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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
/x/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 1995
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM _________________ TO _________________________
COMMISSION FILE NO. 1-11698
KCS ENERGY, INC.
(Exact name of registrant as specified in its charter)
DELAWARE 22-2889587
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
379 THORNALL STREET, EDISON, NEW JERSEY 08837
(Address of principal executive offices)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (908) 632-1770
Securities registered pursuant to Section 12(b) of the Act:
Title of Class Name of each exchange on which registered
-------------- -----------------------------------------
COMMON STOCK, par value $0.01 per share New York Stock Exchange
--------------------------------------- ------------------------
Securities registered pursuant to Section 12(g) of the Act:
Title of class
--------------
COMMON STOCK, par value $0.01 per share
---------------------------------------
INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS
REQUIRED TO BE FILED BY SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934 DURING THE PRECEEDING 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:
The aggregate market value of the 9,182,638 shares of the Common Stock held by
non-affiliates of the Registrant at the $14.625 closing price on December 15,
1995 was $134,296,081.
Number of shares of Common Stock outstanding as of the close of business on
December 15, 1995: 11,487,137
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KCS ENERGY, INC.
FORM 10-K
Report for the Year Ended September 30, 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 Company's recently completed Rocky Mountain Acquisition
has expanded the Company's operations into certain major producing basins in
Wyoming, Colorado and Montana. At September 30, 1995, the Company had working
interests in 331 producing wells, (85 of which it operates). After giving
effect to the Rocky Mountain Acquisition, the Company had working interests in
862 producing wells (406 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, with the Michigan Acquisition, in the Niagaran Reef trend in
Michigan. As of September 30, 1995, approximately 88% of the Company's proved
reserves were natural gas, approximately 83% were classified as proved
developed, and the reserve life was estimated to be 5.4 years. After giving
effect to the Rocky Mountain and Michigan Acquisitions, approximately 76% of
the Company's proved reserves were natural gas, approximately 77% of reserves
were classified as proved developed, and the average reserve life was estimated
to be 7.7 years.
The Company's largest single producing field is the Bob West Field in
south Texas, which accounted for approximately 43% of the Company's production
during fiscal 1995 (32% of fiscal 1995 pro forma production after giving effect
to the Rocky Mountain and Michigan Acquisitions) from its interests in 45 wells
(16 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 2%
of the Company's operating income during fiscal 1995. As of September 30,
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 11 natural gas gathering systems in Texas and Louisiana. The Rocky
Mountain Acquisition added 5 gathering systems in Montana. 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) a high quality, diversified reserve base,
(ii) a significant inventory of attractive development and exploratory drilling
opportunities within the Company's large property base and undeveloped acreage
position, (iii) established relationships with a broad base of industry
partners that continually provide the Company with opportunities to participate
in a diverse group of exploration prospects without expending the resources
that would be required to develop comparable prospects internally, (iv) a
streamlined administrative and operating cost structure that emphasizes a lean
staff and extensive arrangements with independent contractors, and (v) a
volumetric production payment program.
RECENT ACQUISITIONS
Rocky Mountain Acquisition
On November 8, 1995, the Company acquired substantially all of the oil
and gas assets of Natural Gas Processing Company for a purchase price of $33
million, subject to adjustments for a July 1, 1995 effective date. The Rocky
Mountain Acquisition was financed principally through the Company's master note
facility with a group of banks. The Company acquired interests in 531 gross (301
net) wells located in over 30 different fields, principally in six producing
basins located in Wyoming, Colorado and Montana. The Company will operate 321,
or approximately 60%, of these wells. Proved reserves attributable to the
properties are estimated by independent petroleum engineers at September 30,
1995 to be 66.7 Bcfe, consisting of 40.9 Bcf (61%) of natural gas and 4.3 MMbbls
(39%) of oil. (See Item 2). Approximately 45% of the natural gas production
from the acquired properties is subject to multi-year contracts with local
utility companies at prices that are currently in excess of spot market prices.
These Rocky Mountain properties were producing at a combined average rate
attributable to the Company's interest during September 1995 of 7,556 Mcf of
natural gas and 822 Bbls of oil per day.
The Rocky Mountain Acquisition provides the Company with an existing
operation and infrastructure in a new geographic area with high percentage
working and net revenue interests in properties that the Company believes
contain a significant number of development drilling, work-over and
recompletion opportunities, as well as additional exploration opportunities,
which management believes will maximize the value and productivity of these
properties. The Company has budgeted $10 million for drilling and other
enhancement activities on these properties in fiscal 1996. In addition, the
Rocky Mountain Acquisition includes approximately 197,000 gross (160,000 net)
acres of largely underdeveloped properties. The Company also acquired a
significant inventory of oil and gas equipment and supplies, vehicles and
buildings as well as natural gas gathering systems consisting of approximately
200 miles of pipeline. Following this acquisition, the Company hired
exploration and operational personnel with experience in the Rocky Mountain
area who were formerly employed by the seller.
Michigan Acquisition
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 the exploration program discussed below. The volumetric
production payment provides for the delivery to the Company of certain oil and
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gas reserves totaling 20.3 Bcfe through January 31, 2006 without any burden of
development and lease operating expenses. The reserves consist of 13.7 Bcf of
natural gas and 1.1 MMbbls of oil, with approximately 17% of these volumes to
be delivered in 1996. Based on independent reserve reports, the separately
acquired working interests add 3.1 Bcf of natural gas and 219 Mbbls of oil to
the Company's proved reserves. The Michigan Acquisition was financed
principally through the Company's volumetric production payment facility with a
bank.
The volumetric production payment reserves acquired by the Company in
the Michigan Acquisition will be produced principally from 89 wells operated by
a subsidiary of Hawkins Oil and Gas, Inc. ("Hawkins") on properties located in
the Niagaran Reef trend in northern and southern Michigan, all of which were
recently acquired by Hawkins as a result of a merger with Savoy Oil & Gas, Inc.
("Savoy"), a Michigan-based oil and gas exploration company. The operator will
bear all development and lease operating expenses attributable to these
reserves. The Company will bear a proportionate share of applicable severance
taxes on its produced volumes. (See Item 2)
Of the total purchase price for the volumetric production payment, the
operator has committed to utilize approximately $1.3 million towards the
recompletion of up to 20 wells which will support delivery of the volumetric
production payment volumes. Hawkins has the right through August 31, 1998 to
repurchase from the Company up to one-third of the then-outstanding production
payment at a pre-determined schedule of purchase prices that provide the
Company with an agreed-upon rate of return.
The working interests acquired by the Company cover 30 wells on related
properties located in the Niagaran Reef trend. Under the terms of the
assignment and bill of sale covering the interests acquired, the Company is
entitled to a 10% working interest in these wells until the first payout date
(estimated to occur in April 1996), 15% until the second payout date (estimated
to occur in the first quarter of calendar 1997) and 30% thereafter.
The Company has also negotiated a separate agreement that provides for
the Company's right to participate and an overriding royalty interest in a
three-year exploration program with Hawkins and former principals of Savoy. The
majority of the prospects in this exploration program are anticipated to be
generated pursuant to a farmout agreement which covers approximately 150,000
gross (56,250 net) acres in the Niagaran Reef trend in northern and southern
Michigan, and also involve rights to use approximately 17,000 miles of
proprietary seismic data in the area. Following the identification of drilling
prospects, and subject to the elections of third parties under the farmout and
other agreements, the Company will have the right to participate on an equal
basis with Hawkins. The Company has agreed, under certain conditions, to fund
both its and Hawkins' participation costs, including well development and
engineering costs, in consideration for which the Company will recover, as an
annual priority payment out of net production proceeds, 133% of the total costs
annually advanced by the Company.
The Company has also entered into an agreement whereby it is entitled
to receive assignments of overriding royalty interests in certain properties to
be developed by Hawkins pursuant to the exploration agreement. The interests to
be assigned to the Company will be determined based upon lease burdens and the
participating interests of other parties.
(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 38 of this Form 10-K. This
financial data does not include data regarding the Rocky Mountain and Michigan
acquisitions.
(c) Narrative description of business
OIL AND GAS EXPLORATION AND PRODUCTION
The Company's exploration and production activities are primarily
focused on exploration, development and acquisition of producing oil and gas
properties in the United States.
During the three fiscal years ended September 30, 1995, the Company
participated in the drilling of 50 exploratory wells with a 52% success rate.
Discoveries included wells in
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the Bob West Field, Langham Creek Area and Laurel Ridge Field. The Company's
policy is to commit no more than one-third of operating cash flow to
exploration activities and generally no more than $750,000 for any single well.
The fiscal 1996 budget for these operations is approximately $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.
Exploration activities will focus primarily on properties located in the
onshore Gulf Coast regions of Texas and Louisiana. The Company plans to drill
as many as 30 prospects and continue significant 3-D and 2-D seismic data
acquisition and analysis during fiscal 1996. The Company is in the early phase
of a 3-D seismic program to map sand channels in Tuscaloosa Sand trends. 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 exploration program described above as part of
the Michigan Acquisition.
During the three fiscal years ended September 30, 1995, the Company
participated in the drilling of 53 development wells with a 98% success rate
that resulted in 52 successful completions. The majority of this development
has been in the Bob West Field in Zapata and Starr Counties, Texas.
The Company's development budget for fiscal 1996 is approximately $22
million, including development activities on its recently acquired Rocky
Mountain properties. In addition to the development planned on its recently
acquired Rocky Mountain properties, the Company is focusing its Gulf Coast
development activities on acreage in the Langham Creek Area in Harris County,
Texas where it made a discovery in 1994 and on the Laurel Ridge Field in
Iberville Parish, Louisiana where it made two discoveries in late 1995. The
Langham Creek area produces from the Yegua and upper and middle Wilcox sands.
The Company has an average 36% net revenue interest in three newly completed
wells in this area, which are currently producing at a rate attributable to the
Company's interest of approximately 3,700 Mcfe per day, and it believes that the
geological and geophysical evidence indicates the potential for 10 additional
drilling locations on approximately 4,500 gross acres.
Development efforts are also underway in the Laurel Ridge Field, where
the Company is the operator and has a 26% net revenue interest. The initial
discovery well commenced production in August 1995 and a second well in
shallower zones was completed in December 1995. Additional development
activities are also being planned for this field and for properties located in
Goliad and Colorado Counties, Texas.
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 September 30, 1995, the Company had invested $35.3 million under
this program. In addition, the Michigan Acquisition includes a volumetric
production payment that will provide for the delivery to the Company
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of certain oil and gas reserves totaling 20.3 Bcfe through January 31, 2006,
consisting of 13.7 Bcf of natural gas and 1.1 MMbbls of oil, with
approximately 17% of these volumes to be delivered in 1996.
The Company competes with major oil and gas companies, other independent
oil and gas concerns and individual producers and operators in the areas of
reserve acquisitions and the exploration, development, production and marketing
of oil and gas, as well as contracting for equipment and securing personnel.
Oil and gas prices have historically been volatile and are expected 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 82% and 81% of the oil and gas exploration and production
business' revenue and 14% and 16% of the Company's consolidated revenue for the
years ended September 30, 1994 and 1995, 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 fiscal
1994 or 1995.
Oil and gas exploration and production operations accounted for 17% and
20% of the Company's consolidated revenues and 90% and 99% of operating income
in the years ended September 30, 1994 and 1995, respectively.
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 and 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.
As a result of the Rocky Mountain Acquisition, the Company now 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 systems are located in Texas and one 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 September 30, 1995, natural gas transportation
operations accounted for 6% of the Company's consolidated revenue and 3% 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 risk management. For the year ended September 30, 1995, energy marketing
and services operations accounted for 77% of the Company's consolidated
revenue.
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The Company's natural gas marketing operations are engaged in the direct
marketing of natural gas to industrial and commercial end-users. During fiscal
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 utilizes
the NYMEX natural gas futures contract and swaps as pricing and risk management
tools, and it is the Company's policy to hedge or match any sales or purchase
contract longer than 30 days.
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 Company's energy risk management operation provides energy price
risk management consulting and brokerage services to oil and gas producers,
pipelines, marketers and other natural gas customers and also assists the
Company in managing its energy price risk. The Company currently 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 and margins are narrow and there continues to be
consolidation in the industry with fewer but larger competitors. Gas marketing
requires liaison with interstate and intrastate pipelines, local distribution
companies and the Federal Energy Regulatory Commission 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
The sale of 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.
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Employees
The Company and its subsidiaries employed a total of 86 persons on
September 30, 1995. While certain employees perform duties in more than one
business segment, an approximate breakdown is as follows: Oil and Gas
Exploration and Production, 21; Natural Gas Transportation, 10; Energy
Marketing and Services, 47; and parent company, 8. Subsequent to September 30,
1995, the Company added 22 employees as a result of the Rocky Mountain
Acquisition.
Item 2. Properties.
PRINCIPAL WORKING INTEREST OIL AND GAS PROPERTIES
The following table sets forth data as of September 30, 1995 (giving
effect to the Rocky Mountain Acquisition) regarding the number of gross
producing wells and the estimated quantities of proved oil and gas reserves
attributable to the Company's principal onshore Gulf Coast and Rocky Mountain
properties in which it owns working interests.
ESTIMATED PROVED RESERVES
-------------------------
GROSS NATURAL GAS
PRODUCING OIL ----------- Total
WELLS (Mbbls) (MMcf) (MMcfe) % of Total
----- ------- ------ ------- -----------
Property/Area
- -------------
Onshore Gulf Coast:
Bob West Field . . . . 45 -- 33,272 33,272 23%
Langham Creek Area . . 6 130 8,448 9,228 6
Oletha Field . . . . . 6 3 6,325 6,343 4
San Salvador Field . . 11 2 5,080 5,092 4
Richardson-Mueller Field 21 960 -- 5,760 4
Salem-McCan Field . . . 47 140 2,466 3,306 2
Birdie Field . . . . . 1 26 1,563 1,719 1
Bloomberg Areas . . . . 8 42 2,723 2,975 2
Laurel Ridge Field . . 1 50 1,729 2,029 2
Others . . . . . . . . 185 656 6,987 10,923 7
--- --- ----- ------ -
Subtotal . . . . . . 331 2,009 68,593 80,647 55%
--- ----- ------ ------ ---
Rocky Mountain:
Big Horn Basin . . . . 200 3,622 18,213 39,945 27
San Juan Basin . . . . 49 -- 11,978 11,978 8
Sweet Grass Arch Basin 178 554 1,446 4,770 3
Green River Basin . . . 82 42 4,666 4,918 3
Others . . . . . . . . 22 89 4,556 5,090 4
-- -- ----- ----- -
Subtotal . . . . . . 531 4,307 40,859 66,701 45%
--- ----- ------ ------ ---
Total . . . . . 862 6,316 109,452 147,348 100%
=== ===== ======= ======= ====
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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 20 different Upper Wilcox sands
with formation depths ranging from 9,500 to 13,500 feet that require
stimulation by hydraulic fracturing to effectively recover the reserves.
Because the majority of this field is situated under Lake Falcon on the Rio
Grande River, most wells must be drilled directionally under the lake from
common lakeshore drill sites. The Company owns interests in two principal
areas in the Bob West Field. During September 30, 1995 the average combined
rate of production attributable to the Company's net revenue interest was
approximately 15,500 Mcf per day. 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. 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. As of September 30, 1995, these units contained 28 producing wells
with a combined rate of production attributable to the Company's net revenue
interest of approximately 7,500 Mcf per day.
The Company also owns a 100% working interest in and is the operator
for 511 acres referred to as the Falcon/Bob West property. A 320-acre portion
of this acreage is covered by the Tennessee Gas Contract and contains 15
producing natural gas wells that, during September 30, 1995, had an average
combined rate of production attributable to the Company's net revenue interest
of approximately 8,000 Mcf per day. The balance of the Company's interest in the
Falcon/Bob West property consists of a 40-acre tract and a 151-acre tract
immediately adjacent to the Tennessee Gas Contract acreage. Two wells have been
drilled on this acreage and a third is in the planning stage.
Langham Creek Area. This area is comprised of the Cypress Deep and
Langham Creek Fields in western Harris County, Texas, where the Company has
non-operated interests in approximately 4,500 gross (2,362 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 six wells in this area. The wells include two wells that were recently
completed, one in the Yegua formation that is not yet producing and one in the
Wilcox formation that was recently opened into the sales line. Two of the
wells, one in the Wilcox and one in the Yegua, were shut-in at September 30,
1995, but were recompleted in December 1995. During September 1995, the four
producing wells in the Wilcox zone and had an average combined rate of
production attributable to the Company's interest of approximately 3,400 Mcf
and 44 Bbls per day. The Langham Creek Area is actively being developed and
additional wells are scheduled to be drilled in 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 drilling
another well, in which it has a 62% net revenue interest, to test deeper zones
on this acreage. During September 1995, the average rate of production from the
field attributable to the Company's interest was approximately 2,468 Mcf per
day.
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
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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. An additional one or two
development wells are scheduled to be drilled in fiscal 1996, and the Company
believes that each well has a potential for three to five Bcf of gross
reserves. During September 1995, the average rate of production attributable
to the Company's interest was approximately 1,200 Mcf and 2 Bbls per day.
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 six months and are expected to peak in about three years. If the first
phase proves successful, a second phase is expected to be initiated to
waterflood the remaining portion of the field to facilitate recovery of the
full volume of anticipated 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%. During
September 1995, the average production rate attributable to the Company's
interest was 429 Mcf and 67 Bbls per day.
Birdie Field. This field is located in Karnes County, Texas and
consists of a single well located on a 320-acre natural gas unit with
production from a middle Wilcox age sand at approximately 11,800 feet. The
Company owns a 27% non-operated net revenue interest in this well, which during
September 1995 had an average rate of production attributable to the Company's
interest of 1,449 Mcf and 34 Bbls per day. The Company does not believe that
additional wells are required to recover the reserves on this property.
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 seven non-operated wells in this area. During
September 1995, the average rate of production attributable to the Company's
interest was 627 Mcf and 9 Bbls per day.
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. An additional seismic program is
scheduled to establish locations for additional wells to be drilled during
1996.
ROCKY MOUNTAIN PROPERTIES
Big Horn Basin. This basin is located in Hot Springs, Inashakie,
Sweetwater, Bighorn and Park Counties, Wyoming and 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
9
11
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 combined average rate
of production attributable to the Company's interest during the last week of
September 1995 was approximately 2,000 Mcf and 590 Bbls per day. 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. During the last week of September 1995, the wells had an average rate of
production attributable to the Company's interest of 1,600 Mcf per day.
Sweet Grass Arch Basin. The Company has an interest in 71,539 gross
(47,009 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. During the last week of
September 1995, the average combined rate of production attributable to the
Company's interest in this basin was 625 Mcf and 168 Bbls per day. The Company
has identified 55 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 a natural gas gathering system consisting of
approximately 200 miles of pipeline that currently gathers approximately 1,700
Mcf per day of third-party natural gas on this property.
Green River Basin. This area is located in Carbon, Sweetwater and
Lincoln Counties, Wyoming and La Platta County, Colorado, where the Company has
an interest in 20,076 gross (16,884 net) acres. It operates 22 wells and has
non-operating 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. During the last week of
September 1995, the average rate of production attributable to the Company's
interest in this area was 1,284 Mcf and 7 Bbls per day. 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 September 30, 1995, after giving
effect to the Michigan Acquisition, 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 October 1, 1995 through September 30, 2006. Total
future net cash flow to the Company from the volumetric production payment
deliveries scheduled below is estimated to be $75.3 million based on prices in
effect at September 30, 1995 of $1.65 per Mcf and $17.00 per Bbl, before
adjustments for appropriate basis differentials and Btu content.
CUMULATIVE
NATURAL GAS OIL TOTAL TOTAL
PERIOD FROM TO (MMcf) (Mbbls) (MMcfe) (MMcfe)
----------- -- ------ ------- ------- -------
October 1, 1995 September 30, 1996 . . . . 11,747 221 13,073 13,073
October 1, 1996 September 30, 1997 . . . . 7,972 208 9,220 22,293
October 1, 1997 September 30, 1998 . . . . 5,405 173 6,443 28,736
October 1, 1998 September 30, 1999 . . . . 1,732 127 2,494 31,230
October 1, 1999 September 30, 2000 . . . . 1,303 92 1,855 33,085
October 1, 2000 September 30, 2006 . . . . 3,849 254 5,373 38,458
The properties underlying the volumetric production payment program
are located in two major regions, offshore Gulf Coast and in the Niagaran Reef
trend in northern and southern Michigan.
10
12
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. The Texas and Louisiana blocks contain
eight wells drilled during 1994 and 1995 to depths ranging from 1,700 to 9,050
feet in the shallow waters of the Gulf of Mexico. Production attributable to
HHOC's working interest during the month of September 1995 averaged 39,575 Mcf
per day, of which an average of 20,432 Mcf per day was delivered to the Company
under the volumetric production payment program. Proved reserves attributable
to HHOC's interest, which support the volumetric production payment, were
estimated by an independent reserve engineer to be 29,700 MMcf as of September
30, 1995. Pursuant to the HHOC volumetric production payment, the Company
received deliveries totaling 4,471 MMcf during fiscal 1995 and is scheduled to
receive 9,212 MMcf in fiscal 1996, 5,132 MMcf in fiscal 1997 and 3,046 MMcf in
fiscal 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 104 MMcf in fiscal 1994, 593 MMcf in fiscal 1995 and is
scheduled to receive deliveries totaling 732 MMcf in fiscal 1996 and 1997.
In addition, the Company is scheduled to receive volumes totaling 375
MMcfe during the period from 1996 to 1998 from several smaller volumetric
production payments covering onshore Gulf Coast and Appalachian properties.
NIAGARAN REEF TREND PROPERTIES IN MICHIGAN
The properties underlying the volumetric production payment acquired
by the Company in the Michigan Acquisition 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 Hawkins. Additional reserves available to
support the production payment may be derived from a series of recompletions
scheduled during 1995 and 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.
Production rates from the property interests supporting the payment during
September 1995 averaged 6,926 Mcf and 599 Bbls per day. An independent
reservoir engineer estimated at October 1, 1995 that 19,465 MMcf and 1,320
Mbbls were attributable to Hawkins' interest in these properties to support the
payment, with approximately 80% of the reserves contained in 20 wells. 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 taken from reports prepared by R.A. Lenser and Associates, Inc. (the
onshore Gulf Coast properties), H.J. Gruy and Associates, Inc. (the Rocky
Mountain properties) and Netherland, Sewell & Associates, Inc. (the working
interests in Michigan), 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.
Although reserve engineers' reports with respect to reserves
underlying the Company's volumetric production payment program are utilized by
the Company to support its own analysis of such reserves, the proved reserves
and related future net revenues that the Company reports with respect to
volumetric production payments are not derived from independent reserve
engineers' reports, but rather are taken directly from the amounts contracted
for pursuant to the agreements relating to each volumetric production payment
(which amounts are less than the net interest production reflected in the
reserve reports). Reports prepared by Netherland, Sewell & Associates, Inc.
(the volumetric production payment properties owned by Hawkins in Michigan) and
Ryder Scott Company (the volumetric production payment properties owned by HHOC
in the offshore Gulf Coast region)
11
13
include all the reserves of each field from which the Company's interest is
taken.
The following table sets forth, as of September 30, 1995 and giving
effect to the Rocky Mountain and Michigan Acquisitions, summary information
with respect to (i) the estimates made by the reserve engineers of the
Company's proved oil and gas reserves attributable to working interests and
(ii) the reserve amounts contracted for pursuant to the agreements relating to
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.
SEPTEMBER 30,
1995
----
PROVED RESERVES:
Oil (Mbbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,624
Natural gas (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . . 144,718
Total (MMcfe) . . . . . . . . . . . . . . . . . . . . . . . 190,462
Future net revenues ($000s) . . . . . . . . . . . . . . . . . . . . . $385,916
Present value of future net revenues ($000s) . . . . . . . . . . . . $279,004
PROVED DEVELOPED RESERVES:
Oil (Mbbls) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,854
Natural gas (MMcf) . . . . . . . . . . . . . . . . . . . . . . . . . 123,350
Total (MMcfe) . . . . . . . . . . . . . . . . . . . . . . . 146,474
Future net revenues ($000s) . . . . . . . . . . . . . . . . . . . . . $312,623
Present value of future net revenues ($000s) . . . . . . . . . . . . $235,798
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.
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 and with the
assumption that 85% of the Company's delivery capacity from the specified units
in the field will be sold at such price. (See Item 3). As of September 30,
1995, spot prices were $1.65 per Mcf and $17.00 per Bbl, before adjustments for
appropriate differentials and Btu content. The prices for natural gas and, to a
lesser extent, oil are subject to substantial seasonal fluctuations, and prices
for each are subject to substantial fluctuations as a result of numerous other
factors.
ACREAGE
The following table sets forth certain information with respect to the
Company's developed and undeveloped leased acreage as of September 30, 1995,
after giving effect to the Rocky Mountain Acquisition. 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.
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DEVELOPED ACRES UNDEVELOPED ACRES
--------------- -----------------
GROSS NET GROSS NET
----- --- ----- ---
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 10,137
Colorado . . . . . . . . . . . . 10,990 6,510 -- --
Louisiana . . . . . . . . . . . . 969 307 46,544 43,825
Other . . . . . . . . . . . . . . 1,376 322 -- --
----- ------- ------- -------
Total . . . . . . . . . 191,748 155,340 137,592 129,669
======= ======= ======= =======
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 September 30, 1993,
1994 and 1995, is set forth below. The table does not reflect any drilling
activities with respect to the recently acquired Rocky Mountain properties or
with respect to any properties subject to volumetric production payments.
YEAR ENDED SEPTEMBER 30,
------------------------
1995 1994 1993
---- ---- ----
TYPE OF WELL GROSS NET GROSS NET GROSS NET
------------ ----- --- ----- --- ----- ---
Development:
Oil . . . . . . . . . . 1 0.4 - - - -
Natural gas . . . . . . 13 4.9 28 14.1 10 4.2
Non-productive . . . . - - - - 1 0.4
-- --- -- ---- -- ---
Total . . . . . 14 5.3 28 14.1 11 4.6
== === == ==== == ===
Exploratory:
Oil . . . . . . . . . . 1 0.4 2 1.4 1 0.3
Natural gas . . . . . . 8 3.4 10 2.4 4 1.4
Non-productive . . . . 10 5.3 10 2.2 4 1.2
-- --- -- --- - ---
Total . . . . . 19 9.1 22 6.0 9 2.9
== === == === = ===
At September 30, 1995, the Company was participating in the drilling
or completion of 12 gross (4.2 net) wells.
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15
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 September 30,
1995, 1994 and 1993. The table does not reflect any production or sales
attributable to the Rocky Mountain or Michigan Acquisitions.
YEAR ENDED SEPTEMBER 30,
------------------------
1995 1994 1993
---- ---- ----
Net natural gas produced (MMcf):
Tennessee Gas Contract . . . . . . . . . 7,847 5,643 3,124
Other . . . . . . . . . . . . . . . . . . 9,386 3,593 2,465
----- ----- -----
Total . . . . . . . . . . . . . . 17,233 9,236 5,589
Average natural gas sales price ($ per Mcf):
Tennessee Gas Contract . . . . . . . . . $7.79 $7.34 $7.00
Other . . . . . . . . . . . . . . . . . . $1.50 $1.98 $1.99
Average . . . . . . . . . . . . . . . . . $4.77 $5.56 $4.79
Net oil produced (Mbbls) . . . . . . . . . 167 200 171
Average oil sales price ($ per Bbl) . . . . $16.90 $15.20 $18.52
Gas equivalents produced (MMcfe) . . . . . 18,235 10,436 6,615
Production costs ($ per Mcfe) . . . . . . . $0.35 $0.62 $0.64
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 Conroe, Texas, the intrastate
transmission system operations are based in an 1,800 square foot Company-owned
facility. As a result of the Rocky Mountain Acquisition, the Company leases
a 10,000 square foot facility in Worland, Wyoming.
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 35 and 36 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 September
30, 1995.
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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:
Fiscal 1995
--------------------------------------------------------------------------------------------
Oct. - Dec. Jan. - Mar. Apr. - June July - Sept.
--------------------------------------------------------------------------------------------
Market Price
High $18.75 $17.25 $22.25 $21.88
Low 12.25 14.63 15.25 13.75
--------------------------------------------------------------------------------------------
Fiscal 1994
--------------------------------------------------------------------------------------------
Oct. - Dec. Jan. - Mar. Apr. - June July - Sept.
--------------------------------------------------------------------------------------------
Market Price
High $31.50 $29.00 $26.38 $21.88
Low 18.00 21.75 19.63 16.13
--------------------------------------------------------------------------------------------
There were 1,408 stockholders of record of the Company's Common Stock on
December 15, 1995.
The Company pays dividends on a quarterly basis. The aggregate amount
of dividends declared were $920,000 and $1,377,000 in 1994 and 1995,
respectively. Under its long-term debt agreements, aggregate cash dividends are
limited to one-half of the Company's net income after September 30, 1993.
Item 6. Selected Financial Data.
The following table sets forth the Company's selected Financial Data
for each of the five years ended September 30, 1995.
--------------------------------------------------------------------------------------------
Dollars in thousands (except
per share data) 1995 1994 1993 1992 1991
--------------------------------------------------------------------------------------------
Revenue $423,580 $335,598 $271,676 $143,651 $98,946
Net income 22,777 23,281 13,678 3,335 2,495
Total assets 271,982 181,416 152,668 74,657 60,499
Long-term debt 90,800 48,571 30,907 17,757 16,028
Stockholders' equity 95,625 73,766 51,424 29,015 25,701
Per common share:
Net income 1.94 1.97 1.19 0.30 0.23
Stockholders' equity 8.33 6.45 4.52 2.69 2.41
Dividends 0.12 0.08 0.04 0.025 --
============================================================================================
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.
RESULTS OF OPERATIONS -- CONSOLIDATED
Net income was $22.8 million ($1.94 per share) in 1995 compared to
$23.3 million ($1.97 per share) in 1994 and $13.7 million ($1.19 per share) in
1993. The 1995 earnings were impacted by depressed natural gas prices, due in
part to milder than normal winter weather conditions and an oversupply of
natural gas in North America. The increase in 1995 oil and gas operating income
resulting from the Company's expanded oil and gas operations was offset by
losses incurred by the energy marketing and services segment and higher net
interest costs incurred principally to fund the growth of the oil and gas
operations.
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, augmented by the
increased profitability of the Company's other business segments. See Note 7 to
Consolidated Financial Statements for information regarding the Tennessee Gas
Contract.
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On December 11, 1995, 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. The change will become effective on
January 1, 1996. A three-month fiscal transition period from October 1, 1995
through December 31, 1995 will precede the start of the new fiscal year. The
following discussion is based on the Company's September 30 fiscal 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
affected by low natural gas prices in 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
YEAR ENDED SEPTEMBER 30,
------------------------
1995 1994 1993
---- ---- ----
(DOLLARS IN THOUSANDS)
Revenue . . . . . . . . . . . . . . . . . . $84,640 $57,295 $30,450
Production costs . . . . . . . . . . . . . 6,463 6,518 4,248
Depreciation, depletion and amortization . 35,708 13,903 5,016
Other operating expenses . . . . . . . . . 2,665 2,052 1,564
----- ----- -----
Operating income . . . . . . . . . . . . . $39,804 $34,822 $19,622
======= ======= =======
Oil production (Mbbl) . . . . . . . . . . . 167 200 171
Natural gas production (MMcf):
Tennessee Gas Contract . . . . . . . . . 7,847 5,643 3,124
Non-contract . . . . . . . . . . . . . . 9,386 3,593 2,465
----- ----- -----
Total natural gas production . . 17,233 9,236 5,589
====== ===== =====
Average sales price:
Oil (per Bbl) . . . . . . . . . . . . . . $16.90 $15.20 $18.52
Natural gas (per Mcf) . . . . . . . . . . $4.77 $5.56 $4.79
Average lifting cost:
Oil (per Bbl) . . . . . . . . . . . . . . $6.88 $6.36 $6.01
Natural gas (per Mcf) . . . . . . . . . . $0.31 $0.56 $0.54
DD&A as a percent of revenues . . . . . . . 42.2% 24.2% 16.3%
===== ===== =====
The 87% increase in natural gas production in 1995 as compared to 1994
was due mainly to the increase in production from properties not covered by the
Tennessee Gas Contract.
Approximately 5.0 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 57% of total production in 1995 compared to 46% in
1994 and 53% 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, revenue and operating income
were up significantly in 1995, a 24% decline in average non-contract natural
gas prices hindered the overall profitability of this segment. Average
non-contract natural gas prices were approximately $1.50 in 1995 compared to
$1.98 in 1994 and $1.99 in 1993.
Tennessee Gas Contract production increased in 1995 compared to 1994
largely as a result of the continued development of the Bob West Field. Average
sales prices under the Tennessee Gas Contract, excluding severance tax
reimbursements, were $7.79 in 1995, $7.34 in 1994 and $7.00 in 1993. Planned
development of known
16
18
producing horizons in this field was largely completed by the end of fiscal
1995. The Company anticipates that production levels will decline in this field
in 1996, absent any new discoveries in as yet unexplored horizons. See Note 7
to Consolidated Financial Statements for information regarding the Tennessee
Gas Contract.
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 and current low natural gas prices applied to
reserves to be produced in the future. 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 44% reduction in average lifting cost 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 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.
Subsequent Events
Subsequent to September 30, 1995 the Company completed two significant
oil and gas reserve acquisitions. See Note 11 to Consolidated Financial
Statements.
The Rocky Mountain Acquisition was completed on November 8, 1995. This
acquisition added proved reserves of approximately 41 Bcf of natural gas and
4.3 MMbbls of oil to the Company's reserve base. In addition, this acquisition
provides the Company with an existing operation and infrastructure in a new
geographic area with high percentage working interests in properties that the
Company believes contain a significant number of development drilling, workover
and recompletion opportunities, as well as additional exploratory
opportunities.
On December 7, 1995 the Company completed the Michigan Acquisition.
This acquisition included a volumetric production payment which added 13.7 Bcf
of natural gas and 1.1 MMbbls of oil to the Company's proved reserve base and,
in a related transaction, escalating working interests in related properties
which added 3.1 Bcf of gas and 219 Mbbls of oil to the Company's proved
reserves. The volumetric production payment reserves will be produced
principally from 89 wells on properties located in the Niagaran Reef trend.
Natural Gas Transportation
YEAR ENDED SEPTEMBER 30,
------------------------
1995 1994 1993
---- ---- ----
(DOLLARS IN THOUSANDS)
Revenue . . . . . . . . . . . . . . . . . . . . . $24,454 $19,078 $16,030
Cost of natural gas sales . . . . . . . . . . . . 20,473 15,379 13,136
------ ------ ------
Gross margin . . . . . . . . . . . . . . . . . 3,981 3,699 2,894
Depreciation . . . . . . . . . . . . . . . . . . 861 852 755
Other operating expenses . . . . . . . . . . . . 1,812 1,498 1,240
----- ----- -----
Operating income . . . . . . . . . . . . . . . $1,308 $1,349 $899
====== ====== ====
Volume (Bcf) . . . . . . . . . . . . . . . . . . 25.0 21.4 22.9
Gross margin per Mcf . . . . . . . . . . . . . . $0.159 $0.173 $0.126
====== ====== ======
The increases in revenue, gross margin and volume in 1995 compared to
1994 were largely due to the expansion of the Company's existing pipeline and
gathering systems. The expansion was 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 in 1995 from the new system supply
and the associated liquids profits largely offset the
17
19
mild weather conditions as compared to the extreme conditions experienced
during the 1994 winter heating season. During 1994, the Company achieved higher
margins on its natural gas sales and transportation to certain high-priority,
weather-sensitive customers.
The increase in other operating expenses in 1995 compared to 1994 was
primarily due to costs associated with the operation of the Company's gathering
systems, expansion of supply gathering laterals 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 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
YEAR ENDED SEPTEMBER 30,
------------------------
1995 1994 1993
---- ---- ----
(DOLLARS IN THOUSANDS)
Revenue . . . . . . . . . . . . . . . . . . . . $328,201 $263,104 $226,418
Cost of natural gas sales . . . . . . . . . . . 322,932 254,750 219,838
------- ------- -------
Gross margin . . . . . . . . . . . . . . . 5,269 8,354 6,580
Operating expenses . . . . . . . . . . . . . . 6,102 5,966 4,802
----- ----- -----
Operating income (loss) . . . . . . . . . $(833) $2,388 $1,778
====== ====== ======
Volume (Bcf) . . . . . . . . . . . . . . . . . 214.1 147.0 106.7
Gross margin per Mcf . . . . . . . . . . . . . $0.025 $0.057 $0.062
Operating expense per Mcf . . . . . . . . . . . $0.029 $0.041 $0.045
====== ====== ======
While each of the Company's business segments were affected by low
natural gas prices in 1995, the energy marketing and services segment was
impacted the most. During 1995, there was continued consolidation within the
natural gas marketing industry. In addition, state regulatory bodies continued
to pressure end-user utility customers to purchase natural gas supplies at the
lowest possible price.
The combination of (i) low natural gas prices, (ii) increased
competitive pressures within the industry and (iii) the absence of severe
weather conditions and the related opportunities presented by more volatile
natural gas prices during the peak winter heating season were the primary
reasons for the 1995 operating loss. Average natural gas prices were
approximately $0.50 per Mcf lower in 1995 compared to 1994 and average per unit
gross margins were approximately $0.032 lower than last year. In addition, a
major cogeneration plant serviced by the Company was under repair and out of
service during the first fiscal quarter and two other cogeneration plants
serviced by the Company were placed in standby mode (where they will only
operate on an as needed or emergency basis) since the end of the first fiscal
quarter.
Operating expenses, while up slightly in 1995 compared to 1994, were
significantly lower on a per Mcf basis ($0.029 per Mcf in 1995 compared to
$0.041 per Mcf in 1994).
The increase in gross margin in 1994 compared to 1993 was due in part
to the unusually cold 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.
The increase in operating costs in 1994 reflected higher personnel and
marketing costs to support the significant growth in operations.
18
20
Interest and Other Income, Net
Interest and other income was $2.4 million in 1995 compared to $1.1
million in 1994 and $0.7 million in 1993. Of the 1995 amount, $2.0 million was
interest income recorded on the difference between the full contract price and
the price currently paid by Tennessee Gas under interim agreements. See "--
Liquidity and Capital Resources"and Note 7 to Consolidated Financial
Statements. In addition the Company had $0.4 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 $6.0 million in 1995 compared to $2.4 million in
1994 and $1.8 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 its volumetric production payment program
which began in late fiscal 1994. Higher average interest rates were also a
contributing factor in the year to year increases. 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.
Income Taxes
The income tax provision was $11.6 million in 1995 representing an
effective tax rate of 33.7%. This compares with effective tax rates in 1994 and
1993 of 33.5% and 28.1%, respectively. The slight increase in the effective tax
rate in 1995 compared to 1994 was primarily due to higher state taxes offset in
part by higher statutory depletion and Section 29 credits. The 1994 increase
over 1993 reflected significantly higher pre-tax income combined with
approximately the same level of permanent tax differences. A substantial
portion of the income taxes provided by the Company during these periods are
deferred to future years. See Note 6 to Consolidated Financial Statements.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flow from Operating Activities
Net income adjusted for non-cash charges increased to $71.2 million in
1995 compared to $47.8 million in 1994. However, net cash provided by operating
activities in 1995 declined from $45.7 million in 1994 to $32.7 million
primarily as a result of certain interim agreements with Tennessee Gas entered
into during the course of fiscal 1995. Under the interim agreements, Tennessee
Gas has been paying $3.00 per MMBtu, including severance taxes, since September
17, 1994 for all gas taken under the Tennessee Gas Contract. See Note 7 to
Consolidated Financial Statements. Since net cash flow from operating
activities reflects only the $3.00 cash price per MMBtu, the interim agreements
had a significant impact on 1995 cash flow. 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.
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 September 30, 1995, the Company had
recorded cumulative revenue of approximately $141 million for natural gas sold
under the Tennessee Gas Contract based on prices as defined in the contract, of
which approximately $101 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
19
21
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 September 30, 1995, the total net receivable was $46.2 million. See Note
7 to Consolidated Financial Statements. The Company could be required to write
off a portion or all of this receivable if Tennessee Gas ultimately prevails in
the litigation. In addition, as of September 30, 1995, the Company had been
paid approximately $56 million in excess of spot market prices (or prices of
$3.00 per MMBtu for the period from September 17, 1994 to August 1, 1995) for
the natural gas sold under the Tennessee Gas Contract. The Company could be
required to return to Tennessee Gas a portion or all of this amount if
Tennessee Gas ultimately prevails in the litigation.
Trade accounts receivable increased $8.5 million and accounts payable
and accrued liabilities increased $16.0 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 the timing of cash receipts and
payments of the oil and gas exploration and production operations.
Master Note Facility
The Company has a Master Note Facility with a bank group which is used
for the expansion of its exploration and production and natural gas
transportation businesses and is secured by substantially all their assets. The
size of the Master Note Facility, which sets the maximum limit of potential
borrowings under the agreement, was $100 million at September 30, 1995. The
amount of credit available (the borrowing base) is a function of the lenders'
evaluation of the oil and gas properties pledged as collateral. The Master Note
Facility matures on October 1, 1998. In 1995, the borrowing base was increased
to $75 million. At September 30, 1995, the Company had utilized $69.6 million
of the availability under the Master Note Facility, $58.5 million as cash
advances and $11.1 million for the issuance of letters of credit in favor of
the operator of the Bob West Field as a condition to the release of certain
funds.
Subsequent to September 30, 1995, the Master Note Facility was amended
to increase both the maximum credit limit to $120 million and the borrowing
base to $102 million, effective upon the completion of the Rocky Mountain
Acquisition. See Notes 4 and 11 to Consolidated Financial Statements.
Revolving Credit Facilities
In January 1995, the Company's natural gas marketing subsidiary
replaced its existing working capital facility with two new revolving credit
facilities. A receivables facility (the "Receivables Facility") supports the
expansion of the natural gas marketing operations while a volumetric production
payment facility (the "VPP Facility") provides financing for its volumetric
production payment program.
The Receivables Facility is secured by the natural gas marketing
subsidiary's accounts receivable and other assets (excluding those pledged
under the VPP Facility) and a pledge of that subsidiary's common stock. During
1995, the maximum credit limit under the Receivables Facility was increased
from the initial $25 million to $35 million. The borrowing base, or actual
availability under the Receivables Facility, is reviewed monthly and is set at
the lesser of the maximum credit limit or Eligible Receivables (as defined in
the Receivables Facility). As of September 30, 1995, the borrowing base and the
outstanding balance under the Receivables Facility was $22.3 million. The
Receivables Facility matures in December 1996.
The VPP Facility is secured by the oil and gas reserves purchased
through volumetric production payments. The maximum credit limit under this
facility as of September 30, 1995 was $25 million. The borrowing base, or
actual availability under the VPP Facility, is reviewed at least semi-annually
and may be subject to change based upon the lender's evaluation of the oil and
gas reserves pledged as collateral and other factors. At September 30, 1995,
the borrowing base was $15 million and the amount outstanding under the VPP
Facility was $10 million. The VPP Facility matures in January 1999.
In November 1995, the VPP Facility was amended to increase both the
maximum credit commitment to $50 million and the borrowing base to $38 million
simultaneous with the closing of the Michigan Acquisition. See Notes 4 and 11
to Consolidated Financial Statements.
20
22
Note Financing
On November 17, 1995, KCS entered into the $25 million Note Financing.
Proceeds from the Note Financing were used to fund a portion of the Michigan
Acquisition. In addition, the Note Financing will be used for the Company's oil
and gas exploration and production operations and general corporate purposes.
The Note Financing is secured by all of the assets of KCS other than the
capital stock of its marketing subsidiary. The Company anticipates replacing
the Note Financing with more permanent financing early in 1996. The Note
Financing matures in November 1996; however, the Company has the right to
extend the maturity date until June 1997. See Notes 4 and 11 to Consolidated
Financial Statements.
Capital Expenditures
Capital expenditures in 1995 were $78.1 million, of which $73.3
million was invested in oil and gas properties. Of the $73.3 million, $26.1
million was for the purchase of gas reserves under the Company's volumetric
production payment program, $21.3 million for the development of the Bob West
Field and the remainder was largely to conduct seismic evaluation and
exploratory drilling ($15.4 million) and development drilling ($10.5 million)
on non-contract properties. The Company funded its capital expenditures with a
mix of internally generated cash and additional borrowings under its credit
facilities.
Capital expenditures in 1994 were $66.1 million, $64.5 million of
which was for oil and gas properties. Of these, $36.0 million was for
development drilling, primarily in the Bob West Field, $10.7 million for
exploratory drilling and $17.8 million for producing property acquisitions,
including $9.6 million for the acquisition of oil and gas reserves through
volumetric production payments.
During 1993, the Company's capital spending totaled $41.3 million of
which $39.8 million was invested in oil and gas properties. This included $17
million for exploratory and development drilling in the Bob West Field, $4
million for development and exploratory drilling on other properties and $19
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 the 1996 fiscal year is budgeted at $113 million,
primarily for the expansion of the oil and gas operations. Two significant
acquisitions totaling $64.0 million (subject to certain adjustments) were
completed in November and December 1995. See Note 11 to Consolidated Financial
Statements. The 1996 capital budget includes approximately $12 million for
development and exploratory drilling of these properties. In addition, the 1996
budget includes approximately $13 million for development and $12 million for
exploratory drilling of other properties, $10 million for volumetric production
payments and $2 million for pipeline and other assets. The 1996 capital plan
will be financed through a combination of cash generated by operations and
borrowings under existing 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. While the Company is continuing to review adoption alternatives,
SFAS No. 121 is not anticipated to have a material impact on the financial
position or results of operations of the Company.
Item 8. Financial Statements and Supplementary Data.
The consolidated financial statements of the Company and the report of
independent public accountants thereon are presented on pages 22 through 43 of
this Form 10-K.
21
23
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 September 30, 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 September
30, 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.
A KCS subsidiary is selling gas to Tennessee Gas Pipeline Company
(Tennessee Gas) under a long-term contract at a price that is substantially
higher than the current market price. The contract has been subject to ongoing
litigation since August 1990. In August 1995, the Texas Supreme Court affirmed
a 1993 ruling of the Texas Fourth Court of Appeals. The ruling upheld the
contract's pricing and pooling provisions, but remanded to the District Court
for trial the question of whether natural gas volumes taken by Tennessee Gas
under the contract were delivered in good faith and were not unreasonably
disproportionate to a normal or otherwise comparable prior output or the
expectations of the parties. The Company and its co-sellers have filed a
request for rehearing of the volume issue, which is currently pending. As of
September 30, 1995, the Company had recorded cumulative revenue of
approximately $141 million under the contract of which approximately $101
million is at issue in the litigation. For further discussion of this matter,
refer to Note 7 to the Consolidated Financial Statements.
Our audits were made for the purpose 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.
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 September 30, 1995 and 1994, and the results of their
operations and their cash flows for each of the three years in the period ended
September 30, 1995 in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
New York, New York
December 7 , 1995
22
24
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(DOLLARS IN THOUSANDS)
FOR THE YEARS ENDED SEPTEMBER 30,
1995 1994 1993
-------------------------------------------------------------------------------------------------------------
Revenue $423,580 $335,598 $271,676
-------------------------------------------------------------------------------------------------------------
Operating costs and expenses
Cost of gas sales 330,600 267,056 231,807
Other operating and administrative expenses 18,173 17,095 13,767
Depreciation, depletion and amortization 36,858 15,154 6,012
-------------------------------------------------------------------------------------------------------------
Operating costs and expenses 385,631 299,305 251,586
-------------------------------------------------------------------------------------------------------------
Operating income 37,949 36,293 20,090
Interest and other income, net 2,419 1,057 698
Interest expense (6,036) (2,359) (1,764)
-------------------------------------------------------------------------------------------------------------
Income before income taxes 34,332 34,991 19,024
Federal and state income taxes 11,555 11,710 5,346
-------------------------------------------------------------------------------------------------------------
Net income $22,777 $23,281 $13,678
-------------------------------------------------------------------------------------------------------------
Earnings per share of common stock and common
stock equivalents $1.94 $1.97 $1.19
-------------------------------------------------------------------------------------------------------------
Average shares of common stock and common stock
equivalents outstanding 11,759,372 11,828,320 11,536,375
-------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
23
25
KCS ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
SEPTEMBER 30,
------------------------
1995 1994
---- ----
ASSETS
Current assets
Cash and cash equivalents $4,187 $5,075
Trade accounts receivable, less allowance for doubtful
accounts --1995, $347; 1994, $249 44,094 35,632
Fuel inventories 1,206 2,327
Federal income taxes receivable 296 840
Other current assets 5,586 3,856
-------------------------------------------------------------------------------------------------------------
Current assets 55,369 47,730
-------------------------------------------------------------------------------------------------------------
Oil and gas properties, full cost method, less accumulated DD&A --
1995, $77,451; 1994, $41,837 146,130 112,470
Natural gas transportation systems, at cost less accumulated
depreciation -- 1995, $4,004; 1994, $3,274 18,897 17,379
Other property, plant and equipment, at cost less accumulated
depreciation -- 1995, $1,342; 1994, $2,038 1,500 1,483
-------------------------------------------------------------------------------------------------------------
Property, plant and equipment, net 166,527 131,332
-------------------------------------------------------------------------------------------------------------
Other assets
Receivable from Tennessee Gas 46,182 --
Investments and other assets 3,904 2,354
-------------------------------------------------------------------------------------------------------------
Other Assets 50,086 2,354
-------------------------------------------------------------------------------------------------------------
$271,982 $181,416
=============================================================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Current maturities of long-term debt $-- $1,722
Accounts payable 54,362 34,419
Accrued liabilities 3,752 5,990
-------------------------------------------------------------------------------------------------------------
Current liabilities 58,114 42,131
-------------------------------------------------------------------------------------------------------------
Deferred credits and other liabilities
Deferred federal and state income taxes 24,511 14,309
Other 2,932 2,639
-------------------------------------------------------------------------------------------------------------
Deferred credits and other liabilities 27,443 16,948
-------------------------------------------------------------------------------------------------------------
Long-term debt 90,800 48,571
-------------------------------------------------------------------------------------------------------------
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 12,379,058 and 12,324,116, respectively 124 123
Additional paid-in capital 24,240 23,745
Retained earnings 74,533 53,133
Less treasury stock, 892,748 and 890,248 shares, respectively -- at cost (3,272) (3,235)
-------------------------------------------------------------------------------------------------------------
Total stockholders' equity 95,625 73,766
-------------------------------------------------------------------------------------------------------------
$271,982 $181,416
=============================================================================================================
The accompanying notes are an integral part of these financial statements.
24
26
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY
(DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA)
Additional
Common Paid- in Retained Treasury Stockholders'
Stock Capital Earnings Stock Equity
- --------------------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1992 $116 $12,578 $17,647 $(1,326) $29,015
Stock issuances - option and benefit plans 3 707 -- -- 710
- acquisitions 3 6,176 -- -- 6,179
Tax benefit on stock option exercises -- 2,395 -- -- 2,395
Net income -- -- 13,678 -- 13,678
Dividends ($0.04 per share) -- -- (553) -- (553)
- --------------------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1993 122 21,856 30,772 (1,326) 51,424
Stock issuances - option and benefit plans 1 658 -- -- 659
Tax benefit on stock option exercises -- 1,231 -- -- 1,231
Net income -- -- 23,281 -- 23,281
Dividends ($0.08 per share) -- -- (920) -- (920)
Purchase of treasury stock -- -- -- (1,909) (1,909)
- --------------------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1994 123 23,745 53,133 (3,235) 73,766
Stock issuances - option and benefit plan 1 255 - - 256
Tax benefit on stock option exercises - 240 - - 240
Net income - - 22,777 - 22,777
Dividends ($0.12 per share) - - (1,377) - (1,377)
Purchase of treasury stock - - - (37) (37)
- --------------------------------------------------------------------------------------------------------------------------------
Balance at September 30, 1995 $124 $24,240 $74,533 $(3,272) $95,625
================================================================================================================================
The accompanying notes are an integral part of these financial statements.
25
27
KCS ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(DOLLARS IN THOUSANDS)
FOR THE YEARS ENDED SEPTEMBER 30,
1995 1994 1993
------------------------------------
Cash flows from operating activities:
Net income $22,777 $23,281 $13,678
Non-cash charges (credits):
Depreciation, depletion and amortization 36,858 15,154 6,012
Deferred income taxes 10,847 9,557 1,440
Other non-cash charges and credits, net 725 (186) (570)
- -------------------------------------------------------------------------------------------------------
71,207 47,806 20,560
Net changes in assets and liabilities:
Trade accounts receivable (8,462) 18,757 (32,517)
Receivable from Tennessee Gas (46,182) -- --
Fuel inventories 1,121 (643) (279)
Other current assets (1,730) (1,001) (1,974)
Accounts payable and accrued liabilities 18,040 (18,888) 36,112
Federal and state income taxes 211 (2,416) 1,718
Other, net (1,521) 2,037 (169)
- -------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 32,684 45,652 23,451
Cash flows from investing activities:
Investment in oil and gas properties (73,343) (64,479) (29,600)
Proceeds from the sale of oil and gas properties 5,524 -- --
Investment in natural gas transportation systems (3,823) (1,007) (1,124)
Investment in other property, plant and equipment (929) (577) (397)
- -------------------------------------------------------------------------------------------------------
Net cash used in investing activities (72,571) (66,063) (31,121)
Cash flows from financing activities:
Proceeds from long-term debt 64,800 41,400 16,500
Repayments of long-term debt (24,293) (26,139) (3,381)
Issuance of common stock 256 659 710
Tax benefit on stock option exercises 240 1,231 2,395
Purchase of treasury stock (37) (1,909) --
Dividends paid (1,262) (691) (394)
Other, net (705) (413) (49)
- -------------------------------------------------------------------------------------------------------
Net cash provided by financing activities 38,999 14,138 15,781
- -------------------------------------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents (888) (6,273) 8,111
Cash and cash equivalents at beginning of year 5,075 11,348 3,237
- -------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of year $4,187 $5,075 $11,348
=======================================================================================================
The accompanying notes are an integral part of these financial statements.
26
28
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 a natural gas transportation business and an energy
marketing and services business.
Recapitalization (Quasi-reorganization)
At September 30, 1988, prior to the start of KCS Energy, Inc.'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.
Consolidation
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.
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 No. 107 and 119. At September 30, 1995, the Company's
hedging activities consisted of 989 long contracts at an average price of $1.81
per Mcf and 481 short contracts at an average price of $1.85 per Mcf maturing
through 1996 covering 14,700 MMcf of natural gas. At September 30, 1994, the
Company's hedging activities consisted of 608 long contracts at an average price
of $2.14 per Mcf and 235 short contracts at an average price of $2.13 per Mcf
maturing through 1995 and 1996 covering 8,430 Mcf 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 and $1.6 million at September 30, 1995 and
September 30, 1994, respectively.
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
September 30, 1995 or 1994.
Property, Plant and Equipment
Subsidiaries of the Company engaged in the exploration, development and
production of oil and gas follow the full cost method of accounting, under which
all productive and nonproductive costs associated with these 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
27
29
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, included in natural gas transportation
systems, 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
Effective October 1, 1993, the Company adopted 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
$240,000, $1,231,000 and $2,395,000 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 options outstanding under the Company's
stock option plans.
Supplemental Cash Flow Disclosures
The Company acquired certain producing properties during fiscal 1993.
The related non-cash investing and financing activities are summarized as
follows:
DOLLARS IN
THOUSANDS
---------
Investment in oil and gas properties $(10,179)
Subordinated note payable assumed . . . . . . . . . . . . . . . . . . . . 4,000
Issuance of common stock . . . . . . . . . . . . . . . . . . . . . . . . 6,179
2. RETIREMENT BENEFIT PLANS
The Company has a trusteed, non-contributory Retirement Plan ("Plan")
which covers substantially all full-time employees of KCS and its participating
subsidiaries. The Plan was amended to freeze the accrual of future benefits as
of October 31, 1991. 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. No contributions were required in 1995
and 1994. The required contribution was $49,924 in 1993.
Net periodic pension costs consisted of the following components:
1995 1994 1993
---- ---- ----
DOLLARS IN THOUSANDS
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 . . . . . . . . . . . . . . . $1 $(9) $55
== ==== ===
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The following table sets forth the funded status and amounts
recognized in the consolidated balance sheets at September 30, 1995 and 1994
for the Plan:
1995 1994
---- ----
DOLLARS IN THOUSANDS
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 (gain) . . . . . . . . . . . . . . . . 199 143
Unrecognized net asset at October 1 . . . . . . . . . . . . . (82) (100)
---- -----
Pension prepayment in the balance sheet . . . . . . . . . . . $305 $317
==== ====
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 September 30, 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 is in the process of filing 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 the Company's 1996
fiscal year.
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 for both matching and profit sharing
contributions were $301,796 in 1995, $295,145 in 1994 and $175,589 in 1993.
Effective October 1, 1993, the Company adopted FASB Statement No. 106,
"Employers' Accounting for Post-retirement Benefits Other Than Pensions." The
Company currently provides certain health care benefits for eligible retirees.
The adoption of this Statement did not have a material effect on the Company's
results of operations or financial position.
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 and its subsidiaries. The
1992 Stock Plan also provides that bonus stock may be granted to employees.
In 1994, the stockholders of the Company approved the 1994 Directors'
Stock Plan which provides that each non-employee director be granted stock
options for 1,000 shares annually. This plan also provides that each
non-employee director be issued KCS stock with a fair market value equal to 50%
of their annual retainer in lieu of cash.
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31
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 September 30, 1995, options for 330,025 shares were
exercisable.
Transactions during the last three fiscal years involving stock
options under the above plans are summarized as follows:
NUMBER OF OPTION PRICE
SHARES PER SHARE
------ ---------
Options outstanding, September 30, 1992 . . . . . . . . 719,000 $1.21 - $ 2.13
1993 -- Granted . . . . . . . . . . . . . . . . . . . . 73,200 $6.25
-- Exercised . . . . . . . . . . . . . . . . . . . (285,000) $1.33 - $ 1.98
1994 -- Granted . . . . . . . . . . . . . . . . . . . . 112,700 $22.88 - $26.88
-- Exercised . . . . . . . . . . . . . . . . . . . (150,200) $1.21 - $ 6.25
1995 -- Granted . . . . . . . . . . . . . . . . . . . . 105,000 $14.50 - $16.31
-- Exercised . . . . . . . . . . . . . . . . . . . (38,800) $1.33 - $ 6.25
-- Forfeited . . . . . . . . . . . . . . . . . . . (2,800) $22.88 - $26.88
------- ---------------
Options outstanding, September 30, 1995 . . . . . . . . 533,100 $1.50 - $26.88
======= ==============
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 September 30, 1995. Restricted stock
totaling 17,600 shares were outstanding under the Employee Incentive Plans at
September 30, 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 17,600 shares were outstanding at September 30, 1995.
At September 30, 1995, 170,302 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
6,442; 14,413 and 24,481 during 1995, 1994 and 1993, respectively. At September
30, 1995 there were 444,195 shares available for issuance under the Program.
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4. LONG-TERM DEBT
Long-term debt consists of the following:
SEPTEMBER 30,
-------------
1995 1994
---- ----
DOLLARS IN THOUSANDS
Master Note Facility . . . . . . . . . . . . . . . . . . . . . $58,500 $36,400
Receivable Facility . . . . . . . . . . . . . . . . . . . . . . 22,300 --
VPP Facility . . . . . . . . . . . . . . . . . . . . . . . . . 10,000 --
Revolving Credit Agreement . . . . . . . . . . . . . . . . . . -- 12,000
Subordinated Note Payable . . . . . . . . . . . . . . . . . . . -- 1,600
Installment note payable to bank due in equal monthly
installments, with interest at 10.5% and final payment due
January 1997 . . . . . . . . . . . . . . . . . . . . . . . . -- 293
-- ---
90,800 50,293
Less current maturities . . . . . . . . . . . . . . . . . . . . -- 1,722
-- -----
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . $90,800 $48,571
======= =======
MASTER NOTE FACILITY
The maximum credit limit under the Company's revolving Master Note
Facility ("Facility") was $100 million as of September 30, 1995. The maturity
date of the Facility is October 1, 1998. The Facility is used primarily for the
expansion of the Company's oil and gas 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
September 30, 1994 to $75 million effective March 1995. At September 30, 1995,
the Borrowers had utilized $69.6 million of the availability under the
Facility, $58.5 million as cash advances and $11.1 million for the issuance of
letters of credit in favor of the operator of certain wells at the Bob West
Field as a condition to the release of funds previously held. The borrowing
base is reviewed at least semi-annually and may be adjusted based on the
lenders' valuation of the Borrowers' oil and gas reserves, pipeline assets, and
other factors. Substantially all of the Borrower's oil and gas reserves
(excluding those acquired through volumetric production payments) and pipeline
assets have been pledged to secure this Facility.
The Facility permits the Borrowers to choose between various interest
rate options based on the bank's prime rate, its certificate of deposit 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 7.7% in 1995 and 5.43% in
1994. As of September 30, 1995, the weighted average effective interest rate on
the borrowings was 7.69%.
Subsequent to September 30, 1995, the Master Note Facility was amended
to increase both the maximum credit limit to $120 million and the borrowing
base to $102 million effective upon completion of the Rocky Mountain
Acquisition (See Note 11 to Consolidated Financial Statements).
REVOLVING CREDIT FACILITIES
Revolving Credit Agreement
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. During 1995, the borrowing limit of this facility was $20 million and
its revolving period was to expire January 1996. Under the terms of the
Agreement, the subsidiary could borrow the lesser of the borrowing limit or 80%
of eligible accounts receivable, as defined by the bank.
The Company had the option to request working capital advances on
which interest charged by the bank was based on its "Base Rate", or long-term,
not to exceed 36 months, fixed rate advances with interest accruing based upon
U.S. Treasury Securities. A commitment fee on one-quarter of one percent was
paid on the unused
31
33
portion of the borrowing limit. At September 30, 1994, $12.0 million was
reflected as outstanding under this Agreement. On January 12, 1995, the Company
paid in full all outstanding balances and terminated the Agreement. The
weighted average effective interest rate was 8.6% in 1995 and 7.25% in 1994.
In January 1995, the Company's natural gas marketing subsidiary
replaced the Revolving Credit Agreement with two new revolving credit
facilities. One of the facilities supports the expansion of the natural gas
marketing operations (the "Receivables Facility") while the other provides
financing for the Company's volumetric production payment program (the "VPP
Facility").
Receivables Facility
The Receivables Facility matures in December 1996 and is secured by
the natural gas marketing subsidiary's accounts receivable and other assets
(excluding those pledged under the VPP Facility) and a pledge of the natural
gas marketing subsidiary's stock. During 1995, the maximum credit limit under
the Receivables Facility was increased from the initial $25 million to $35
million, effective August 1995. Under the terms of 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 September 30, 1995 the borrowing base was
$22.3 million and the outstanding balance under the Receivables Facility was
$22.3 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 7.72% in 1995. On September 30, 1995, the
weighted average effective interest rate on outstanding borrowings was 7.38%.
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
maximum credit commitment under this facility was $25 million and the borrowing
base under the VPP Facility was $15 million as of September 30, 1995. The
borrowing base is reviewed at least semi-annually and may be subject to change
based upon the lender's evaluation of the oil and gas reserves and other
factors. The outstanding balance under the VPP Facility was $10 million on
September 30, 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 8.24% in 1995. As of September 30, 1995, the
weighted average effective interest rate on outstanding borrowings was 8.15%.
In November 1995, the VPP Facility was amended to increase both the
maximum credit commitment to $50 million and the borrowing base to $38 million
effective upon completion of the Michigan Acquisition (See Note 11 to
Consolidated Financial Statements).
Note Financing
On November 17, 1995, the Company entered into a $25 million Note
Financing Agreement ("Note Financing"). The Note Financing is secured by all of
the assets of the Company other than the capital stock of its marketing
subsidiary. A portion of the proceeds from the Note Financing were used to fund
a portion of the Michigan acquisition. In addition, the Note Financing will be
used for the Company's oil and gas exploration and production operations and
for general corporate purposes. The Company anticipates replacing the Note
Financing with more permanent financing early in 1996.
The unpaid principal balance of the Note Financing bears interest at
the rate of 12% per annum until May 17, 1996. The interest rate increases 0.5%
each six months thereafter. The Note Financing matures on November 17, 1996;
however, the Company has the right to extend the maturity date until May 16,
1997. The Note Financing can be repaid at any time without penalty or premium.
32
34
The Company also issued to the purchaser under the Note Financing
(with an option to buy back) a warrant to purchase 114,683 shares of the
Company's common stock exercisable at a price of $11.65 per share, subject to
adjustment to prevent dilution.
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's ability to incur additional indebtedness
and pay cash dividends is limited by these agreements. Aggregate cash dividends
are restricted to one-half of the Company's net income after September 30,
1993.
The Company had a short-term note payable, which was issued in
conjunction with a 1993 acquisition of producing properties and was
subordinated to the lien recorded under the Master Note Facility. The balance
of the subordinated note 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 September 30, 1996
to 2000, is as follows: $-0- in 1996, $22,300,000 in 1997, $10,000,000 in 1998,
$58,500,000 in 1999 and $-0- in 2000. Interest payments were $5,169,000 in
1995, $1,827,000 in 1994 and $1,573,000 in 1993.
5. LEASES
Future minimum lease payments under non-cancelable operating leases
are as follows: $561,000 in 1996, $547,000 in 1997, $538,000 in 1998, $421,000
in 1999 and $337,000 in 2000.
Lease payments charged to operating expenses amounted to $456,000,
$598,000 and $579,000 during 1995, 1994 and 1993, respectively.
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6. INCOME TAXES
Federal and state income tax expense includes the following
components:
FOR THE YEARS ENDED SEPTEMBER 30,
---------------------------------
1995 1994 1993
---- ---- ----
DOLLARS IN THOUSANDS
Currently payable . . . . . . . . . . . . . . . . . . . . . . $772 $1,774 $3,877
Deferred provision, net . . . . . . . . . . . . . . . . . . . 9,518 9,535 1,433
Amortization of investment tax credits . . . . . . . . . . . -- -- (96)
-- -- ----
Federal income tax expense . . . . . . . . . . . . . . . . . 10,290 11,309 5,214
State income taxes (deferred provision $1,329 in 1995, $22 in
1994 and $7 in 1993) . . . . . . . . . . . . . . . . . . . 1,265 401 132
----- --- ---
$11,555 $11,710 $5,346
------- ------- ------
Sources of deferred federal and state income taxes:
Intangible drilling costs . . . . . . . . . . . . . . . . . $14,527 $8,385 $2,578
Revenue recognition deferred . . . . . . . . . . . . . . . 1,734 1,909 --
Depreciation, depletion and amortization . . . . . . . . . (5,610) (640) 588
Tax credit carry forwards and other, net . . . . . . . . . 196 (97) (1,726)
--- ---- -------
$10,847 $9,557 $1,440
------- ------ ------
Reconciliation of federal income tax expense at statutory rate
to provision for income taxes:
Income before income taxes . . . . . . . . . . . . . . . . . $34,332 $34,991 $19,024
------- ------- -------
Tax provision at statutory rate (35% in 1995 and 1994 and
34.75% in 1993) . . . . . . . . . . . . . . . . . . . . . . 12,016 12,247 6,611
State income tax, net of federal income tax benefit . . . . . 822 261 87
Statutory depletion . . . . . . . . . . . . . . . . . . . . . (714) (690) (596)
Section 29 credits . . . . . . . . . . . . . . . . . . . . . (430) (374) (443)
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . (139) 266 (313)
----- --- -----
$11,555 $11,710 $5,346
======= ======= ======
The primary differences giving rise to the Company's deferred tax assets and
liabilities are as follows:
SEPTEMBER 30, 1995
------------------
ASSETS LIABILITIES
------ -----------
DOLLARS IN THOUSANDS
Income tax effects of:
Accelerated DD&A and other property related items . . . . . . . . $23,871
Alternative minimum tax credit carry forwards . . . . . . . . . . $3,649
Deferred revenue . . . . . . . . . . . . . . . . . . . . . . . . 3,643
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . 646
------ ---
$3,649 $28,160
====== =======
No income tax payments were made in 1995. Income tax payments were
$2,969,000 in 1994 and $67,500 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 carry forwards, which can be
carried forward indefinitely, of $3,649,000 are available to reduce the
Company's future federal income tax liabilities.
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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, which runs through January
1999, 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"), $8.07 per MMBtu during September 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 Tennessee Gas Contract.
In August 1990 in the District Court of Bexar County, Texas, 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 and its co-sellers have filed a request for a rehearing in the Texas
Supreme Court of the Section 2.306 issue, which 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 in late 1996.
In connection with the District Court judgment, in October 1994,
August 1995 and October 1995, Tennessee Gas posted with the Bexar County
District supersedeas bonds totaling $180 million and executed interim
agreements with the Company and its co-sellers to pay currently $3.00 per
MMBtu, including severance tax reimbursement, for natural gas delivered after
September 17, 1994, and 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
supersedeas bonds and the interim agreements are in effect until the earlier of
the issuance of a mandate from the Texas Supreme Court or January 31, 1996.
Prior to the interim agreement of October 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 September 30, 1995, the Company had recorded cumulative
revenue of approximately $141 million for natural gas sold under the Tennessee
Gas Contract based on the prices as defined in the contract, of which
approximately $101 million (approximately $56 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 September 30, 1995, such
receivable (which includes
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37
accrued interest income as provided for in the contract and is net of deferred
severance taxes and other payables) was $46.2 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 account 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 September 30, 1995, the amount of natural gas taken by
Tennessee Gas attributable to these royalty interests was approximately 2.9
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 $7.42 per Mcf, net of severance tax.
The average contract price was approximately $7.33 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 $16.6
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 lawsuits 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.
36
38
8. QUARTERLY FINANCIAL DATA (UNAUDITED)
Fiscal Quarters
---------------
First Second Third Fourth
----- ------ ----- ------
Dollars in thousands (except per share data)
1995
Revenue . . . . . . . . . . . . . . . $91,306 $96,039 $126,556 $109,679
------- ------- -------- --------
Operating Income . . . . . . . . . . $12,021 $10,184 $9,306 $6,438
------- ------- ------ ------
Net Income . . . . . . . . . . . . . $7,095 $6,219 $5,377 $4,086
------ ------ ------ ------
Earnings Per Common Share . . . . . . $0.60 $0.53 $0.46 $0.35
===== ===== ===== =====
1994
Revenue . . . . . . . . . . . . . . . $85,191 $85,173 $84,491 $80,743
------- ------- ------- -------
Operating Income . . . . . . . . . . $9,702 $9,380 $11,135 $6,076
------ ------ ------- ------
Net Income . . . . . . . . . . . . . $6,219 $6,170 $6,915 $3,977
------ ------ ------ ------
Earnings Per Common Share . . . . . . $0.53 $0.52 $0.58 $0.34
===== ===== ===== =====
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39
9. FINANCIAL INFORMATION BY BUSINESS SEGMENT
The following financial information has been provided for the business
segments of the Company:
FOR THE YEARS ENDED SEPTEMBER 30,
---------------------------------
1995 1994 1993
---- ---- ----
DOLLARS IN THOUSANDS
Revenue
Oil and Gas Exploration and Production . . . . $84,640 $57,295 $30,450
Energy Marketing and Services . . . . . . . . . 328,201 263,104 226,418
Natural Gas Transportation . . . . . . . . . . 24,454 19,078 16,030
Intercompany . . . . . . . . . . . . . . . . . (13,715) (3,879) (1,222)
-------- ------- -------
$423,580 $335,598 $271,676
======== ======== ========
Operating Income (Loss)
Oil and Gas Exploration and Production . . . . $39,804 $34,822 $19,622
Energy Marketing and Services . . . . . . . . . (833) 2,388 1,778
Natural Gas Transportation . . . . . . . . . . 1,308 1,349 899
----- ----- ---
40,279 38,559 22,299
Corporate Expenses . . . . . . . . . . . . . . (2,330) (2,266) (2,209)
Interest and Other Income, net . . . . . . . . 2,419 1,057 698
Interest Expense . . . . . . . . . . . . . . . (6,036) (2,359) (1,764)
------- ------- -------
Income Before Income Taxes . . . . . . . . . . $34,332 $34,991 $19,024
======= ======= =======
Identifiable Assets
Oil and Gas Exploration and Production . . . . $202,102 $120,372 $81,824
Energy Marketing and Services(1) . . . . . . . 38,832 35,899 48,609
Natural Gas Transportation . . . . . . . . . . 21,729 19,315 18,952
Corporate and Other . . . . . . . . . . . . . . 9,319 5,830 3,283
----- ----- -----
$271,982 $181,416 $152,668
======== ======== ========
Depreciation, Depletion and Amortization
Oil and Gas Exploration and Production . . . . $35,708 $13,903 $5,016
Energy Marketing and Services . . . . . . . . . 226 372 221
Natural Gas Transportation . . . . . . . . . . 861 852 755
Other . . . . . . . . . . . . . . . . . . . . . 63 27 20
-- -- --
$36,858 $15,154 $6,012
======= ======= ======
Capital Expenditures
Oil and Gas Exploration and Production . . . . $74,017 $64,668 $39,847
Energy Marketing and Services . . . . . . . . . 135 205 251
Natural Gas Transportation . . . . . . . . . . 3,852 1,039 1,184
Other . . . . . . . . . . . . . . . . . . . . . 91 151 18
-- --- --
$78,095 $66,063 $41,300
======= ======= =======
(1) Energy Marketing and Services assets consist primarily of trade
accounts receivable.
38
40
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 September
30, 1995 are not necessarily reflective of the prices the Company expects to
receive in the future. Other than gas sold under contractual arrangements, gas
prices were $1.65 and $1.53 per Mcf at September 30, 1995 and 1994,
respectively. Oil prices were $17.00 per bbl for each period.
Volumetric production payments 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:
FOR THE YEARS ENDED SEPTEMBER 30,
---------------------------------
1995 1994 1993
---- ---- ----
DOLLARS IN THOUSANDS
Revenue . . . . . . . . . . . . . . . . . . . . . . . . $84,640 $57,350 $30,390
Production (lifting) costs . . . . . . . . . . . . . . 6,463 6,518 4,248
Technical support and other . . . . . . . . . . . . . . 2,494 2,056 1,568
Depreciation, depletion and amortization . . . . . . . 35,499 13,985 4,967
------ ------ -----
Total expenses . . . . . . . . . . . . . . . 44,456 22,559 10,783
------ ------ ------
Pretax income from producing activities . . . . . . . . 40,184 34,791 19,607
Income taxes . . . . . . . . . . . . . . . . . . . . . 12,899 11,269 5,627
------ ------ -----
Results of oil and gas producing activities (excluding
corporate overhead and interest) . . . . . . . . . . $27,285 $23,522 $13,980
======= ======= =======
Capitalized costs incurred:
Property acquisition . . . . . . . . . . . . . . . . $26,343 $17,752 $19,092
Exploration . . . . . . . . . . . . . . . . . . . . . 15,353 10,710 4,911
Development . . . . . . . . . . . . . . . . . . . . . 31,647 36,017 15,776
------ ------ ------
Total capitalized costs incurred . . . . . . $73,343 $64,479 $39,779
======= ======= =======
Capitalized costs at year-end:
Proved properties . . . . . . . . . . . . . . . . . . $218,003 $149,355 $87,447
Unproved properties . . . . . . . . . . . . . . . . . 5,578 4,952 2,381
----- ----- -----
223,581 154,307 89,828
Less accumulated depreciation, depletion and
amortization . . . . . . . . . . . . . . . . . . . . (77,451) (41,837) (27,852)
-------- -------- --------
Net investment in oil and gas producing properties . . $146,130 $112,470 $61,976
======== ======== =======
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 substantial 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 (see Note
7).
39
41
DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
September 30,
-------------
1995 1994
---- ----
Dollars in thousands
Future cash inflows . . . . . . . . . . . . . . . . . . $295,150 $376,163
Future costs:
Production . . . . . . . . . . . . . . . . . . . . . (42,477) (46,444)
Development . . . . . . . . . . . . . . . . . . . . . (11,079) (17,577)
Discount -- 10% annually . . . . . . . . . . . . . . (52,122) (68,097)
-------- --------
Present value of future net revenues . . . . . . . . 189,472 244,045
Future income taxes, discounted at 10% . . . . . . . (38,999) (62,082)
-------- --------
Standardized measure of discounted future net cash flows $150,473 $181,963
======== ========
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42
CHANGES IN DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVE QUANTITIES
For the Years Ended September 30,
---------------------------------
1995 1994 1993
---- ---- ----
Dollars in thousands
Balance, beginning of year . . . . . . . . . . $181,963 $185,534 $81,247
-------- -------- -------
Increases (decreases)
Sales, net of production costs . . . . . . . (78,177) (50,738) (26,361)
Net change in prices, net of production costs (16,747) (23,721) 3,922
Discoveries and extensions, net of future
production and development costs . . . . . 13,525 34,917 124,597
Changes in estimated future development costs (391) (9,337) (288)
Change due to acquisition of reserves in place 26,055 16,283 29,620
Development costs incurred during the period 7,921 7,220 2,925
Revisions of quantity estimates . . . . . . . (15,114) (18,704) (9,504)
Accretion of discount . . . . . . . . . . . . 23,651 24,799 11,164
Net change in income taxes . . . . . . . . . 23,083 2,744 (34,353)
Sales of reserves in place . . . . . . . . . (1,931) -- --
Changes in production rates (timing) and other (13,365) 12,966 2,565
-------- ------ -----
Net increase (decrease) . . . . . . . . . . . (31,490) (3,571) 104,287
-------- ------- -------
Balance, end of year . . . . . . . . . . . . . $150,473 $181,963 $185,534
======== ======== ========
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.).
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.
1995 1994 1993
---- ---- ----
GAS OIL GAS OIL GAS OIL
MMcf Mbbl MMcf Mbbl MMcf Mbbl
---- ---- ---- ---- ---- ----
Proved developed and undeveloped
reserves
Balance, beginning of year . . . . 86,362 2,576 79,257 1,653 41,192 1,526
Production . . . . . . . . (17,233) (167) (9,236) (200) (5,589) (171)
Discoveries, extensions, etc 8,307 49 11,498 1,034 25,066 2
Acquisition of reserves in place 17,692 -- 12,230 149 14,230 1,687
Sales of reserves in place (3,751) (3) -- -- -- --
Revisions of estimates . . (4,353) (435) (7,387) (60) 4,358 (1,391)
------- ----- ------- ---- ----- -------
Balance, end of year . . . 87,024 2,020 86,362 2,576 79,257 1,653
========================================================================
Proved developed reserves
Balance, beginning of year 71,141 1,573 65,853 1,625 35,434 1,209
------ ----- ------ ----- ------ -----
Balance, end of year . . 76,766 996 71,141 1,573 65,853 1,625
========================================================================
41
43
Proved gas reserves at September 30, 1995 include 33,272 MMcf
(including 29,958 MMcf 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.
SUBSEQUENT ACQUISITIONS
Subsequent to September 30, 1995 the Company completed two significant
reserve acquisitions, purchasing a number of producing wells, along with
equipment and developable leases in the Rocky Mountain region, and purchasing a
significant volumetric production payment and working interest in wells in
Michigan. 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 (H.J. Gruy and Associates, Inc. and Netherland,
Sewell & Associates, Inc.)
These acquisitions, if recorded at September 30, 1995, would have
increased the Company's reserves as follows:
ACQUIRED PROPERTIES COMPANY PRO FORMA
------------------- -----------------
GAS OIL GAS OIL
MMcf Mbbl MMcf Mbbl
---- ---- ---- ----
Proved Reserves at September 30, 1995 . . 57,694 5,604 144,718 7,624
===================================================
Proved Developed Reserves at September 30, 1995 46,584 2,858 123,350 3,854
===================================================
Discounted future cash flows related to these acquired properties are
as follows (in thousands):
ACQUIRED COMPANY
PROPERTIES PRO FORMA
---------- ---------
Future Cash Inflows . . . . . . . . . . . . . . . . . . . . . $204,166 $499,315
Future costs:
Production . . . . . . . . . . . . . . . . . . . . . . . . (48,710) (91,186)
Development . . . . . . . . . . . . . . . . . . . . . . . . (11,134) (22,213)
Discount -- 10% annually . . . . . . . . . . . . . . . . . (54,790) (106,912)
-------- ---------
Present value of future net revenues . . . . . . . . . . . 89,532 279,004
Future income taxes, discounted at 10% . . . . . . . . . . (20,917) (59,916)
-------- --------
Standardized measure of discounted future net cash flows . . $68,615 $219,088
======= ========
11. SUBSEQUENT EVENTS
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 a purchase price of $33 million, subject to adjustments for
a July 1, 1995 effective date. The purchase was financed principally through
the Master Note Facility. The Company acquired interests in 531 gross (301 net)
wells located in over 30 different fields, principally in six producing basins
located in Wyoming, Colorado and Montana. Proved reserves attributable to the
properties are estimated by independent petroleum engineers at October 1, 1995
to be 66.7 Bcfe, consisting of 40.9 Bcf of natural gas and 4.3 MMbbls of oil.
In addition, the Rocky Mountain Acquisition includes approximately 197,000
gross (160,000 net) acres of largely underdeveloped properties. 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 the exploration program discussed below (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 reserves
consist of 13.7 Bcf of natural gas and 1.1 MMbbls of oil, with approximately
16% of these volumes to be delivered in 1996. Based on independent reserve
reports, the separately acquired working
42
44
interests add 3.1 Bcf of natural gas and 219 Mbbls of oil to the Company's
proved reserves. The Michigan Acquisition was financed through the VPP Facility
and the Note Financing.
The reserves acquired by the Company in the Michigan Acquisition will
be produced principally from 89 wells operated by a subsidiary of Hawkins Oil
and Gas, Inc. ("Hawkins") on properties located in the Niagaran Reef trend in
northern and southern Michigan, all of which were recently acquired by Hawkins
as a result of a merger with Savoy Oil & Gas, Inc. ("Savoy"), a Michigan-based
oil and gas exploration company. The operator will bear all development and
lease operating expenses attributable to these reserves. The Company will bear a
proportionate share of applicable severance taxes on its produced volumes. For a
description of these properties, see "-- Volumetric Production Payment Program
and Underlying Properties."
The Company also entered into a separate agreement that provides for
the right to participate in a three-year exploration program with the seller,
who is also the operator. The majority of the prospects in this exploration
program are anticipated to be generated pursuant to a farmout agreement which
covers approximately 150,000 gross (56,250 net) acres in the Niagaran Reef trend
in northern and southern Michigan, and will involve rights to approximately
17,000 miles of proprietary seismic data in the area. Following the
identification of drilling prospects, and subject to the elections of third
parties under the farmout and other agreements, the Company will have the right
to participate on an equal basis with the operator. The Company has agreed,
under certain conditions, to fund both its and the operators' participation
costs, including lease acquisition, well development and engineering costs, in
consideration of which the Company will recover, as an annual priority payment
out of net production proceeds, 133% of the total costs annually advanced by the
Company.
The Company has also entered into an agreement whereby it is entitled
to receive assignments of overriding royalty interests in certain properties to
be developed by Hawkins pursuant to the exploration agreement. The interests to
be assigned to the Company will be determined based upon lease burdens and the
participating interests of other parties.
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 year ended September 30, 1995 as if such transaction had occurred on
October 1, 1994. 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 transaction had occurred as presented or that
may be obtained in the future.
Year Ended
September 30,
1995
----
Dollars in thousands
(except per share data)
Revenue . . . . . . . . . . . . . . . . . . . . . . . . . . $439,345
Net Income . . . . . . . . . . . . . . . . . . . . . . . . 22,886
Earnings per common share . . . . . . . . . . . . . . . . . $1.95
On December 11, 1995, 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. The change will become effective on
January 1, 1996. A three-month fiscal transition period from October 1, 1995
through December 31, 1995 will precede the start of a new fiscal year.
Item 9. Changes in and Disagreements With Accountants On
Accounting And Financial Disclosure.
None.
43
45
PART III
Item 10 - Directors and Executive Officers of the Registrant
The following table sets forth the name, age and present position with
the Company of each of the Company's executive officers, directors and certain
other key employees.
NAME AGE POSITION WITH THE COMPANY
---- --- -------------------------
James W. Christmas . . 47 President and Chief Executive Officer and
Director
C.R. Devine . . . . . . 49 Vice President, Oil and Gas Operations;
President, KCS Resources, Inc.
Harry Lee Stout . . . . 47 President, KCS Energy Marketing, Inc.;
President, KCS Pipeline Systems, Inc.;
President, KCS Michigan Resources, Inc.
Henry A. Jurand . . . . 46 Vice President, Treasurer and Secretary
G. Stanton Geary . . . 61 Director
Stewart B. Kean . . . . 61 Director and Chairman of the Board
James E. Murphy, Jr . . 39 Director
Robert G. Raynolds . . 43 Director
Joel D. Siegel . . . . 54 Director
Christopher A. Viggiano 42 Director
James W. Christmas has served as President and Chief Executive Officer
and as a director of the Company since 1988. Prior to joining the Company, Mr.
Christmas spent ten years with NUI Corporation, serving in a variety of officer
capacities and as President of several of its subsidiaries. While Mr. Christmas
was Vice President of Planning of NUI Corporation, he was in charge of the
spin-off of its non-regulated businesses that resulted in the formation of KCS
Energy, Inc. Mr. Christmas began his career with Arthur Andersen & Co.
C. R. Devine was named Vice President, Oil and Gas Operations of the
Company in December 1992 and President of KCS Resources, Inc., the subsidiary
of the Company engaged in oil and gas exploration and production, in December
1993. He has served as principal operating officer of the Company's oil and gas
operations since 1988. He has been employed by the Company and its predecessor
companies since 1974.
Harry Lee Stout has served as President of KCS Energy Marketing, Inc.,
and KCS Pipeline Systems, Inc., the subsidiaries of the Company engaged in
natural gas marketing and transportation, since joining the Company in August
1991. In October 1995, he was named President of KCS Michigan Resources, Inc.
From 1990 to 1991, he was Vice President of Minerex Corporation in Houston,
Texas. From 1978 to 1990, he was employed by Enron Corp. of Houston, Texas,
holding various management positions including Senior Vice President of
Houston Pipe Line Company and Executive Vice President, Enron Gas Marketing
Company, both of which are subsidiaries of Enron Corp.
Henry A. Jurand has served as Vice President of the Company since
September 1990, as Treasurer since March 1991, and as Secretary since February
1992. From 1988 to 1990, he was a Senior Vice President of Private Capital
Partners, Inc., in New York City. From 1977 to 1988, he was employed by
Baltimore Gas and Electric Company, holding management positions including Vice
President and Chief Financial Officer of Constellation Holdings, Inc., a
subsidiary.
G. Stanton Geary has served as a director of the Company since 1988.
He is proprietor of Gemini Associates, Pomfret, Connecticut, a venture capital
consulting firm, and business manager of the Rectory School, Pomfret,
Connecticut.
Stewart B. Kean has served as Chairman of the Board of Directors of
the Company since 1988. He was President of Utility Propane Company, a former
subsidiary of the Company, from 1965 to 1989. He is past President of the
National LP Gas Association and past President of the World LP Gas Forum. He
currently serves as a member of the Council of the World LP Gas Forum. Mr. Kean
is Robert G. Raynolds' uncle.
James E. Murphy, Jr. has served as a director of the Company since
1988. Mr. Murphy heads his own political and governmental relations consulting
firm offering strategic planning and management consulting services to
Republican candidates nationwide, with extensive experience at the
presidential, state and congressional levels. Based in Gaithersburg, Maryland,
he also advises corporations and industry groups on strategic planning,
governmental relations and grassroots lobbying projects.
Robert G. Raynolds has served as a director of the Company since
August 1995. He has been an independent consulting geologist for several major
and independent oil and gas companies from 1992 until the present and was a
geologist with Amoco Production Company from 1983 until 1992. Mr. Raynolds is
Stewart B. Kean's nephew.
Joel D. Siegel has served as a director of the Company since 1988. He
is an attorney-at-law and has been President of the law firm, Orloff,
Lowenbach, Stifelman & Siegel, P.A. of Roseland, New Jersey, since 1975.
Orloff, Lowenbach, Stifelman & Siegel, P.A. serves as outside legal counsel to
the Company. Mr. Siegel served as President and Chief Executive Officer of
Constellation Bancorp, Elizabeth, New Jersey, and Constellation Bank,
Elizabeth, New Jersey, for the period April 26, 1991 to December 6, 1991.
Christopher A. Viggiano has served as a director of the Company since
1988. Mr. Viggiano has been President, Chairman of the Board and majority owner
of O'Bryan Glass Corp., Queens, New York, since December 1, 1991, and served as
Vice President and a member of the Board of Directors of O'Bryan Glass Corp.
from 1985 to December 1, 1991. He is a Certified Public Accountant.
44
46
Item 11 - Executive Compensation
Summary Compensation Table
(a) (b) (c) (d) (e) (f) (g) (h) (i)
Long Term Compensation
-----------------------------------
Awards
------------------
Restricted Options/ Performance
Fiscal Performance Other Annual Stock & Cash SARs Unit Plan All Other
Name and Position Year Salary($) Award($) Compensation($) Awards($) Awards(#) Awards($) Compensation($)
- ----------------- ---- --------- -------- --------------- --------- --------- --------- --------------
James W. Christmas 1995 294,750 50,000 40,000 87,500 13,296
President and CEO 1994 262,175 67,300 - - 40,000 87,500 15,844
1993 187,125 147,300 - - 30,000 87,500 11,343
C.R. Devine 1995 181,000 20,000 50,950 20,000 43,750 13,789
Vice President, Oil and Gas 1994 163,000 32,600 - 76,150 20,000 43,750 12,539
Operations, and President, 1993 124,500 63,500 - - 9,600 43,750 7,689
KCS Resources, Inc.
Harry Lee Stout 1995 155,025 10,000 15,000 8,000 11,931
President, KCS Energy 1994 145,250 9,125 - - 15,000 4,950 12,383
Marketing, Inc., 1993 129,500 39,200 - - 9,600 - 3,996
KCS Pipeline Systems, Inc. and
KCS Michigan Resources, Inc.
Henry A. Jurand 1995 148,175 50,000 10,000 43,750 12,848
Vice President, 1994 142,050 23,950 - - 10,000 43,750 12,592
Treasurer & Secretary 1993 136,975 69,150 - - 9,600 43,750 8,521
- ----------------------------
NOTES:
(1) The amounts set forth in column (c) for Mr. Christmas include directors fees
of $2,400 and $4,800 paid in 1994 and 1993, respectively.
(2) The amounts set forth in column (d) represent performance awards which are
paid subsequent to September 30 each year for performance during the
previous fiscal year. Awards were paid to all recipients based on
attainment of specific goals including profitablity and growth of the
Corporation and its various operating segments.
(3) The amount set forth in column (f) for Mr. Devine reflects a restricted cash
award of $30,000 and 8,400 shares of restricted stock, both vesting
one-third each year on December 2, 1993, 1994 and 1995. Aggregate remaining
restricted stock holdings for Mr. Devine total 2,800 shares valued at
$40,250 at September 30, 1995. Dividends will be paid or withheld by the
Corporation for the grantee's account and interest paid on the amount of
dividends withheld.
(4) The amounts set forth in column (g) represent the number of stock options
granted under either the KCS Energy, Inc. 1988 Stock Plan or the KCS Energy,
Inc. 1992 Stock Plan. See the notes to the table entitled "Option/SAR
Grants in Last Fiscal Year."
(5) The Performance Unit Plan award amounts set forth in column (h) are awarded
pursuant to the KCS Performance Unit Plan subsequent to September 30, 1995
for performance during the previous three fiscal years. See the notes to
the table entitled "Long-Term Incentive Plan - Awards in Last Fiscal year."
(6) Amounts shown in column (i) represent amounts contributed by the Corporation
as 50% matching contributions for up to the first 6% of base salary
contributed by the named individual to the KCS Savings and Investment Plan
and the pro rata share of the Corporation's discretionary profit sharing
contribution made on behalf of the named individual to the KCS Savings and
Investment Plan.
45
47
Option/SAR Grants in Last Fiscal Year
(a) (b) (c) (d) (e) (f) (g)
Potential Realizable Value
@ Assumed Annual Rates
Of Stock Price Appreciation
Options/ % of Total for Option Term
SARs Granted Exercise Expiration -----------------------------
Name and Position Granted in FY 95 Price Date 5% 10%
- ----------------- ------- -------- ------ ----- --- ----
James W. Christmas 40,000 38% $14.50 11/30/04 $364,759 $924,371
President and CEO
C.R. Devine 20,000 19% $14.50 11/30/04 $182,379 $462,185
Vice President, Oil and Gas Operations,
and President, KCS Resources, Inc.
Harry Lee Stout 15,000 14% $14.50 11/30/04 $136,785 $346,639
President, KCS Energy Marketing, Inc.,
KCS Pipeline Systems, Inc. and
KCS Michigan Resources, Inc.
Henry A. Jurand 10,000 10% $14.50 11/30/04 $91,190 $231,093
Vice President, Treasurer
and Secretary
- -----------------------
NOTES:
(1) All options were granted under the KCS Energy, Inc. 1992 Stock Plan.
(2) The exercise price for all options granted during fiscal 1995 is equal to
the fair market value of the Common Stock on the date of the grant, November
30, 1994. The options granted become exercisable in one-fourth increments
at the end of each year following the date of the grant. Exercise rights
and expiration dates may be affected by the death, retirement, termination
of employment or disability of an optionee.
21-Dec-95 Aggregate Option/SAR Exercises in Last Fiscal Year
and FY-end Option/SAR Values Table
(a) (b) (c) (d) (e) (f) (g)
Value of Unexercised
Number of Unexercised In-the-money Options/
Options/SARs @ FY 95-end (#) SARs @ FY 95-end ($)(3)
Shares Acquired Value ----------------------------- ----------------------------
Name and Position on Exercise Realized (1) Exercisable (2) Unexercisable Exercisable Unexercisable
- ----------------- ----------- ------------ --------------- ------------- ----------- -------------
James W. Christmas 0 $0 210,000 80,000 $2,447,200 $88,750
President and CEO
C.R. Devine 9,200 $124,252 5,000 38,200 $0 $29,300
Vice President, Oil and Gas Operations,
and President, KCS Resources, Inc.
Harry Lee Stout 10,000 $173,750 23,150 29,450 $224,225 $28,675
President, KCS Energy Marketing, Inc.,
KCS Pipeline Systems, Inc. and
KCS Michigan Resources, Inc.
Henry A. Jurand 12,000 $159,315 46,900 20,700 $538,610 $28,050
Vice President, Treasurer
and Secretary
- -----------------------------
NOTES:
(1) Market Value of underlying securities at exercise minus the exercise price.
(2) Options granted to these executives under the KCS Energy, Inc. 1988 Stock
Plan and the KCS Energy, Inc. 1992 Stock Plan become exercisable in equal
installments over a period of either three or four years from the date of
grant.
(3) Market value of underlying securities at September 30, 1995 ($14.375 per
share), minus the exercise price.
46
48
Long-Term Incentive Plan - Awards in Last Fiscal Year
(a) (b) (c) (d) (e) (f)
Estimated Future Payouts
Number of Performance ---------------------------------
Name and Position Performance Units Period Threshold Target Maximum
- ----------------- ----------------- --------- ---------- -------- ---------
James W. Christmas 1,000 FY 95-97 $25,000 $100,000 $175,000
President and CEO
C.R. Devine 500 FY 95-97 12,500 50,000 87,500
Vice President, Oil and Gas Operations,
and President, KCS Resources, Inc.
Harry Lee Stout 500 FY 95-97 12,500 50,000 87,500
President, KCS Energy Marketing, Inc.,
KCS Pipeline Systems, Inc. and
KCS Michigan Resources, Inc.
Henry A. Jurand 500 FY 95-97 12,500 50,000 87,500
Vice President, Treasurer
and Secretary
- --------------------
NOTES:
(1) The KCS Performance Unit Plan is designed to promote the profitable growth
of the Corporation through awards of performance units which become cash
awards at the end of a period of years, currently three years. The
Compensation Committee of the Board of Directors establishes separate
performance criteria for each executive. Performance criteria consider
attainment of certain financial goals and are based on reasonable accounting
measures, including but not limited to, growth in earnings per share for
corporate executives and growth in subsidiary operating income for
subsidiary executives. The value of each performance unit could range from
$25 to $175 depending on the attainment of performance criteria.
(2) The awards described above provide for the payments indicated in column (e)
if targeted three-year cumulative targets are achieved. The potential
payments indicated in column (d) are the awards payable if the minimum
approved three-year targets are achieved. The potential payments indicated
in column (f) are the maximum awards payable if three-year cumulative
results significantly exceed the target amount.
COMPENSATION OF DIRECTORS
Directors who are not executive officers of KCS were paid an annual
retainer of $20,000 (paid one-half in cash and one-half in Common Stock) in
fiscal 1995. Directors who are not executive officers were paid $1,500 for each
meeting of the Board of Directors attending during fiscal 1995. Directors who
are not officers who are members of committees were paid $1,000 for each
committee meeting attended ($500 for meetings held on a day other than a day of
a Board of Directors' meeting) prior to February 15, 1994. ICS also reimburses
directors for expenses they incur in attending board and committee meetings.
There was no compensation not covered above, paid or distributed in the
fiscal year ended September 30, 1994 to any of the directors who are not
executive officers of KCS, except for a non-preferential discount of $4,838 on
the purchase of 3,000 shares of KCS Common Stock through KCS Employee Stock
Purchase Program by Mr. Kean and for a non-preferential discount of $2,776 on
the purchase of 1,633 shares of KCS Common Stock through the KCS Employee Stock
Purchase Program by Mr. Geary.
47
49
Item 12 - Security Ownership of Certain Beneficial Owners and Management
As of December 15, 1995, there were 11,487,137 shares of the Company's
Common Stock outstanding. These shares were held by 1,408 holders of record.
The following table sets forth information as to the number and percentage of
shares owned beneficially as of December 15, 1995 by each person known by the
Company to be a beneficial owner of more than 5% of the Company's Common Stock,
by each executive officer and director of the Company, and by all executive
officers and directors as a group. For the purpose of the following table, a
beneficial owner of a security includes any person who, directly or indirectly,
has or shares voting power and/or investment power with respect to such
security.
SHARES OWNED PERCENT
BENEFICIALLY(1) OF CLASS(2)
--------------- -----------
James W. Christmas . . . . . . . . . . . . . . . . . . . . . . 567,072(3)(4) 4.8%
C. R. Devine . . . . . . . . . . . . . . . . . . . . . . . . . 97,205(3) *
Henry A. Jurand . . . . . . . . . . . . . . . . . . . . . . . . 37,310(3) *
Harry Lee Stout . . . . . . . . . . . . . . . . . . . . . . . . 63,983(3) *
G. Stanton Geary . . . . . . . . . . . . . . . . . . . . . . . 5,625(3) *
Stewart B. Kean . . . . . . . . . . . . . . . . . . . . . . . . 1,748,703(3)(5) 14.8%
James E. Murphy, Jr . . . . . . . . . . . . . . . . . . . . . . 14,740(3) *
Robert G. Raynolds . . . . . . . . . . . . . . . . . . . . . . 527 *
Joel D. Siegel . . . . . . . . . . . . . . . . . . . . . . . . 89,992(3)(6) *
Christopher A. Viggiano . . . . . . . . . . . . . . . . . . . . 36,492(3) *
Stewart B. Kean, John Kean and M.A. Raynolds as co-trustees of
certain family trusts . . . . . . . . . . . . . . . . . . . . 962,460(7) 8.1%
Officers and directors as a group (12 persons) . . . . . . . . 2,661,649 22.5%
__________
* Less than 1%
(1) Unless otherwise indicated, beneficial owner has sole voting and
investment power.
(2) Class includes 357,150 shares issuable upon the exercise of options
granted that were vested as of December 15, 1995.
(3) Includes shares that (i) may be purchased as a result of options
granted that are exercisable within 60 days as of December 15, 1995 of
240,000;18,200;53,100 and 33,850 for Messrs. Christmas, Devine, Stout
and Jurand, respectively and 2,000 each for Messrs. Geary, S. B. Kean,
Murphy, Siegel and Viggiano or (ii) are allocated to the beneficial
owner's account under 401(k) plans.
(4) Includes 9,000 shares held in trusts established for the benefit of
his children, the beneficial ownership of which is disclaimed.
(5) Includes the following shares as to which the beneficial owner
indicated shares voting and investment power: 962,460 shares held by
Stewart B. Kean, a director of the Company, John Kean and May Raynolds
as the three co-trustees under certain family trusts; 58,392 shares
held by Stewart B. Kean, a director of the Company, and John Kean as
the two co-trustees under certain family trusts; 40,620 shares held by
Stewart B. Kean, a director of the Company, and John Kean, Jr. as the
two co-trustees under certain family trusts.
(6) Includes 8,000 shares held in trusts established for the benefit of
his children, the beneficial ownership of which is disclaimed.
(7) Beneficial owners indicated share voting and investment power with
respect to these shares.
In December 1994, the Board of Directors adopted a policy requiring
minimum levels of ownership of the Company's Common Stock by its directors and
by executive officers of the Company and its subsidiaries. Within a four-
48
50
year period, directors are required to become beneficial owners of common stock
with a market value equivalent to four times their annual retainer. During such
period, the president and chief executive officer must become the owner of
common stock with a market value of four times his annual base salary. For vice
presidents of the Company and presidents of subsidiaries, the multiple of
annual base salary is two and one-half times and for vice presidents of
subsidiaries it is one-half.
Item 13 Certain Relationships and Related Transactions.
During fiscal 1995, the Company retained the firm of Orloff,
Lowenbach, Stifelman & Siegel, P.A. for legal counsel of which Joel D. Siegel,
a director of the Company, is a member. It is the opinion of management that
the professional fees charged are comparable to the fees of other law firms of
similar size and expertise.
49
51
PART IV
Item 14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) Financial statements, financial statement schedules, and
exhibits.
(1) The following consolidated financial statements of KCS and its
subsidiaries are presented in Item 8 of this Form 10-K.
Page
----
Report of Independent Public Accountants . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Statements of Consolidated Income for the years ended September 30, 1995, 1994 and 1993 . . . . . 23
Consolidated Balance Sheets at September 30, 1995 and 1994 . . . . . . . . . . . . . . . . . . . . 24
Statements of Consolidated Stockholders' Equity for the years ended September 30, 1995, 1994
and 1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
Statements of Consolidated Cash Flows for the years ended September 30, 1995, 1994 and 1993 . . . 26
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27-43
(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.
Schedule Number
II Valuation and Qualifying Accounts for the three-year period ended September 30, 1995 . . . . . 52
(3) Exhibits
See "Exhibit Index" located on pages 53 through 55 for a
listing of exhibits filed herein or incorporated by reference to a previously
filed registration statement or report with the Securities and Exchange
Commission.
(b) Reports on Form 8-K.
There were no reports on Form 8-K filed for the three months ended
September 30, 1995.
50
52
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: 12/27/95 By:/s/ Henry A. Jurand
-------- ----------------------
Henry A. Jurand
Vice President,Treasurer
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.
12/27/95 /s/ James W. Christmas
-------- ---------------------------------
Date James W. Christmas, President
& Chief Executive Officer & Director
12/27/95 /s/ Stewart B. Kean
-------- ---------------------------------
Date Stewart B. Kean, Chairman and Director
12/28/95 /s/ Robert G. Raynolds
-------- ---------------------------------
Date Robert G. Raynolds, Director
12/27/95 /s/ G. Stanton Geary
-------- ---------------------------------
Date G. Stanton Geary, Director
12/27/95 /s/ James E. Murphy
-------- ---------------------------------
Date James E. Murphy, Director
12/27/95 /s/ Joel D. Siegel
-------- ---------------------------------
Date Joel D. Siegel, Director
12/27/95 /s/ Christopher A. Viggiano
-------- ---------------------------------
Date Christopher A. Viggiano, Director
/s/ Henry A. Jurand 12/27/95
- --------------------------------- --------
Henry A. Jurand, Vice President Date
Treasurer and Secretary
Principal Financial Officer
51
53
Schedule II
KCS ENERGY, INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
FOR THE THREE YEARS ENDED SEPTEMBER 30, 1993 TO 1995
Balance at Charged to Costs Balance at End
Beginning of and of
Description Period Expenses Deductions Period
----------- ------ -------- ---------- ------
Thousands of Dollars
--------------------
Valuation accounts deducted in
balance sheet from accounts to which
they apply:
1995
----
Investments and other assets $55 - - $55
===================================================================
Accounts receivable $249 $351 $253 $347
===================================================================
1994
----
Investments and other assets $55 - - $55
===================================================================
Accounts receivable $99 $206 $56 $249
===================================================================
1993
----
Investments and other assets $55 - - $55
===================================================================
Accounts receivable $103 $46 $50 $99
===================================================================
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EXHIBIT INDEX
-------------
Exhibit
No. Description
------ -----------
(3) i Certificate of Incorporation of KCS filed as Exhibit 4.3 to
Form S-8 Registration Statement No. 33-63982 filed with SEC
June 8, 1993.
ii By-Laws of KCS filed as Exhibit 4.4 to Form S-8 Registration
Statement No. 33-63982 filed with SEC June 8, 1993.
(4) i Form of Common Stock Certificate, $0.01 Par Value, filed as
Exhibit 4 of Registrant's Form 10-K Report for Fiscal 1988.
ii Form of Common Stock Certificate, $0.01 Par Value, filed as
Exhibit 5 of Registrant's Form 8-A Registration Statement No.
1-11698 filed with the SEC, January 27, 1993.
(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.
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.
53
55
Exhibit
No. Description
------ -----------
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, 1
994 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 Guarantor 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 (xix) of Registrant's Form 10-K Report for fiscal
1994.
54
56
Exhibit
No. Description
------ -----------
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.
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 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 10.1 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 herewith.
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
herewith.
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 herewith.
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 thru 2.6 to Form
8-K on December 22, 1995.
(11) Statement re computation of per share earnings - filed
herewith.
(21) Subsidiaries of the Registrant - filed herewith .
(23) Consent of Arthur Andersen, LLP. - filed herewith.
55