.7 million in 1994. However, net cash provided by
operating activities in 1995 declined from $50.1 million in 1994 to $30.1
million, primarily as a result of interim agreements under which Tennessee Gas
has been paying $3.00 per MMBtu since September 17, 1994 for all gas taken
under the Tennessee Gas contract and bonding the balance, pending the outcome
of the litigation. See Note 7 to Consolidated Financial Statements. As a
result of the interim agreements, planned capital expenditures were partially
curtailed and the Company used its credit facilities to a larger extent in
order to finance its capital spending program.
17
<PAGE> 19
Prior to September 17, 1994, Tennessee Gas had been paying a price for
natural gas production from the dedicated leases based on Section 102(b)(2) of
the Natural Gas Policy Act of 1978 ("NGPA"), plus reimbursement for severance
taxes, subject to the right to recover any excess price if ultimately
successful in the litigation. As of December 31, 1995, the Company had recorded
cumulative revenue of approximately $155 million for natural gas sold under the
Tennessee Gas contract based on prices as defined in the contract, of which
approximately $112 million is at issue in the litigation.
The Company continues to accrue an accounts receivable amount (which
includes interest as provided for in the contract) due from Tennessee Gas that
reflects the difference between the amount that Tennessee Gas has paid for
natural gas under the interim agreements between the parties and the price that
would have been paid pursuant to the terms of the Tennessee Gas contract. As
of December 31, 1995, the total net receivable was $56.4 million. See Note 7
to Consolidated Financial Statements. If Tennessee Gas ultimately prevails in
this litigation, and depending on the amount of natural gas for which the
courts determine that Tennessee Gas should have paid the spot market price
rather than the contract price, the Company could be required (i) to write off
a portion or all of its accounts receivable that is attributable to Tennessee
Gas and (ii) to return a portion or all of the disputed amounts received (plus
interest if it is awarded by the court) to Tennessee Gas.
Trade accounts receivable increased $11.7 million and accounts payable
increased $15.3 million primarily due to the timing of cash receipts and cash
payments related to the high volume activity of the energy marketing and
services segment and, to a lesser extent, the timing of cash receipts and
payments of the oil and gas exploration and production operations.
Capital Expenditures
Capital expenditures in 1995 were $128.7 million, of which $121.3
million was invested in oil and gas properties. Of the $121.3 million, $43.8
million was for the purchase of oil and gas reserves under the Company's
volumetric production payment program, $33 million for the Rocky Mountain
acquisition and $19.4 million for the development of the Bob West Field. The
remainder was largely for lease acquisitions, seismic evaluations and
exploratory drilling ($16.9 million) and development drilling ($7.5 million) on
non-contract properties. The Company funded its capital expenditures with a mix
of additional borrowings under its credit facilities and internally generated
cash.
Capital expenditures in 1994 were $75.0 million, $73.7 million of which
was for oil and gas properties. Of these, $28.9 million was for development
drilling, primarily in the Bob West Field, $12.6 million for exploratory
drilling and $27.8 million for producing property acquisitions, including $19.5
million for the acquisition of oil and gas reserves through volumetric
production payments.
During 1993, the Company's capital spending totaled $48.5 million of
which $46.7 million was invested in oil and gas properties. This included $18.5
million for development drilling in the Bob West Field, $9.6 million for
development and exploratory drilling on other properties and $18.6 million for
acquisition of producing properties. The acquisitions were financed by a
combination of cash, seller-provided subordinated debt and issuance of 261,538
shares of KCS common stock.
Capital spending for 1996 has been initially set at $70 million,
primarily for the expansion of the oil and gas operations. The 1996 capital
expenditure budget includes approximately $22 million for development drilling
and $15 million for exploratory drilling, $30 million for acquisitions (working
interest acquisitions and volumetric production payments) and $3 million for
gathering facilities and other assets. The 1996 capital plan will be financed
largely through cash generated by operations and the sale of nonstrategic
assets.
18
<PAGE> 20
Debt Financing
On January 25, 1996, the Company completed the private sale of $150
million principal amount of 11% Senior Notes due 2003. The net proceeds to the
Company of approximately $145 million (after deducting expenses of the
offering) were utilized by the Company to reduce the outstanding indebtedness
under its current bank credit facilities and to repay a note recently sold to a
third party. Immediately following the sale of the Senior Notes and repayments
under other credit facilities, the Company had $34.8 million of availability
under its existing credit facilities. The Senior Notes are redeemable at the
Company's option in whole or in part at any time on or after January 15, 2000.
The indenture for Senior Notes contains certain typical financial and
restrictive covenants.
See Note 4 to Consolidated Financial Statements for information
regarding the new debt issue and the Company's other credit facilities.
Equity Availability
KCS has 5 million authorized but unissued shares of preferred stock and
approximately 38 million shares of common stock available for future equity
financing.
Impact of Recently Issued Accounting Standards
The Financial Accounting Standards Board issued Statement of Financial
Accounting Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to be Disposed Of." SFAS No. 121 is
effective for financial statements for fiscal years beginning after December
15, 1995. SFAS No. 121 is not anticipated to have a material impact on the
financial position or results of operations of the Company.
19
<PAGE> 21
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, 1995
and 1994, and the related statements of consolidated income, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1995. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of KCS Energy, Inc.
and subsidiaries as of December 31, 1995 and 1994, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1995 in conformity with generally accepted accounting principles.
Our audits were made for the purposes of forming an opinion on the
basic financial statements taken as a whole. The schedule listed in the
accompanying index is the responsibility of the Company's management and is
presented for purposes of complying with the Securities and Exchange
Commission's rules and is not part of the basic financial statements. This
schedule has been subjected to the auditing procedures applied in the audits of
the basic financial statements and, in our opinion, fairly states in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
New York, New York
February 29, 1996
20
<PAGE> 22
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
1995 1994 1993
----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenue $ 449,965 $ 341,713 $ 304,289
----------------------------------------------------------------------------------------------------------
Operating costs and expenses
Cost of gas sales 356,186 265,076 253,435
Other operating and administrative expenses 18,669 18,285 15,018
Depreciation, depletion and amortization 39,209 19,740 8,036
----------------------------------------------------------------------------------------------------------
Operating costs and expenses 414,064 303,101 276,489
----------------------------------------------------------------------------------------------------------
Operating income 35,901 38,612 27,800
Interest and other income, net 3,713 1,039 704
Interest expense (7,732) (2,938) (1,983)
----------------------------------------------------------------------------------------------------------
Income before income taxes 31,882 36,713 26,521
Federal and state income taxes 10,576 12,556 7,910
----------------------------------------------------------------------------------------------------------
Net income $ 21,306 $ 24,157 $ 18,611
----------------------------------------------------------------------------------------------------------
Earnings per share of common stock and common
stock equivalents $1.81 $2.05 $1.60
----------------------------------------------------------------------------------------------------------
Average shares of common stock and common stock
equivalents outstanding 11,760,701 11,804,989 11,658,370
----------------------------------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these financial statements.
21
<PAGE> 23
KCS ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
DECEMBER 31,
1995 1994
---- ----
<S> <C> <C>
ASSETS
Current assets
Cash and cash equivalents $5,846 $988
Trade accounts receivable, less allowance for doubtful
accounts --1995, $415; 1994, $305 58,052 46,380
Fuel inventories 782 2,509
Other current assets 3,374 4,148
- -------------------------------------------------------------------------------------------------------
Current assets 68,054 54,025
- -------------------------------------------------------------------------------------------------------
Property, plant and equipment
Oil and gas properties, full cost method, less accumulated DD&A --
1995, $86,936; 1994, $49,077 204,958 125,621
Natural gas transportation systems, at cost less accumulated
depreciation -- 1995, $4,285; 1994, $3,480 22,345 17,315
Other property, plant and equipment, at cost less accumulated
depreciation -- 1995, $1,472; 1994, $1,681 2,013 1,468
- -------------------------------------------------------------------------------------------------------
Property, plant and equipment, net 229,316 144,404
- -------------------------------------------------------------------------------------------------------
Other assets
Receivable from Tennessee Gas 56,437 13,569
Investments and other assets 6,802 2,425
- -------------------------------------------------------------------------------------------------------
Other assets 63,239 15,994
- -------------------------------------------------------------------------------------------------------
$360,609 $214,423
=======================================================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Current maturities of long-term debt $ - $1,035
Accounts payable 59,475 44,172
Accrued liabilities 4,926 6,172
- -------------------------------------------------------------------------------------------------------
Current liabilities 64,401 51,379
- -------------------------------------------------------------------------------------------------------
Deferred credits and other liabilities
Deferred federal and state income taxes 26,172 17,069
Other 2,931 3,337
- -------------------------------------------------------------------------------------------------------
Deferred credits and other liabilities 29,103 20,406
- -------------------------------------------------------------------------------------------------------
Long-term debt 165,529 61,970
- -------------------------------------------------------------------------------------------------------
Commitments and contingencies
- -------------------------------------------------------------------------------------------------------
Preferred stock, authorized 5,000,000 shares -- unissued -- --
Stockholders' equity
Common stock, par value $0.01 per share, authorized 50,000,000
shares, issued 12,379,885 and 12,344,278, respectively 124 123
Additional paid-in capital 24,910 23,895
Retained earnings 79,814 59,885
Less treasury stock, 892,748 and 890,248 shares, respectively -- at cost (3,272) (3,235)
- -------------------------------------------------------------------------------------------------------
Total stockholders' equity 101,576 80,668
- -------------------------------------------------------------------------------------------------------
$360,609 $214,423
=======================================================================================================
</TABLE>
The accompanying notes are an integral part of these financial statements.
22
<PAGE> 24
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY
(DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
Additional
Common Paid- in Retained Treasury Stockholders'
Stock Capital Earnings Stock Equity
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Balance at December 31, 1992 $116 $12,618 $18,825 $(1,326) $30,233
Stock issuances - option and benefit plans 4 1,019 - - 1,023
- acquisitions 3 6,176 - - 6,179
Tax benefit on stock option exercises - 3,473 - - 3,473
Net income - - 18,611 - 18,611
Dividends ($0.06 per share) - - (675) - (675)
- -------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1993 123 23,286 36,761 (1,326) 58,844
Stock issuances - option and benefit plans - 380 - - 380
Tax benefit on stock option exercises - 229 - - 229
Net income - - 24,157 - 24,157
Dividends ($0.09 per share) - - (1,033) - (1,033)
Purchase of treasury stock - - - (1,909) (1,909)
- -------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1994 123 23,895 59,885 (3,235) 80,668
Stock issuances - option and benefit plans 1 188 - - 189
Tax benefit on stock option exercises - 201 - - 201
Stock warrants issued - 626 - - 626
Net income - - 21,306 - 21,306
Dividends ($0.12 per share) - - (1,377) - (1,377)
Purchase of treasury stock - - - (37) (37)
- -------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1995 $124 $24,910 $79,814 $(3,272) $101,576
===============================================================================================================================
</TABLE>
The accompanying notes are an integral part of these financial statements.
23
<PAGE> 25
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
For the Years Ended December 31,
1995 1994 1993
----------------------------------------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income $21,306 $24,157 $18,611
Non-cash charges (credits):
Depreciation, depletion and amortization 39,209 19,740 8,036
Deferred income taxes 9,756 10,896 1,440
Other non-cash charges and credits, net 820 (65) (559)
- ------------------------------------------------------------------------------------------------------
71,091 54,728 27,528
Net changes in assets and liabilities:
Trade accounts receivable (11,672) 19,107 (36,153)
Receivable from Tennessee Gas (42,868) (13,569) -
Fuel inventories 1,727 (1,126) (417)
Other current assets 490 (1,299) 138
Accounts payable and accrued liabilities 14,163 (10,724) 29,023
Federal and state income taxes 178 (119) 1,615
Other, net (2,999) 3,118 (311)
- ------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 30,110 50,116 21,423
Cash flows from investing activities:
Investment in oil and gas properties (121,265) (73,682) (36,420)
Proceeds from the sale of oil and gas properties 4,069 - -
Investment in natural gas transportation systems (5,969) (700) (1,512)
Investment in other property, plant and equipment (1,465) (571) (344)
- ------------------------------------------------------------------------------------------------------
Net cash used in investing activities (124,630) (74,953) (38,276)
Cash flows from financing activities:
Proceeds from long-term debt 141,298 49,431 18,000
Repayments of long-term debt (38,774) (26,247) (3,956)
Issuance of common stock 189 380 1,023
Issuance of stock warrants 626 - -
Tax benefit on stock option exercises 201 229 3,473
Purchase of treasury stock (37) (1,909) -
Dividends paid (1,377) (919) (554)
Deferred financing costs and other, net (2,748) (509) (56)
- ------------------------------------------------------------------------------------------------------
Net cash provided by financing activities 99,378 20,456 17,930
- ------------------------------------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents 4,858 (4,381) 1,077
Cash and cash equivalents at beginning of year 988 5,369 4,292
- ------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of year $5,846 $988 $5,369
======================================================================================================
</TABLE>
The accompanying notes are an integral part of these financial statements.
24
<PAGE> 26
KCS ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
KCS Energy, Inc. is principally engaged in the acquisition,
exploration, development and production of natural gas and crude oil. The
Company also operates natural gas transportation and energy marketing and
services businesses.
Recapitalization (Quasi-reorganization)
At September 30, 1988, prior to the start of the Company's first full
year of operations as a separate legal entity with independent management, an
amount equal to the cumulative retained earnings deficit of the KCS
subsidiaries ($25,109,000) was eliminated against additional paid-in capital in
connection with a quasi-reorganization.
Basis of Presentation
The consolidated financial statements include the accounts of KCS
Energy, Inc. and its wholly owned subsidiaries ("KCS" or "Company"). All
significant intercompany accounts and transactions have been eliminated in
consolidation. Certain previously reported amounts have been reclassified to
conform to current year presentations.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates. The most
significant estimates and assumptions impacting the Company's consolidated
financial statements relate to the Tennessee Gas contract. See Note 7.
Cash Equivalents
The Company considers all highly liquid investments with a maturity of
three months or less when purchased to be cash equivalents.
Futures Contracts
The Company utilizes oil and natural gas futures contracts for the
purpose of hedging the risks associated with fluctuating crude oil and natural
gas prices and accounts for such contracts in accordance with FASB Statement
No. 80, "Accounting for Futures Contracts." These contracts permit settlement
by delivery of commodities and, therefore, are not financial instruments, as
defined by FASB Statement Nos. 107 and 119. At December 31, 1995, the Company's
hedging activities consisted of 700 long contracts at an average price of $1.82
per Mcf and 587 short contracts at an average price of $1.95 per Mcf maturing
through 1996, covering 12,870 MMcf of natural gas. At December 31, 1994, the
Company's hedging activities consisted of 760 long contracts at an average
price of $1.93 per Mcf and 305 short contracts at an average price of $1.95 per
Mcf maturing through 1995 and 1996, covering 10,650 MMcf of natural gas. 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 losses, net
of deferred gains, were $0.1 million at December 31, 1995. Deferred gains, net
of deferred losses, were $1.4 million at December 31, 1994.
Imbalances
The Company follows the entitlements method of accounting for
production imbalances, where revenues are recognized based on its interest in
oil and gas production from a well. Imbalances arise when a purchaser takes
delivery of more or less from a well than the Company's actual interest in the
production from that well. The difference between cash received and revenue
recorded is a receivable or payable. Such imbalances are reduced either by
subsequent balancing of over and under deliveries or by cash settlement, as
required by applicable contracts. Such imbalances were not material at December
31, 1995 or 1994.
25
<PAGE> 27
Property, Plant and Equipment
The Company follows the full cost method of accounting, under which all
productive and nonproductive costs associated with its exploration, development
and production activities are capitalized in a country-wide cost center. Such
costs include lease acquisitions, geological and geophysical services,
drilling, completion, equipment and certain general and administrative costs
directly associated with acquisition, exploration and development activities.
General and administrative costs related to production and general overhead are
expensed as incurred. The Company provides for depreciation, depletion and
amortization of evaluated costs using the future gross revenue method based on
recoverable reserves valued at current prices. Under accounting procedures
prescribed by the Securities and Exchange Commission ("SEC"), capitalized costs
may not exceed the present value of future net revenues from production of
proved oil and gas reserves. To the extent that the capitalized costs exceed
the estimated present value of future net revenues at the end of any fiscal
quarter, such excess costs are written down with a corresponding charge to
income.
Depreciation of other property, plant and equipment is provided on a
straight-line basis over the useful lives of the assets, except for certain
natural gas gathering pipelines which are depreciated based on the estimated
lives of the gas wells served. Repairs of all property, plant and equipment and
replacements and renewals of minor items of property are charged to expense, as
incurred.
Income Taxes
The Company accounts for income taxes in accordance with FASB Statement
No. 109, "Accounting for Income Taxes." Deferred income taxes reflect the
future tax consequences of differences between the tax bases of assets and
liabilities and their financial reporting amounts at each year end.
For income tax purposes, the Company deducts the difference between
market value and exercise price arising from the exercise of stock options.
The tax effect of this deduction which, for financial reporting purposes, is
accounted for as an increase to additional paid-in capital, amounted to
$201,000, $229,000 and $3,473,000 in 1995, 1994 and 1993, respectively.
Earnings Per Share
Earnings per share have been computed by dividing net earnings by the
weighted average number of common shares outstanding during the periods,
adjusted for the dilutive effects of stock options and warrants.
Supplemental Cash Flow Disclosures
The Company acquired certain producing properties during 1993. The
related non-cash investing and financing activities are summarized as follows:
<TABLE>
<CAPTION>
DOLLARS IN
THOUSANDS
---------
<S> <C>
Investment in oil and gas properties . . . . . . . . . . . . . . . . . . $(10,179)
Subordinated note payable assumed . . . . . . . . . . . . . . . . . . . . 4,000
Issuance of common stock . . . . . . . . . . . . . . . . . . . . . . . . 6,179
</TABLE>
26
<PAGE> 28
2. RETIREMENT BENEFIT PLANS
The Company has a trusteed, non-contributory Retirement Plan ("Plan").
The Plan was amended to freeze the accrual of future benefits as of October 31,
1991. Prior to October 1991, the Plan covered substantially all full-time
employees of KCS and its participating subsidiaries. The Company's funding
policy for the Plan is to make annual contributions that meet the minimum
funding requirements of the Employee Retirement Income Security Act of 1974.
The required contribution was $49,924 in 1993. No contributions were required
in 1995 and 1994.
Net periodic pension costs consisted of the following components:
<TABLE>
<CAPTION>
1995 1994 1993
---- ---- ----
DOLLARS IN THOUSANDS
<S> <C> <C> <C>
Service cost -- benefits earned during the period . . . $0 $0 $0
Interest cost on projected benefit obligation . . . . . 69 66 75
Actual return on plan assets . . . . . . . . . . . . . (4) 78 (360)
Net amortization and deferral . . . . . . . . . . . . . (64) (153) 340
---- ----- ----
Net periodic pension cost (income) . . . . . . . . . . $1 $(9) $55
=== ==== ====
</TABLE>
The following table sets forth the funded status and amounts
recognized in the consolidated balance sheets at December 31, 1995 and 1994 for
the Plan:
<TABLE>
<CAPTION>
1995 1994
---- ----
DOLLARS IN THOUSANDS
<S> <C> <C>
Actuarial present value of benefit obligations:
Vested benefits . . . . . . . . . . . . . . . . . . . . . . $969 $980
Non-vested benefits . . . . . . . . . . . . . . . . . . . . -- 18
-- ---
Accumulated benefit obligation . . . . . . . . . . . . . . 969 998
Projected benefit obligation . . . . . . . . . . . . . . . . 969 998
Market value of plan assets . . . . . . . . . . . . . . . . . 1,157 1,272
Excess of plan assets over projected benefit obligation . . . 188 274
Unrecognized net loss . . . . . . . . . . . . . . . . . . . . 199 143
Unrecognized net asset at January 1 . . . . . . . . . . . . . (82) (100)
---- -----
Pension prepayment in the balance sheet . . . . . . . . . . . $305 $317
===== =====
</TABLE>
Assumptions used for the 1995 and 1994 actuarial calculations
were 7% for the discount rate and expected long-term return on assets. As a
result of the October 31, 1991 freeze of future benefits, no service costs
accrued during the periods. During 1995, the Company made lump-sum cash
payments to terminated participants which represented a settlement of projected
benefit obligations. Plan assets at December 31, 1995 are invested in both cash
equivalents and KCS Energy, Inc. Common Stock.
The Board of Directors took action to terminate the Plan effective
September 30, 1995. The Company has filed all required standard termination
applications with both the Internal Revenue Service and the Pension Benefit
Guaranty Corporation. A complete settlement of the Plan's projected benefit
obligations is expected to occur during 1996.
The Company sponsors a Savings and Investment Plan ("Savings Plan")
under Section 401(k) of the Internal Revenue Code. Eligible employees may
contribute up to 16% of their base salary to the Savings Plan subject to
certain IRS limitations. The Company may make matching contributions, which
have been set by the Board of Directors at 50% of the employee's contribution
(up to 6% of annual base compensation) since the inception of the Savings Plan
in June 1988. The Savings Plan also contains a profit-sharing component whereby
the Board of Directors may declare annual discretionary profit-sharing
contributions. Profit-sharing contributions are allocated to each eligible
employee. Employee and profit-sharing contributions are invested at the
direction of the employee in one or more funds or can be directed to purchase
common stock of the Company at fair market value. Company matching
contributions are invested in shares of KCS common stock. Eligible employees
vest in both the Company matching and discretionary profit-sharing
contributions over a four-year period based upon their years of service with
the Company. Company contributions to the Savings Plan were $253,666 in 1995,
$293,622 in 1994 and $282,232 in 1993.
27
<PAGE> 29
3. STOCK OPTION AND INCENTIVE PLANS
The Company has two employee stock option and incentive plans, the 1988
Stock Plan and the 1992 Stock Plan (the "Employee Incentive Plans"). Under the
Employee Incentive Plans, stock options, stock appreciation rights and
restricted stock may be granted to employees of KCS. The 1992 Stock Plan also
provides that bonus stock may be granted to employees.
The 1994 Directors' Stock Plan provides that each non-employee director
be granted stock options for 1,000 shares annually. This plan also provides
that in lieu of cash, each non-employee director be issued KCS stock with a
fair market value equal to 50% of their annual retainer.
Each plan provides that the option price of shares issued be equal to
the market price on the date of grant. All options expire 10 years after the
date of grant. At December 31, 1995, options for 405,500 shares were
exercisable.
Transactions during the last three years involving stock options under
the above plans are summarized as follows:
<TABLE>
<CAPTION>
NUMBER OF OPTION PRICE
SHARES PER SHARE
------ ---------
<S> <C> <C>
Options outstanding, December 31, 1992 . . . . . . . . 792,200 $1.21 - $ 6.25
1993 -- Granted . . . . . . . . . . . . . . . . . . . . 106,700 $22.88
-- Exercised . . . . . . . . . . . . . . . . . . . (419,200) $1.21 - $ 6.25
1994 -- Granted . . . . . . . . . . . . . . . . . . . . 106,000 $14.50 - $26.88
-- Exercised . . . . . . . . . . . . . . . . . . . (32,200) $1.33 - $ 6.25
1995 -- Granted . . . . . . . . . . . . . . . . . . . . 105,000 $13.00 - $16.31
-- Exercised . . . . . . . . . . . . . . . . . . . (22,600) $1.33 - $ 1.98
-- Forfeited . . . . . . . . . . . . . . . . . . . (3,100) $22.88 - $26.88
------- ---------------
Options outstanding, December 31, 1995 . . . . . . . . 632,800 $1.50 - $26.88
======== ==============
</TABLE>
Restricted shares awarded under the Employee Incentive Plans have
a fixed restriction period during which ownership of the shares cannot be
transferred and the shares are subject to forfeiture if employment terminates.
Restricted stock has the same dividend and voting rights as other common stock
and is considered to be currently issued and outstanding. The cost of the
awards, determined as the fair market value of the shares at the date of grant,
is expensed ratably over the period the restrictions lapse. This cost was
immaterial during the three years ended December 31, 1995. Restricted stock
totaling 11,200 shares was outstanding under the Employee Incentive Plans at
December 31, 1995.
Bonus stock awards under the 1992 Stock Plan convert to shares of
restricted stock if certain three-year performance goals are met. The
restricted stock then vests over a two-year period. The cost of the awards is
expensed ratably based on the current market price of the Company's common
stock and the extent to which the performance goals are being met. This cost
was immaterial in 1995 and 1994 and amounted to $200,000 in 1993. Bonus stock
grants totaling 48,800 shares were outstanding at December 31, 1995.
At December 31, 1995, 49,402 shares were available for future grants
(including bonus stock awards) under the Employee Incentive Plans.
Under the 1988 KCS Energy, Inc. Employee Stock Purchase Program (the
"Program"), all eligible employees and directors may purchase full shares from
the Company at a price per share equal to 90% of the market value per share
determined by the closing price on the date of purchase. The minimum purchase
is 25 shares. The maximum annual purchase is the number of shares costing no
more than 10% of the eligible employee's annual base salary, and for directors,
3,000 shares. The number of shares issued in connection with the Program was
6,897, 7,438 and 26,845 during 1995, 1994 and 1993, respectively. At December
31, 1995, there were 443,695 shares available for issuance under the Program.
28
<PAGE> 30
4. LONG-TERM DEBT
Long-term debt consists of the FOLLOWING:
<TABLE>
<CAPTION>
DECEMBER 31,
------------
1995 1994
---- ----
DOLLARS IN THOUSANDS
<S> <C> <C>
Master Note Facility . . . . . . . . . . . . . . . . . . . . . $76,255 $46,400
Receivables Facility . . . . . . . . . . . . . . . . . . . . . 26,900 --
VPP Facility . . . . . . . . . . . . . . . . . . . . . . . . . 38,000 --
Note Financing . . . . . . . . . . . . . . . . . . . . . . . . . 24,374 --
Revolving Credit Agreement . . . . . . . . . . . . . . . . . . -- 15,431
Subordinated Note Payable . . . . . . . . . . . . . . . . . . . -- 910
Installment note payable to bank due in equal monthly
installments, with interest at 10.5% . . . . . . . . . . . . -- 264
-- ---
165,529 63,005
Less current maturities . . . . . . . . . . . . . . . . . . . . -- 1,035
-- -----
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . $165,529 $61,970
======== =======
</TABLE>
SENIOR NOTES
On January 25, 1996, subsequent to the year ended December 31, 1995,
KCS Energy, Inc. (the "Parent") completed a Rule 144A private offering of $150
million senior notes at an interest rate of 11% due January 15, 2003 (the
"Senior Notes"). The Senior Notes are noncallable for four years and are
unsecured obligations of the Parent. Prior to January 15, 1999, the Parent may
use proceeds from a public equity offering to redeem up to $35 million of the
Senior Notes. The subsidiaries of the Parent have guaranteed the Senior Notes
on a senior unsecured basis. The net proceeds of approximately $145 million
were used to reduce the amounts outstanding under certain of the agreements
discussed below.
The Senior Notes contain certain restrictive covenants which, among
other things, limit the Company's ability to incur additional indebtedness,
require the repurchase of the Senior Notes upon a change of control and
restrict the aggregate cash dividends paid to 50% of the Company's cumulative
net income during the period beginning October 1, 1995. Additionally, the
Master Note Facility, Receivables Facility and VPP Facility agreements
summarized below were amended to permit the borrowers under the agreements to
guarantee the Senior Notes and to remove restrictions on subsidiary dividends
to the Parent.
MASTER NOTE FACILITY
The Master Note Facility ("Facility"), which matures on October 1,
1998, is used primarily for the expansion of the Company's exploration and
production and natural gas transportation businesses. As such, borrowings under
the Facility are limited to certain KCS subsidiaries ("Borrowers") which are
engaged in those activities. The borrowing base, or actual availability under
the Facility, increased from $64 million at December 31, 1994 to $100 million
at December 31, 1995. As of December 31, 1995, $76.3 million was outstanding
under the facility and $11.1 million was reserved pursuant to existing letters
of credit. The borrowing base is reviewed at least semiannually and may be
adjusted based on the lenders' valuation of the Borrowers' oil and gas
reserves, pipeline assets and other factors. Substantially all of the
Borrowers' oil and gas reserves (excluding those acquired through volumetric
production payments) and pipeline assets have been pledged to secure the
Facility.
The Facility permits the Borrowers to choose interest rate options
based on the bank's prime rate or LIBOR and from maturities ranging up to three
months. A commitment fee of one-half of one percent is paid on the unused
portion of the borrowing base. The weighted average effective interest rate was
7.98% in 1995 and 6.13% in 1994. As of December 31, 1995, the weighted average
effective interest rate on the borrowings was 8.66%.
Immediately following the sale of the Senior Notes, the Facility was
amended to decrease the borrowing base to $20 million. The amount outstanding
under the Facility was reduced to $2 million and $11.1 million was reserved
pursuant to existing letters of credit.
29
<PAGE> 31
REVOLVING CREDIT FACILITIES
Revolving Credit Agreement
During 1994, the Company's natural gas marketing subsidiary had a
Revolving Credit Agreement ("Agreement") that was used primarily for working
capital purposes and the purchase of oil and gas reserves through volumetric
production payments and was secured by that subsidiary's trade accounts
receivable and other assets.
The Agreement was replaced with two new revolving credit facilities,
the Receivables Facility and the VPP Facility. At December 31, 1994, $15.4
million was reflected as outstanding under the Agreement. On January 12, 1995,
the Company paid in full all outstanding balances and terminated the Agreement.
The weighted average effective interest rate was 8.87% in 1995 and 7.97% in
1994.
Receivables Facility
The Receivables Facility matures in June 1997 and is secured by the
natural gas marketing subsidiary's accounts receivables and other assets
(excluding those pledged under the VPP Facility) and a pledge of the natural
gas marketing subsidiary's stock. In August 1995, the maximum credit limit
under the Receivables Facility was increased from the initial $25 million to
$35 million. Under the terms of the Receivables Facility, the subsidiary may
borrow the lesser of the credit limit or the borrowing base supported by
Eligible Receivables, as defined by the lender. The borrowing base is reviewed
on a monthly basis. As of December 31, 1995, the borrowing base and outstanding
balance was $26.9 million.
The Company may choose to borrow funds based on either the lender's
"Base Rate" or the 30-day LIBOR. A commitment fee of one-half of one percent is
paid on the average daily unused portion of the credit limit. The weighted
average effective interest rate was 7.64% in 1995. On December 31, 1995, the
weighted average effective interest rate on outstanding borrowings was 7.60%.
Proceeds from the sale of the Senior Notes were used to decrease the
amount outstanding under the Receivables Facility to $23.4 million. The
borrowing base of the Receivables Facility was unaffected by the sale of the
Senior Notes.
VPP Facility
The VPP Facility matures in January 1999 and is secured by all of the
oil and gas reserves purchased through volumetric production payments. The
initial maximum credit commitment under this facility of $25 million was
increased in December 1995 to $50 million and the borrowing base was increased
to $38 million. The borrowing base is reviewed at least semiannually and may be
subject to change based upon the lenders' evaluation of the oil and gas
reserves and other factors. The outstanding balance under the VPP Facility was
$38 million on December 31, 1995.
Under the VPP Facility, the Company can request advances based upon
either the prime rate, certificates of deposit rate or LIBOR with maturities
ranging up to three months. A commitment fee of one-half of one percent is paid
on the average daily unused portion of the borrowing base. The weighted average
effective interest rate was 8.17% in 1995. As of December 31, 1995, the
weighted average effective interest rate on outstanding borrowings was 8.11%.
Proceeds from the sale of the Senior Notes were used to decrease the
amount outstanding under the VPP Facility to $1.0 million. The VPP Facility's
borrowing base was unaffected by the sale of the Senior Notes.
NOTE FINANCING
On November 17, 1995, the Parent entered into a $25 million Note
Financing Agreement ("Note Financing"), secured by all of the assets of the
Parent other than the capital stock of its marketing subsidiary. The proceeds
from the Note Financing were used to fund the Company's oil and gas property
acquisitions and for general corporate purposes.
30
<PAGE> 32
The Note Financing, which was paid in full with the proceeds of the
Senior Notes, accrued interest at the rate of 12% per annum.
The Parent also issued to the purchaser under the Note Financing (with
an option to buy back at 150% of the exercise price within 12 months and 175%
between 12 and 24 months) a warrant to purchase 114,683 shares of the Parent's
common stock exercisable at a price of $11.65 per share, subject to adjustment
to prevent dilution. These warrants expire on November 16, 2000.
OTHER INFORMATION
KCS Energy, Inc. has guaranteed the obligations of its subsidiaries
under the above agreements. The agreements contain certain restrictive
covenants which, among other things, require the Company to maintain minimum
levels of working capital, cash flow and tangible net worth, as defined in the
agreements. In addition, the Company is restricted from incurring indebtedness
in excess of $225 million, and the ability to pay cash dividends is limited by
these agreements.
The Company had a subordinated short-term note payable, which was
issued in conjunction with a 1993 acquisition of producing properties. The
balance was paid in full during fiscal year 1995. This note, payable in monthly
installments, accrued interest at prime plus one percent.
Long-term debt is carried at an amount approximating fair value because
its interest rates are based on current market rates.
Long-term debt due during the fiscal years ending December 31, 1996 to
2000, is as follows: $-0- in 1996, $51,900,000 in 1997, $76,255,000 in 1998,
$38,000,000 in 1999 and $-0- in 2000. Reflecting the issuance of the Senior
Notes on January 25, 1996 and the repayment of amounts outstanding on the
Master Note Facility, the Receivables Facility and the VPP Facility, long-term
debt due during the fiscal years ending December 31, 1996 to 2000, is as
follows: $-0- in 1996, $23.4 million in 1997, $2 million in 1998, $1 million in
1999 and $-0- million in 2000. Interest payments were $6,757,000 in 1995,
$2,088,000 in 1994 and $1,819,000 in 1993.
5. LEASES
Future minimum lease payments under non-cancelable operating leases are
as follows: $558,000 in 1996, $548,000 in 1997, $537,000 in 1998, $421,000 in
1999 and $337,000 in 2000.
Lease payments charged to operating expenses amounted to $466,000,
$598,000 and $579,000 during 1995, 1994 and 1993, respectively.
31
<PAGE> 33
6. INCOME TAXES
Federal and state income tax expense includes the following components:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------
1995 1994 1993
---- ---- ----
DOLLARS IN THOUSANDS
<S> <C> <C> <C>
Currently payable . . . . . . . . . . . . . . . . . . . . . . $1,216 $1,039 $6,316
Deferred provision, net . . . . . . . . . . . . . . . . . . . 8,296 10,692 1,428
Amortization of investment tax credits . . . . . . . . . . . - - (73)
-------------------------------------
Federal income tax expense . . . . . . . . . . . . . . . . . 9,512 11,731 7,671
-------------------------------------
State income taxes (deferred provision $1,460 in 1995, $204 in
1994 and $12 in 1993) . . . . . . . . . . . . . . . . . . . 1,064 825 239
-------------------------------------
$10,576 $12,556 $7,910
-------------------------------------
Sources of deferred federal and state income taxes:
Intangible drilling costs . . . . . . . . . . . . . . . . . $12,619 $10,278 $3,708
Revenue recognition deferred . . . . . . . . . . . . . . . 1,854 2,343 -
Depreciation, depletion and amortization . . . . . . . . . (5,579) (1,883) (814)
Tax credit carry forwards and other, net . . . . . . . . . 862 158 (1,454)
-------------------------------------
$9,756 $10,896 $1,440
-------------------------------------
Reconciliation of federal income tax expense at statutory rate
to provision for income taxes:
Income before income taxes . . . . . . . . . . . . . . . . . $31,882 $36,713 $26,521
-------------------------------------
Tax provision at 35% statutory rate . . . . . . . . . . . . . 11,159 12,850 9,282
State income tax, net of federal income tax benefit . . . . . 692 537 151
Statutory depletion . . . . . . . . . . . . . . . . . . . . . (676) (696) (620)
Section 29 credits . . . . . . . . . . . . . . . . . . . . . (425) (388) (537)
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . (174) 253 (366)
-------------------------------------
$10,576 $12,556 $7,910
=====================================
</TABLE>
The primary differences giving rise to the Company's deferred tax assets and
liabilities are as FOLLOWS:
<TABLE>
<CAPTION>
DECEMBER 31, 1995
-----------------
ASSETS LIABILITIES
------ -----------
DOLLARS IN THOUSANDS
<S> <C> <C>
Income tax effects of:
Accelerated DD&A and other property related items . . . . . . $24,261
Alternative minimum tax credit carry forwards . . . . . . . . $3,175
Deferred revenue . . . . . . . . . . . . . . . . . . . . . . . 4,197
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . 889
---------------------------
$3,175 $29,347
===========================
</TABLE>
No income tax payments were made in 1995. Income tax payments
were $1,302,000 in 1994 and $1,729,500 in 1993. The Company received federal
income tax refunds of $58,000 and $233,000 in 1994 and 1993, respectively,
related to fiscal year 1993 and 1992 overpayments.
The alternative minimum tax credit carryforwards of $3,175,000, which
can be carried forward indefinitely, are available to reduce the Company's
future federal income tax liabilities.
32
<PAGE> 34
7. CONTINGENCIES
Tennessee Gas Litigation
The Company is currently selling natural gas from certain leases in the
Bob West Field in south Texas under the Tennessee Gas contract which runs
through January 1999. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Liquidity and Capital Resources". A recent
Texas Supreme Court decision held that the contract requires that the price of
natural gas sold thereunder is to be calculated in accordance with Section
102(b)(2) of the Natural Gas Policy Act of 1978 ("NGPA"), $8.17 per MMBtu
during December 1995, plus reimbursement of severance taxes. However, that
court also remanded to the trial court an issue not previously tried concerning
the volumes of natural gas that Tennessee Gas is required to take or pay for
under the contract.
In August 1990, in the District Court of Bexar County, Texas ("District
Court"), Tennessee Gas filed suit against the Company and its co- sellers
claiming among other things that the price of natural gas under the Tennessee
Gas contract should be determined under Section 101 of the NGPA rather than
Section 102(b)(2), that certain leases were no longer subject to the contract,
that for purposes of the contract the acreage subject to the contract could not
be pooled with other properties and that the contract was governed by Section
2.306 of the Texas Uniform Commercial Code ("Section 2.306"). In July 1992, the
District Court ruled in favor of the Company on all of these issues and awarded
damages for past underpayments and legal fees. The District Court's judgment
was partially affirmed by the Court of Appeals, which held that the price of
natural gas under the contract was to be determined in accordance with Section
102(b)(2), that all leases were subject to the contract, and that pooling of
the property with a pro rata acreage allocation of production to the contract
was in accordance with the contract. However, the Court of Appeals reversed
the District Court's summary judgment holding that the Tennessee Gas contract
was not an output contract subject to Section 2.306. Under the Court of Appeals
decision, new wells could be drilled and production increased, but any
production increase had to have complied with certain good faith and
reasonableness standards mandated by Section 2.306. The Court of Appeals also
set aside the District Court's awards to the Company of legal fees and past
underpayments pending the outcome of the trial on the Section 2.306 issue.
On August 1, 1995, the Texas Supreme Court affirmed the ruling of the
Court of Appeals, including its decision that Section 2.306 was applicable to
the Tennessee Gas contract. The Texas Supreme Court remanded to the District
Court for plenary trial the question of whether, as required by Section 2.306,
natural gas volumes taken by Tennessee Gas under the contract were produced and
delivered in good faith and were not unreasonably disproportionate to a normal
or otherwise comparable prior output or the expectation of the parties. The
Company filed a request on September 15, 1995 for a rehearing in the Texas
Supreme Court of the Section 2.306 issue, which request is currently pending.
If the Court does not grant a rehearing or does not change its decision after
reconsidering the matter, the Company expects the trial on the Section 2.306
issue to take place no earlier than late 1996.
In connection with a District Court judgment, since September 1994
Tennessee Gas has posted supersedeas bonds totaling $206 million and executed
interim agreements with the Company and its co-sellers under which it pays
$3.00 per MMBtu, currently, for natural gas delivered, and has agreed to take
monthly no less than 85% of the delivery capacity, if available, of the wells
covered by the Tennessee Gas contract for the term of the interim agreement, or
until mandate issues. The excess of $3.00 per MMBtu over the market price for
natural gas delivered since August 1, 1995 (but not for the earlier deliveries)
is refundable to Tennessee Gas to the extent required by a final judgment
against the Company. The acceptance of the $3.00 per MMBtu does not constitute
any waiver by the Company to its claim for the full contract price for all
natural gas taken by Tennessee Gas. The current interim agreement, unless again
extended by the parties, is in effect until the earlier of the issuance of a
mandate from the Texas Supreme Court or April 30, 1996.
Prior to September 17, 1994, Tennessee Gas had been paying a price for
natural gas production from the dedicated leases based on Section 102(b)(2) of
the NGPA, plus reimbursement for severance taxes, subject to the right to
recover any excess price if ultimately successful in the litigation. As of
December 31, 1995, the Company had recorded cumulative revenue of approximately
$155 million for natural gas sold under the Tennessee Gas contract based on the
prices as defined in the contract, of which approximately $112 million
(approximately $61 million of which has been received by the Company) is at
issue in the litigation. The Company continues to accrue an accounts receivable
amount due from Tennessee Gas that reflects the difference between the amount
paid for natural gas under the interim agreements between the parties and the
price that would have been paid pursuant to the terms of the Tennessee Gas
contract. At December 31, 1995, such receivable (which includes accrued
interest as
33
<PAGE> 35
provided for in the contract and is net of deferred severance taxes and other
payables) was $56.4 million. The Company anticipates this amount will continue
to increase. If Tennessee Gas ultimately prevails in this litigation, and
depending on the amount of natural gas for which the courts determine that
Tennessee Gas should have paid the spot market price rather than the contract
price, the Company could be required (i) to write off a portion or all of its
accounts receivable that is attributable to Tennessee Gas and (ii) to return a
portion or all of the disputed amounts received (plus interest if it is awarded
by the courts) to Tennessee Gas.
In a related matter, in April 1995, Tennessee Gas filed suit against
the Company and its co-sellers in District Court in Zapata County, Texas,
seeking declaratory judgment that no more than 50% of the production from
either of the jointly-owned Guerra "A" or Guerra "B" units is subject to the
Tennessee Gas contract, and claiming that the sellers are delivering in excess
of such amounts. In another related matter, Tennessee Gas filed suit in
November 1994, claiming that some of the natural gas taken under the Tennessee
Gas contract had been artificially enriched by the Company, thereby depriving
Tennessee Gas of its contractual right to reject natural gas that does not
comply with contractual quality specifications. Each of these cases is still
pending.
While the Company believes its defenses are meritorious and that it
should prevail in all of the pending litigation, there can be no assurance as
to the ultimate outcome of these matters.
Other Legal Proceedings
The Company is a party to three lawsuits involving the holders of
royalty interests on the acreage covered by the Tennessee Gas contract. The
Company is a co-plaintiff in the first of these lawsuits that was filed and is
a defendant in the other subsequently filed suits. The basis of these
declaratory judgment actions is the royalty holders' claim that their royalty
payments should be based on the price paid by Tennessee Gas for the natural gas
purchased by it under the Tennessee Gas contract. The Company has been paying
royalties for this natural gas based upon the spot market price. Because the
leases have market-value royalty provisions, the Company believes it is in full
compliance under the leases with its royalty holders. The amount at issue in
these cases cannot be determined at this time as it is a function of the
quantity of natural gas for which Tennessee Gas ultimately is obligated to pay
at the contract price at the resolution of the Tennessee Gas litigation
described above. As of December 31, 1995, the amount of natural gas taken by
Tennessee Gas attributable to these royalty interests was approximately 3.1
Bcf, for which royalties have been paid by the Company at the average spot
price of approximately $1.71 per Mcf, net of severance tax, compared to the
average contract price of approximately $7.50 per Mcf, net of severance tax.
Consequently, if the Company prevails in its litigation with Tennessee Gas, but
loses in its litigation with these royalty interest owners, the Company faces a
maximum liability in this litigation of approximately $17.9 million.
The Company is also a party to various other lawsuits and governmental
proceedings, all arising in the ordinary course of business. Although the
outcome of these proceedings cannot be predicted with certainty, management
does not expect such matters to have a material adverse effect, either singly
or in the aggregate, on the financial position of the Company.
8. QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
Quarters
--------
First Second Third Fourth
----- ------ ----- ------
Dollars in thousands (except per share data)
<S> <C> <C> <C> <C>
1995
Revenue . . . . . . . . . . . . . . . $96,039 $126,556 $109,679 $117,691
------- -------- -------- --------
Operating Income . . . . . . . . . . $10,184 $9,306 $6,438 $9,973
------- ------ ------ ------
Net Income . . . . . . . . . . . . . $6,219 $5,377 $4,086 $5,624
------ ------ ------ ------
Earnings Per Common Share . . . . . . $0.53 $0.46 $0.35 $0.48
===== ===== ===== =====
1994
Revenue . . . . . . . . . . . . . . . $85,173 $84,491 $80,743 $91,306
------- ------- ------- -------
Operating Income . . . . . . . . . . $9,380 $11,135 $6,076 $12,021
------ ------- ------ -------
Net Income . . . . . . . . . . . . . $6,170 $6,915 $3,977 $7,095
------ ------ ------ ------
Earnings Per Common Share . . . . . $0.52 $0.58 $0.34 $0.60
===== ===== ===== =====
</TABLE>
34
<PAGE> 36
9. FINANCIAL INFORMATION BY BUSINESS SEGMENT
The following financial information has been provided for the business
segments of the Company:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------
1995 1994 1993
---- ---- ----
DOLLARS IN THOUSANDS
<S> <C> <C> <C>
Revenue
Oil and Gas Exploration and Production . . . . $83,284 $66,076 $40,455
Energy Marketing and Services . . . . . . . . . 359,620 260,704 249,017
Natural Gas Transportation . . . . . . . . . . 26,722 19,910 16,480
Intercompany . . . . . . . . . . . . . . . . . (19,661) (4,977) (1,663)
-------- ------- -------
$449,965 $341,713 $304,289
========= ========= =========
Operating Income
Oil and Gas Exploration and Production . . . . $36,732 $37,804 $26,655
Energy Marketing and Services . . . . . . . . . 85 1,803 2,337
Natural Gas Transportation . . . . . . . . . . 1,479 1,225 1,241
------ ------ ------
38,296 40,832 30,233
Corporate Expenses . . . . . . . . . . . . . . (2,395) (2,220) (2,433)
Interest and Other Income, net . . . . . . . . 3,713 1,039 704
Interest Expense . . . . . . . . . . . . . . . (7,732) (2,938) (1,983)
------- ------- -------
Income Before Income Taxes . . . . . . . . . . $31,882 $36,713 $26,521
======== ======== ========
Identifiable Assets
Oil and Gas Exploration and Production . . . . $274,474 $151,571 $94,266
Energy Marketing and Services(1) . . . . . . . 53,229 39,929 48,040
Natural Gas Transportation . . . . . . . . . . 25,102 20,644 20,366
Corporate and Other . . . . . . . . . . . . . . 7,804 2,279 3,318
------ ------ ------
$360,609 $214,423 $165,990
========= ========= =========
Depreciation, Depletion and Amortization
Oil and Gas Exploration and Production . . . . $37,988 $18,538 $7,004
Energy Marketing and Services . . . . . . . . . 209 321 200
Natural Gas Transportation . . . . . . . . . . 948 857 798
Other . . . . . . . . . . . . . . . . . . . . . 64 24 34
--- --- ---
$39,209 $19,740 $8,036
======== ======== =======
Capital Expenditures
Oil and Gas Exploration and Production . . . . $122,554 $73,870 $46,667
Energy Marketing and Services . . . . . . . . . 85 210 201
Natural Gas Transportation . . . . . . . . . . 6,000 732 1,572
Other . . . . . . . . . . . . . . . . . . . . . 60 141 15
--- ---- ---
$128,699 $74,953 $48,455
========= ======== ========
</TABLE>
(1) Energy Marketing and Services assets consist primarily of trade
accounts receivable.
35
<PAGE> 37
10. OIL AND GAS PRODUCING OPERATIONS
The following data is presented pursuant to FASB Statement No. 69
with respect to oil and gas acquisition, exploration, development and
producing activities, which is based on estimates of year-end oil and
gas reserve quantities and forecasts of future development costs and
production schedules. These estimates and forecasts are inherently
imprecise and subject to substantial revision as a result of changes
in estimates of remaining volumes, prices, costs, and production rates.
Except where otherwise provided by contractual agreement, future cash
inflows are estimated using year-end prices. Oil and gas prices at December 31,
1995 are not necessarily reflective of the prices the Company expects to
receive in the future.
Volumetric production payment volumes represent oil and gas reserves
purchased from third parties which entitle the Company to a specified volume of
oil and gas to be delivered over a stated time period. The related volumes
stated herein reflect scheduled amounts of oil and gas to be delivered to the
Company at agreed delivery points, and are stated at year-end prices. The
Company does not bear any development or lease operating expenses associated
with the volumetric production payments.
PRODUCTION REVENUES AND COSTS
Information with respect to production revenues and costs related to
oil and gas producing activities is as follows:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------
1995 1994 1993
---- ---- ----
DOLLARS IN THOUSANDS
<S> <C> <C> <C>
Revenue . . . . . . . . . . . . . . . . . . . . . . . . $85,424 $65,773 $39,918
Production (lifting) costs . . . . . . . . . . . . . . 6,623 7,063 5,011
Technical support and other . . . . . . . . . . . . . . 1,941 2,671 1,785
Depreciation, depletion and amortization . . . . . . . 37,859 18,538 6,944
-------- ------- ------
Total expenses . . . . . . . . . . . . . . . 46,423 28,272 13,740
-------- ------- -------
Pretax income from producing activities . . . . . . . . 39,001 37,501 26,178
Income taxes . . . . . . . . . . . . . . . . . . . . . 12,549 12,041 8,005
-------- ------- ------
Results of oil and gas producing activities (excluding
corporate overhead and interest) . . . . . . . . . . $26,452 $25,460 $18,173
========= ======== ========
Capitalized costs incurred:
Property acquisition . . . . . . . . . . . . . . . . $77,515 $27,772 $18,563
Exploration . . . . . . . . . . . . . . . . . . . . . 16,891 12,599 3,787
Development . . . . . . . . . . . . . . . . . . . . . 26,859 33,311 24,249
-------- ------- -------
Total capitalized costs incurred . . . . . . $121,265 $73,682 $46,599
========== ======== ========
Capitalized costs at year-end:
Proved properties . . . . . . . . . . . . . . . . . . $284,597 $169,624 $98,369
Unproved properties . . . . . . . . . . . . . . . . . 7,297 5,074 2,647
------- ------ ------
291,894 174,698 101,016
Less accumulated depreciation, depletion and
amortization . . . . . . . . . . . . . . . . . . . . (86,936) (49,077) (30,539)
--------- -------- --------
Net investment in oil and gas producing properties . . $204,958 $125,621 $70,477
========= ======== ========
</TABLE>
36
<PAGE> 38
DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED)
The following information relating to discounted future net cash flows
has been prepared on the basis of the Company's estimated net proved oil and
gas reserves in accordance with FASB Statement No. 69. A significant portion of
the discounted future net cash flows presented below is attributable to the Bob
West Field where gas is committed under the Tennessee Gas contract, which runs
through January 31, 1999 (see Note 7).
DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
<TABLE>
<CAPTION>
DECEMBER 31,
------------
1995 1994
---- ----
DOLLARS IN THOUSANDS
<S> <C> <C>
Future cash inflows . . . . . . . . . . . . . . . . . . $521,914 $371,323
Future costs:
Production . . . . . . . . . . . . . . . . . . . . . (94,880) (44,795)
Development . . . . . . . . . . . . . . . . . . . . . (21,985) (18,995)
Discount -- 10% annually . . . . . . . . . . . . . . (113,964) (65,828)
--------- --------
Present value of future net revenues . . . . . . . . 291,085 241,705
Future income taxes, discounted at 10% . . . . . . . (59,322) (62,045)
-------- --------
Standardized measure of discounted future net cash flows $231,763 $179,660
========= =========
</TABLE>
CHANGES IN DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVE QUANTITIES
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------
1995 1994 1993
---- ---- ----
DOLLARS IN THOUSANDS
<S> <C> <C> <C>
Balance, beginning of year . . . . . . . . . . $179,660 $160,884 $106,993
--------- --------- ---------
Increases (decreases)
Sales, net of production costs . . . . . . . (78,801) (58,710) (34,907)
Net change in prices, net of production costs 9,593 (11,180) (7,648)
Discoveries and extensions, net of future
production and development costs . . . . . . . . 22,417 26,930 75,365
Changes in estimated future development costs (862) (9,622) (1,862)
Change due to acquisition of reserves in place 108,798 26,038 23,665
Development costs incurred during the period 9,672 13,924 3,371
Revisions of quantity estimates . . . . . . . (19,256) 1,532 (15,791)
Accretion of discount . . . . . . . . . . . . 24,033 21,017 14,600
Net change in income taxes . . . . . . . . . 2,021 (12,060) (10,279)
Sales of reserves in place . . . . . . . . . (1,931) - -
Changes in production rates (timing) and other (23,581) 20,907 7,377
-------- ------- ------
Net increase . . . . . . . . . . . . . . . . 52,103 18,776 53,891
------- ------- -------
Balance, end of year . . . . . . . . . . . . . $231,763 $179,660 $160,884
========= ========= =========
</TABLE>
37
<PAGE> 39
RESERVE INFORMATION (UNAUDITED)
The following information with respect to the Company's estimated net
proved oil and gas reserves are estimates based on reports prepared by
independent petroleum engineers (principally R.A. Lenser and Associates, Inc.
and H. J. Gruy and Associates, Inc.) Proved developed reserves represent only
those reserves expected to be recovered through existing wells using equipment
currently in place. Proved undeveloped reserves represent proved reserves
expected to be recovered from new wells or from existing wells after material
recompletion expenditures. All of the Company's reserves are located within the
United States.
<TABLE>
<CAPTION>
1995 1994 1993
---- ---- ----
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 . . . . 89,184 2,319 69,740 2,578 52,029 1,333
Production . . . . . . . . (19,129) (196) (11,304) (211) (6,977) (179)
Discoveries, extensions, etc 10,399 202 10,924 33 14,066 972
Acquisition of reserves in place 71,560 5,449 18,206 148 10,043 1,684
Sales of reserves in place (3,751) (3) - - - -
Revisions of estimates . . (7,300) (254) 1,618 (229) 579 (1,232)
------- ----- ------ ----- ---- -------
Balance, end of year . . . 140,963 7,517 89,184 2,319 69,740 2,578
=====================================================================
Proved developed reserves
Balance, beginning of year 74,215 1,336 61,016 1,579 39,140 1,095
------- ------ ------- ------ ------- ------
Balance, end of year . . . . . . 121,987 3,808 74,215 1,336 61,016 1,579
=====================================================================
</TABLE>
Proved gas reserves at December 31, 1995 include 31.7 Bcf
(including 28.7 Bcf proved, developed) attributable to the Bob West Field,
where gas is committed under the Tennessee Gas contract (see Note 7). Not all
of the reserves can be produced during the remaining life of the contract which
runs through January 31, 1999.
11. RECENT ACQUISITIONS
On November 8, 1995, the Company acquired substantially all of the oil
and gas assets of Natural Gas Processing Company (the "Rocky Mountain
Acquisition") for $33 million, subject to adjustments for a July 1, 1995
effective date. The purchase was financed principally through the Master Note
Facility. The Company also acquired a significant inventory of oil and gas
equipment and supplies, vehicles and buildings as well as natural gas gathering
systems consisting of approximately 200 miles of pipeline.
On December 7, 1995, the Company acquired reserves in the northern and
southern Niagaran Reef trend in Michigan for $31 million, including a
volumetric production payment covering certain reserves, escalating working
interests in related properties and participation rights and an overriding
royalty interest in an exploration program (collectively, the "Michigan
Acquisition"). The volumetric production payment provides for the delivery to
the Company of certain oil and gas reserves totaling 20.3 Bcfe through January
31, 2006 without any burden of operating costs. The Michigan Acquisition was
financed through the VPP Facility and the Note Financing.
These acquisitions were accounted for using the purchase method. The
results of operations for the acquired entities are included in the Company's
consolidated results of operations from the dates of acquisition.
38
<PAGE> 40
The following is the unaudited pro forma revenue, net income and
earnings per share giving effect to the Rocky Mountain and Michigan
Acquisitions for the years ended December 31, 1995 and 1994, as if such
transactions had occurred at the beginning of such years. The unaudited pro
forma financial data do not purport to be indicative of the financial position
or results of operations that would actually have occurred if the transactions
had occurred as presented or that may be obtained in the future.
<TABLE>
<CAPTION>
Years Ended
December 31,
-------------------------
Dollars in thousands
(except per share data)
1995 1994
---- ----
<S> <C> <C>
Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . $463,815 $356,748
Net income . . . . . . . . . . . . . . . . . . . . . . . . $21,586 $24,316
Earnings per common share . . . . . . . . . . . . . . . . . $1.84 $2.06
</TABLE>
Item 9. Changes in and Disagreements With Accountants On
Accounting And Financial Disclosure.
None.
39
<PAGE> 41
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 1996 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.
<TABLE>
<CAPTION>
Page
----
<S> <C>
Report of Independent Public Accountants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Statements of Consolidated Income for the years ended December 31, 1995, 1994 and 1993 . . . . . . . . . 21
Consolidated Balance Sheets at December 31, 1995 and 1994 . . . . . . . . . . . . . . . . . . . . . . . 22
Statements of Consolidated Stockholders' Equity for the years ended December 31, 1995, 1994
and 1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Statements of Consolidated Cash Flows for the years ended December 31, 1995, 1994 and 1993 . . . . . . . 24
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 - 39
</TABLE>
(2) Financial Statement Schedules
The following financial statement schedule for KCS Energy, Inc.
is filed as a part of this Form 10-K. Schedules not included have been omitted
because they are not applicable or the required information is shown in the
financial statements or notes thereto.
<TABLE>
<CAPTION>
Schedule Number
---------------
<S> <C>
II Valuation and Qualifying Accounts for the three-year period ended December 31, 1995 . . . . . 42
</TABLE>
(3) Exhibits
See "Exhibit Index" located on page 43 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.
During the three months ended December 31, 1995, the registrant filed
the following reports on Form 8-K:
On November 22, 1995, the registrant reported a significant acquisition
of assets under Item 2 of Form 8-K. This report was amended on Form
8-K/A on January 22, 1996.
On December 21, 1995, the registrant reported the commencement of Rule
144A private offering of $150,000,000 aggregate principal amount of
senior notes due 2003 under Item 5 of Form 8-K.
On December 22, 1995, the registrant reported a change in fiscal year
end under Item 8 of Form 8-K.
On December 22, 1995, the registrant reported a significant acquisition
of assets under Item 2 of Form 8-K. This report was amended on Form
8-K/A on January 19, 1996.
40
<PAGE> 42
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: 3/26/96 By:/s/ Henry A. Jurand
------- ----------------------
Henry A. Jurand, Vice President,
Chief Financial Officer and Secretary
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.
3/25/96 /s/ James W. Christmas
------- ------------------------------
Date James W. Christmas, President
& Chief Executive Officer & Director
3/25/96 /s/ Stewart B. Kean
------- ---------------------------------
Date Stewart B. Kean, Chairman and Director
3/25/96 /s/ G. Stanton Geary
------- -----------------------------------
Date G. Stanton Geary, Director
3/25/96 /s/ James E. Murphy
------- ---------------------------------
Date James E. Murphy, Director
3/25/96 /s/ Robert G. Raynolds
------- ------------------------------
Date Robert G. Raynolds, Director
3/25/96 /s/ Joel D. Siegel
------- ------------------------------------
Date Joel D. Siegel, Director
3/25/96 /s/ Christopher A. Viggiano
------- ----------------------------
Date Christopher A. Viggiano, Director
/s/ Henry A. Jurand 3/26/96
- --------------------------------- -------
Henry A. Jurand, Vice President, Date
Chief Financial Officer and Secretary
41
<PAGE> 43
Schedule II
KCS ENERGY, INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1993 TO 1995
<TABLE>
<CAPTION>
Balance at Charged to Costs Balance at End
Beginning of and of
Description Period Expenses Deductions Period
----------- ------ -------- ---------- ------
Thousands of Dollars
--------------------
<S> <C> <C> <C> <C>
Valuation accounts deducted in
balance sheet from accounts to which
they apply:
1995
----
Investments and other assets $55 $150 - $205
==================================================================
Accounts receivable $305 $363 $253 $415
==================================================================
1994
----
Investments and other assets $55 - - $55
==================================================================
Accounts receivable $99 $206 - $305
==================================================================
1993
----
Investments and other assets $55 - - $55
==================================================================
Accounts receivable $103 $46 $50 $99
==================================================================
</TABLE>
42
<PAGE> 44
Exhibit Index
<TABLE>
<CAPTION>
Exhibit
No. Description
------ -----------
<S> <C> <C>
(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).
v Registration Rights Agreement, dated January 25, 1996, between KCS, certain of its subsidiaries, Smith
Barney Inc., Donaldson, Lufkin & Jenrette Securities Corporation, Nomura Securities International, Inc.
and Paine Webber Incorporated, filed as Exhibit 10 to Current Report on Form 8-K dated January 25, 1996.
(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 Stock Purchase Agreement by and among KCS Group, Inc., Alfonso Izzi,
AJI Corporation, and Computil Corporation dated February 15, 1989,
filed as Exhibit 10(v) of Registrant's Form 10-K Report for Fiscal 1989.
vii Assets Sale and Purchase Agreement between Utility Propane Company and Amerigas, Inc.
dated August 3, 1989 filed as Exhibit A to the KCS Proxy Statement regarding a special
meeting of stockholders filed with the SEC on September 6, 1989.
viii Credit Agreement dated as of March 14, 1991 by and among The Lenape Resources
Corporation, Enercorp Gas Transmission Systems, Inc., Enercorp Pipeline, LTD.
and Bank One, Texas, National Association filed as Exhibit 10 (xiii) of Registrant's
Form 10-K Report for Fiscal 1991.
ix First Amendment dated May 18, 1993 to Credit Agreement dated as of March 14, 1991
by and among The Lenape Resources Corporation, Enercorp Gas Transmission Systems, Inc.,
Enercorp Pipeline, Ltd. and Bank One, Texas, National Association.
</TABLE>
43
<PAGE> 45
<TABLE>
<S> <C>
x Guaranty Agreement dated as of March 14, 1991 made jointly and severally by KCS Group, Inc.
and Enercorp in favor of Bank One, Texas, National Association filed as Exhibit 10 (xiv)
of Registrant's Form 10-K Report for Fiscal 1991.
xi First Amendment dated May 18, 1993 to Guaranty Agreement dated as of March 18, 1991 made
jointly and severally by KCS Energy, Inc. (formerly known as KCS Group, Inc.) and
Enercorp in favor of Bank One, Texas, National Association.
xii Loan and Security Agreement dated September 27, 1991 by and between First
Fidelity Bank, National Association, New Jersey and Energy Marketing Exchange, as
Borrower and KCS Group, Inc. and Proliq, Inc. as Guarantors filed as Exhibit 10 (xv) of
Registrant's Form 10-K Report for Fiscal 1991.
xiii Modification Agreement dated March 31, 1993 to Loan and Security Agreement dated
September 27, 1991 by and between First Fidelity Bank, National Association, New
Jersey and KCS Energy Marketing, Inc. (formerly known as Energy Marketing Exchange, Inc.) as
Borrower and KCS Energy, Inc. and Proliq, Inc. as Guarantors.
xiv Partial Assignment and Bill of Sale between Esenjay Petroleum Corporation and The Lenape
Resources Corporation filed as Exhibit 10 (xvi) of Registrant's Form 10-K Report for Fiscal 1991.
xv Severance and Settlement Agreement with Stewart B. Kean filed as Exhibit
10 (xvii) of Registrant's Form 10-K Report for Fiscal 1991.
xvi 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.
xvii Amended and Restated Credit Agreement dated as of March 15, 1994 by and among KCS Resources, Inc. (the
surviving corporation of the merger of The Lenape Resources Corporation), KCS Pipeline Systems, Inc. (the
surviving corporation of the merger of Enercorp Gas Transmission Systems, Inc.) and Bank One, Texas,
National Association filed as Exhibit 10 (xvii) of Registrant's Form 10-K Report for fiscal 1994.
xviii Amended and Restated Guaranty Agreement dated as of March 15, 1994 made by KCS Energy,
Inc. (formerly KCS Group, Inc.) in favor of Bank One, Texas, National Association filed as
Exhibit 10 (xviii) of Registrant's Form 10-K Report for fiscal 1994.
xix Modification Agreement dated March 31, 1994 to Loan and Security Agreement dated
September 27, 1991 as modified by a modification agreement dated April 1, 1992
and by a modification agreement dated as of March 31, 1993 by and between First
Fidelity Bank, National Association and KCS Energy Marketing, Inc.(formerly known
as Energy Marketing Exchange, Inc.) as Borrower and KCS Energy, Inc. and Proliq, Inc.
as Guarantors filed as Exhibit 10 (xix) of Registrant's Form 10-K Report for fiscal 1994.
xx First Amendment dated September 29, 1994 to Amended and Restated Credit Agreement by and
among KCS Resources, Inc.(the surviving corporation of the merger of the Lenape
Resources Corporation), KCS Pipeline Systems, Inc. (the surviving corporation of the merger
of Enercorp Gas Transmission Systems, Inc.) and Bank One, Texas, National Association,
and CIBC, Inc. filed as Exhibit 10 (xx) of Registrant's Form 10-K Report for fiscal 1994.
xxi First Amendment dated September 29, 1994 to Amended and Restated Guaranty Agreement made
by KCS Energy, Inc. in favor of Bank One, Texas, National Association and CIBC, Inc. filed as
Exhibit 10 (xxi) of Registrant's Form 10-K Report for fiscal 1994.
xxii 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.
</TABLE>
44
<PAGE> 46
<TABLE>
<S> <C> <C>
xxiii Loan Agreement dated January 11, 1995 among KCS Energy Marketing, Inc. as Borrower; KCS Energy, Inc. and
Proliq, Inc., each as a Guarantor; and Canadian Imperial Bank of Commerce, as Lender filed as Exhibit 10.3
of Registrant's Form 10-Q for the quarterly period ended December 31, 1994.
xxiv Security Agreement dated January 11, 1995 among KCS Energy Marketing, Inc., KCS Energy, Inc., and Canadian
Imperial Bank of Commerce filed as Exhibit 10.4 of Registrant's Form 10-Q for the quarterly period ended
December 31, 1994.
xxv Pledge and Security Agreement dated January 11, 1995 between Proliq, Inc. and Canadian Imperial Bank of
Commerce filed as Exhibit 10.5 of Registrant's Form 10-Q for the quarterly period ended December 31, 1994.
xxvi Credit Agreement dated January 12, 1995 between KCS Energy Marketing, Inc. and Comerica Bank - Texas filed
as Exhibit 10.1 of Registrant's Form 10-Q for the quarterly period ended December 31, 1994.
xxvii Guaranty Agreement dated January 12, 1995 by KCS Energy, Inc. and Proliq, Inc. in favor of Comerica Bank -
Texas filed as Exhibit 10.2 of Registrant's Form 10-Q for the quarterly period ended December 31, 1994.
xxviii Second Amendment dated December 22, 1994 to Amended and Restated Credit Agreement by and among KCS
Resources, Inc., KCS Pipeline Systems, Inc. and Bank One, Texas, National Association and CIBC, Inc. -
filed as Exhibit 10 (xxviii) of Registrant's Form 10-K Report for the period ended September 30, 1995.
xxix Third Amendment dated March 15, 1995 to Amended and Restated Credit Agreement by and among KCS Resources,
Inc., KCS Pipeline Systems, Inc. as Borrowers; KCS Energy, Inc. as Guarantor; and Bank One, Texas,
National Association and CIBC, Inc. - filed as Exhibit 10 (xxix) of Registrant's Form 10-K Report for the
period ended September 30, 1995.
xxx First Amendment dated July 1, 1995 to Loan Agreement by and among KCS Energy Marketing, Inc. as Borrower;
KCS Energy, Inc. and Proliq, Inc. as Guarantors; and Canadian Imperial Bank of Commerce - filed as Exhibit
10 (xxx) of Registrant's Form 10-K Report for the period ended September 30, 1995.
xxxi 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.
xxxii 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.
(11) Statement re computation of per share earnings - filed herewith.
(21) Subsidiaries of the Registrant - filed herewith .
(23) i Consent of Arthur Andersen LLP - filed herewith.
ii Consent of R.A. Lenser and Associates, Inc. - filed herewith.
iii Consent of H. J. Gruy and Associates, Inc. - filed herewith.
</TABLE>
- ---------------
* Management contract or compensatory plan or arrangement required to be filed
as an exhibit.
45
<PAGE> 1
Exhibit 11
Statement re Computation of Per Share Earnings
Earnings per share were calculated as follows:
<TABLE>
<CAPTION>
For the Years Ended December 31,
--------------------------------
1995 1994 1993
---- ---- ----
In Thousands
Except per share amount
<S> <C> <C> <C>
Net income $21,306 $24,157 $18,611
=========== =========== ===========
Average shares of common
stock outstanding
11,480 11,485 11,069
Add: Net shares assumed to be issued
for dilutive stock options 281 320 589
----------- ----------- -----------
Average shares of common stock
and common stock equivalents
outstanding 11,761 11,805 11,658
=========== =========== ===========
Earnings per share of common stock
and common stock equivalents
$1.81 $2.05 $1.60
=========== =========== ===========
</TABLE>
46
<PAGE> 1
Exhibit 21
KCS ENERGY, INC.
LIST OF WHOLLY-OWNED SUBSIDIARIES
KCS Resources, Inc.
KCS Pipelines Systems, Inc.
Enercorp Gas Marketing, Inc.
KCS Energy Risk Management, Inc.
National Enerdrill Corporation
Proliq, Inc.
KCS Energy Marketing, Inc.
KCS Power Marketing, Inc.
KCS Michigan Resources, Inc.
47
<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 28, 1996
48
<PAGE> 1
Exhibit 23 (ii)
CONSENT OF INDEPENDENT PETROLEUM ENGINEER
We hereby consent to the references to us under the headings "Oil and Gas
Producing Operations: and "Oil and Gas Reserves" in the Annual Report on Form
10-K of KCS Energy, Inc. for the year ended December 31, 1995.
R. A. Lenser and Associates, Inc.
Houston, Texas
March 26, 1996
49
<PAGE> 1
Exhibit 23 (iii)
CONSENT OF INDEPENDENT PETROLEUM ENGINEER
We hereby consent to the references to us under the headings "Oil and Gas
Producing Operations: and "Oil and Gas Reserves" in the Annual Report on Form
10-K of KCS Energy, Inc. for the year ended December 31, 1995.
H. J. Gruy and Associates, Inc.
Houston, Texas
March 26, 1996
50
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> DEC-31-1995
<CASH> 5,846
<SECURITIES> 0
<RECEIVABLES> 58,467
<ALLOWANCES> 415
<INVENTORY> 782
<CURRENT-ASSETS> 68,054
<PP&E> 322,009
<DEPRECIATION> 92,693
<TOTAL-ASSETS> 360,609
<CURRENT-LIABILITIES> 64,401
<BONDS> 0
0
0
<COMMON> 124
<OTHER-SE> 101,452
<TOTAL-LIABILITY-AND-EQUITY> 360,609
<SALES> 449,965
<TOTAL-REVENUES> 449,965
<CGS> 356,186
<TOTAL-COSTS> 356,186
<OTHER-EXPENSES> 57,878
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 7,732
<INCOME-PRETAX> 31,882
<INCOME-TAX> 10,576
<INCOME-CONTINUING> 21,306
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 21,306
<EPS-PRIMARY> 1.81
<EPS-DILUTED> 0
</TABLE>
