-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, DgrhCSzFz5YQKcUBbLH4XfT4DaloUc05hQNOGPR/BpTfCAxD0mnIEcviT/MzUjkW 3uZKAnekf/6eC37FDZRxjA== 0000950123-95-003911.txt : 19960102 0000950123-95-003911.hdr.sgml : 19960102 ACCESSION NUMBER: 0000950123-95-003911 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 8 CONFORMED PERIOD OF REPORT: 19950930 FILED AS OF DATE: 19951229 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: KCS ENERGY INC CENTRAL INDEX KEY: 0000832820 STANDARD INDUSTRIAL CLASSIFICATION: WHOLESALE-PETROLEUM & PETROLEUM PRODUCTS (NO BULK STATIONS) [5172] IRS NUMBER: 222889587 STATE OF INCORPORATION: DE FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 000-16932 FILM NUMBER: 95606353 BUSINESS ADDRESS: STREET 1: 379 THORNALL ST CITY: EDISON STATE: NJ ZIP: 08837 BUSINESS PHONE: 9086321770 FORMER COMPANY: FORMER CONFORMED NAME: KCS GROUP INC DATE OF NAME CHANGE: 19920310 10-K 1 FORM 10-K 1 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 2 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. 3 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 2 4 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 3 5 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 4 6 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. 5 7 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. 6 8 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% === ===== ======= ======= ====
7 9 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 8 10 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. 12 14
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. 13 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. 14 16 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. 15 17 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 == ==== ===
28 30 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. 29 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. 30 32 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. 33 35 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. 34 36 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 35 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 ===== ===== ===== =====
37 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 ======== ========
40 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 ===================================================================
52 54 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 EX-10.XXVIII 2 2ND AMENDMENT DATED 12/22/94 TO CREDIT AGREEMENT 1 Exhibit (10) xxviii SECOND AMENDMENT TO CREDIT AGREEMENT among KCS RESOURCES, INC. KCS PIPELINE SYSTEMS, INC. AS BORROWERS and BANK ONE, TEXAS, NATIONAL ASSOCIATION AS A BANK, THE AGENT, AND THE ISSUING BANK and CIBC, INC. AS A BANK Effective as of December 22, 1994 2 TABLE OF CONTENTS
PAGE ---- ARTICLE I. DEFINITIONS ......................................... 1 1.01 Terms Defined Above ........................... 1 1.02 Terms Defined in Agreement .................... 1 1.03 References .................................... 1 1.04 Articles and Sections ......................... 2 1.05 Number and Gender ............................. 2 ARTICLE II. AMENDMENTS .......................................... 2 2.01 Amendment of Section 1.2 ...................... 2 2.02 Amendment of Section 2.7 ...................... 2 2.03 Amendment of Section 2.12 ..................... 3 ARTICLE III. CONDITIONS .......................................... 3 3.01 Receipt of Documents .......................... 3 3.02 Accuracy of Representations and Warranties .... 4 3.03 Matters Satisfactory to Lender ................ 4 ARTICLE IV. REPRESENTATIONS AND WARRANTIES ...................... 4 ARTICLE V. RATIFICATION ........................................ 4 ARTICLE VI. MISCELLANEOUS ....................................... 4 6.01 Scope of Amendment ............................ 4 6.02 Agreement as Amended .......................... 5 6.03 Parties in Interest ........................... 5 6.04 Rights of Third Parties ....................... 5 6.05 ENTIRE AGREEMENT .............................. 5 6.06 GOVERNING LAW ................................. 5 6.07 JURISDICTION AND VENUE ........................ 5
i 3 SECOND AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT This SECOND AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT (this "Second Amendment") is made and entered into effective as of December 22, 1994, between KCS RESOURCES, INC. and KCS PIPELINE SYSTEMS, INC., both Delaware corporations, ("Borrowers") and BANK ONE, TEXAS, NATIONAL ASSOCIATION, a national banking association, as a Bank, the Agent and the Issuing Bank, and CIBC, INC., a Canadian Chartered Bank, each a ("Bank") and collectively, the ("Banks"). W I T N E S S E T H: WHEREAS, the above named parties did execute and exchange counterparts of that certain Amended and Restated Credit Agreement dated September 29, 1994, (the "Agreement"), to which reference is here made for all purposes; WHEREAS, the parties subject to and bound by the Agreement are desirous of amending the Agreement in the particulars hereinafter set forth; NOW, THEREFORE, in consideration of the mutual covenants and agreements of the parties to the Agreement, as set forth therein, and the mutual covenants and agreements of the parties hereto, as set forth in this Second Amendment, the parties hereto agree as follows: ARTICLE I. DEFINITIONS 1.01 Terms Defined Above. As used herein, each of the terms "Agreement," "Borrowers," "Second Amendment," and "Banks" shall have the meaning assigned to such term hereinabove. 1.02 Terms Defined in Agreement. As used herein, each term defined in the Agreement shall have the meaning assigned thereto in the Agreement, unless expressly provided herein to the contrary. 1.03 References. References in this Second Amendment to Article or Section numbers shall be to Articles and Sections of this Second Amendment, unless expressly stated herein to the contrary. References in this Second Amendment to "hereby," "herein," "hereinafter," "hereinabove," "hereinbelow," "hereof," and "hereunder" shall be to this Second Amendment in its entirety 4 and not only to the particular Article or Section in which such reference appears. 1.04 Articles and Sections. This Second Amendment, for convenience only, has been divided into Articles and Sections and it is understood that the rights, powers, privileges, duties, and other legal relations of the parties hereto shall be determined from this Second Amendment as an entirety and without regard to such division into Articles and Sections and without regard to headings prefixed to such Articles and Sections. 1.05 Number and Gender. Whenever the context requires, reference herein made to the single number shall be understood to include the plural and likewise the plural shall be understood to include the singular. Words denoting sex shall be construed to include the masculine, feminine, and neuter, when such construction is appropriate, and specific enumeration shall not exclude the general, but shall be construed as cumulative. Definitions of terms defined in the singular and plural shall be equally applicable to the plural or singular, as the case may be. ARTICLE II. AMENDMENTS The Borrowers and the Banks hereby amend the Agreement in the following particulars: 2.01 Amendment of Section 1.1. Section 1.1 of the Agreement is hereby amended as follows: The following definition is amended to read as follows: "Applicable Rate" means: (i) during the period that an Advance is a Base Rate Advance, the Base Rate plus one-fourth of one percent (1/4%); (ii) during the period that an Advance is a Eurodollar Advance, the Adjusted Eurodollar Rate plus one and one-half percent (1-1/2%); and (iii) during the period that an Advance is a CD Advance, the Adjusted CD Rate plus one and three-quarters percent (1-3/4%). 2.02 Amendment of Section 6.2. Section 6.2 of the Agreement is hereby amended to read as follows: 6.02 Prepayment. The Borrowers may, upon same day notice to Agent by noon, central standard or daylight time, in the case of Base Rate Advances, at least two (2) Business Days prior notice to 2 5 Agent in the case of CD Advances, and two (2) Business Days prior notice to Bank in the case of Eurodollar Advances prepay the Bank One and/or CIBC Credit Note in whole at any time or from time to time in part without premium or penalty but with accrued interest to the date of prepayment on the amount so prepaid; provided that a. Fixed Rate Advances may be prepaid only on the last day of the Interest Period for such Advances, and b. each partial prepayment shall be in the principal amount of $100,000 or an integral multiple thereof. 2.03 Substitution of Exhibit B. Exhibit B, ADVANCE REQUEST FORM, of the Agreement is replaced by the Exhibit B attached hereto and made a part hereof. ARTICLE III. CONDITIONS The obligation of the Banks to amend the Agreement as provided herein is subject to the fulfillment of the following conditions precedent: 3.01 Receipt of Documents. The Banks shall have received, reviewed, and approved the following documents and other items, appropriately executed when necessary and in form and substance satisfactory to the Lender: (a) multiple counterparts of this Second Amendment and the Note, as requested by the Lender; (b) multiple counterparts of Notice of Final Agreement; and (c) such other agreements, documents, items, instruments, opinions, certificates, waivers, consents, and evidence as the Lender may reasonably request. 3.02 Accuracy of Representations and Warranties. The representations and warranties contained in Article X of the Agreement and this Second Amendment shall be true and correct. 3.03 Matters Satisfactory to Banks. All matters incident to the consummation of the transactions contemplated hereby shall be satisfactory to the Banks. 3 6 ARTICLE IV. REPRESENTATIONS AND WARRANTIES The Borrowers hereby expressly re-make, in favor of the Banks, all of the representations and warranties set forth in Article X of the Agreement, and represents and warrants that all such representations and warranties remain true and unbreached. ARTICLE V. RATIFICATION Each of the parties hereto does hereby adopt, ratify, and confirm the Agreement and the other Loan Documents, in all things in accordance with the terms and provisions thereof, as amended by this Second Amendment. ARTICLE VI. MISCELLANEOUS 6.01 Scope of Amendment. The scope of this Second Amendment is expressly limited to the matters addressed herein and this Second Amendment shall not operate as a waiver of any past, present, or future breach, or Event of Default under the Agreement, except to the extent, if any, that any such breach, or Event of Default is remedied by the effect of this Second Amendment. 6.02 Agreement as Amended. All references to the Agreement in any document heretofore or hereafter executed in connection with the transactions contemplated in the Agreement shall be deemed to refer to the Agreement as amended by this Second Amendment. 6.03 Parties in Interest. All provisions of this Second Amendment shall be binding upon and shall inure to the benefit of the Borrowers, the Banks and their respective successors and assigns. 6.04 Rights of Third Parties. All provisions herein are imposed solely and exclusively for the benefit of the Banks and the Borrowers, and no other Person shall have standing to require satisfaction of such provisions in accordance with their terms and any or all of such provisions may be freely waived in whole or in part by the Banks at any time if in its sole discretion it deems it advisable to do so. 6.05 ENTIRE AGREEMENT. THIS WRITTEN LOAN AGREEMENT REPRESENTS THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT 4 7 ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES. 6.06 APPLICABLE LAW. THIS AGREEMENT AND EACH OF THE OTHER LOAN DOCUMENTS (EXCEPT TO EXTENT OTHERWISE EXPRESSLY PROVIDED IN ANY OF THEM) SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS AND TO THE EXTENT APPLICABLE, LAWS OF THE UNITED STATES OF AMERICA; PROVIDED HOWEVER, THE PROVISIONS OF CHAPTER 15 OF THE TEXAS CREDIT CODE (VERNON'S TEXAS CIVIL STATUTES, ARTICLE 5069-15) ARE SPECIFICALLY DECLARED BY THE PARTIES HERETO NOT TO BE APPLICABLE TO THIS AGREEMENT OR ANY OF THE OTHER LOAN DOCUMENTS OR TO THE TRANSACTIONS CONTEMPLATED HEREBY. THIS AGREEMENT AND EACH OF THE OTHER LOAN DOCUMENTS HAVE BEEN ENTERED INTO IN HARRIS COUNTY, TEXAS, AND EACH SHALL BE PERFORMABLE BY EACH OF THE BORROWERS FOR ALL PURPOSES IN HARRIS COUNTY, TEXAS. 6.07 SUBMISSION TO JURISDICTION; WAIVERS. TO THE MAXIMUM EXTENT NOT EXPRESSLY PROHIBITED BY APPLICABLE LAW FROM TIME TO TIME IN EFFECT, EACH OF THE BORROWERS HEREBY KNOWINGLY, VOLUNTARILY AND INTENTIONALLY (AND AFTER IT HAS CONSULTED WITH ITS OWN ATTORNEY) IRREVOCABLY AND UNCONDITIONALLY: i) SUBMITS FOR ITSELF AND ITS PROPERTY IN ANY LEGAL ACTION OR PROCEEDING RELATING TO THE LOAN DOCUMENTS OR FOR RECOGNITION AND ENFORCEMENT OF ANY JUDGMENT IN RESPECT THEREOF, TO THE NON-EXCLUSIVE GENERAL JURISDICTION OF THE COURTS OF HARRIS COUNTY, TEXAS, THE COURTS OF THE UNITED STATES OF AMERICA FOR THE SOUTHERN DISTRICT OF TEXAS, HOUSTON DIVISION, AND APPELLATE COURTS FROM ANY THEREOF; ii) CONSENTS THAT ANY SUCH ACTION OR PROCEEDING MAY BE BROUGHT IN SUCH COURTS, AND WAIVES ANY OBJECTION THAT IT MAY NOW OR HEREAFTER HAVE TO THE VENUE OR ANY SUCH ACTION OR PROCEEDING IN ANY SUCH COURT OR THAT SUCH ACTION OR PROCEEDING WAS BROUGHT IN AN INCONVENIENT COURT AND AGREES NOT TO PLEAD OR CLAIM THE SAME; iii) AGREES THAT SERVICE OF PROCESS IN ANY SUCH ACTION OR PROCEEDING MAY BE EFFECTED BY MAILING A COPY THEREOF BY REGISTERED OR CERTIFIED MAIL, RETURN RECEIPT REQUESTED, (OR ANY SUBSTANTIALLY SIMILAR FORM OF MAIL), POSTAGE PREPAID, TO SUCH PERSON AT ITS ADDRESS FOR NOTICES REFERRED TO IN SECTION 12.09 OF THE CREDIT AGREEMENT, ATTENTION TO AN AUTHORIZED REPRESENTATIVE OF SUCH PERSON (WITH COPY THEREOF, SO MAILED, TO ORLOFF, LOWENBACH, STIFELMAN & SIEGEL, P.A., 101 EISENHOWER PARKWAY, ROSELAND, NEW JERSEY 07068-1082, ATTENTION: MR. RALPH M. LOWENBACH) OR AT SUCH OTHER ADDRESS OR ADDRESSES OF WHICH BANK SHALL HAVE BEEN NOTIFIED PURSUANT HERETO; 5 8 iv) AGREES THAT NOTHING HEREIN SHALL AFFECT THE RIGHT TO EFFECT SERVICE OF PROCESS IN ANY OTHER MANNER PERMITTED BY LAW OR SHALL LIMIT THE RIGHT TO SUE IN ANY OTHER JURISDICTION; AND v) IN RECOGNITION THAT IT MAY BE ENTITLED TO A TRIAL IN WHICH MATTERS OF FACT ARE DETERMINED BY A JURY (AS OPPOSED TO A TRIAL IN WHICH SUCH MATTERS ARE DETERMINED BY A PRESIDING JUDGE), WAIVES ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT TO ANY LITIGATION DIRECTLY OR INDIRECTLY AT ANY TIME ARISING OUT OF, UNDER, OR IN CONJUNCTION WITH, ANY OF THE LOAN DOCUMENTS, OR ANY OF THE TRANSACTIONS PROVIDED FOR HEREIN OR THEREIN OR CONTEMPLATED HEREBY OR THEREBY, WHETHER BEFORE OR AFTER MATURITY AND WHETHER OR NOT COMMENCED BY OR AGAINST IT. IN WITNESS WHEREOF, this Second Amendment to Credit Agreement is executed effective the date first hereinabove written. "KRI": ----- KCS RESOURCES, INC. By: /s/ C. R. DEVINE ------------------------------------ Name: C. R. Devine Title: Vice President Address for Notices: ------------------- KCS Resources, Inc. 379 Thomall Street Edison, New Jersey 08837 Attn: An Authorized Representative (as herein defined and addressed as expressly required hereby) Telecopy: (908) 603-8960 Principal Place of Business: --------------------------- 1800 West Loop South, Suite 1400 Houston, Texas 77027 6 9 "KCS Pipeline" KCS PIPELINE SYSTEMS, INC. By: /s/ Harry Lee Stout ----------------------- Harry Lee Stout President GUARANTOR: KCS ENERGY, INC. By: /s/ C.R. Devine ----------------------- C.R. Devine Vice President BANK ONE, TEXAS, N.A. By: /s/ Gary L. Stone ----------------------- Gary L. Stone Senior Vice President CIBC, INC. By: /s/ Gary Gaskill ----------------------- Name: Gary Gaskill Title: Vice President 7 EX-10.XXIX 3 3RD AMENDMENT DATED 3/15/95 TO CREDIT AGREEMENT 1 Exhibit (10) xxix THIRD AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT AMONG KCS RESOURCES, INC., KCS PIPELINE SYSTEMS, INC. AS BORROWERS; KCS ENERGY, INC. AS GUARANTOR; AND BANK ONE, TEXAS, NATIONAL ASSOCIATION AS A BANK, THE AGENT, AND THE ISSUING BANK, AND CIBC, INC. AS A BANK Effective as of March 15, 1995 2 TABLE OF CONTENTS PAGE ---- ARTICLE I. DEFINITIONS......................................... 1 1.01 Terms Defined Above........................... 1 1.02 Terms Defined in Agreement.................... 1 1.03 References.................................... 2 1.04 Articles and Sections......................... 2 1.05 Number and Gender............................. 2 ARTICLE II. AMENDMENTS.......................................... 2 2.01 Amendment of Section 1.02..................... 2 2.02 Amendment of Section 2.03..................... 3 2.03 Amendment of Section 2.07..................... 3 2.04 Amendment of Section 3.03..................... 3 2.05 Amendment of Section 3.06..................... 3 ARTICLE III. CONDITIONS.......................................... 3 3.01 Receipt of Documents.......................... 3 3.02 Accuracy of Representations and Warranties.... 4 3.03 Matters Satisfactory to Banks................. 4 ARTICLE IV. REPRESENTATIONS AND WARRANTIES...................... 4 ARTICLE V. RATIFICATION........................................ 4 ARTICLE VI. MISCELLANEOUS....................................... 4 6.01 Scope of Amendment............................ 4 6.02 Agreement as Amended.......................... 4 6.03 Parties in Interest........................... 5 6.04 Rights of Third Parties....................... 5 6.05 ENTIRE AGREEMENT.............................. 5 6.06 GOVERNING LAW................................. 5 6.07 JURISDICTION AND VENUE........................ 5 i 3 THIRD AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT This THIRD AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT (this "Third Amendment") is made and entered into effective as of March 15, 1995, among KCS RESOURCES, INC., a Delaware corporation ("KRI"), KCS PIPELINE SYSTEMS, INC., a Delaware corporation ("KCS Pipeline," and together with KRI, collectively the "Borrowers"); KCS ENERGY, INC., a Delaware corporation ("Guarantor") and BANK ONE, TEXAS, NATIONAL ASSOCIATION, a national banking association ("Bank One") and CIBC, INC., a Canadian Chartered Bank ("CIBC," with Bank One, CIBC and each financial institution that becomes a party hereto or entitled to benefits and subject to obligations hereunder subsequent to the date hereof, each a "Bank") and collectively, the "Banks"), and Bank One as agent for the Banks (in such capacity and together with any successors designated pursuant hereto, the "Agent"). W I T N E S S E T H: WHEREAS, the Borrowers and Bank One did execute and exchange counterparts of that certain Amended and Restated Credit Agreement dated March 15, 1994, as amended by that certain First Amendment to Amended and Restated Credit Agreement dated September 29, 1994, and Second Amendment to Amended and Restated Credit Agreement dated December 22, 1994, among the Borrowers, Bank One and CIBC (the "Agreement"), to which reference is here made for all purposes; WHEREAS, the parties subject to and bound by the Agreement are desirous of amending the Agreement in the particulars hereinafter set forth; NOW, THEREFORE, in consideration of the mutual covenants and agreements of the parties to the Agreement, as set forth therein, and the mutual covenants and agreements of the parties hereto, as set forth in this Third Amendment, the parties hereto agree as follows: ARTICLE I. DEFINITIONS 1.01 Terms Defined Above. As used herein, each of the terms "Agent," "Agreement," "Bank," "Banks," "Bank One," "Borrowers," "CIBC," "KCS Pipeline," "KRI" and "Third Amendment" shall have the meaning assigned to such term hereinabove. 1.02 Terms Defined in Agreement. As used herein, each term defined in the Agreement shall have the meaning assigned thereto in the Agreement, unless expressly provided herein to the contrary. 4 1.03 References. References in this Third Amendment to Article or Section numbers shall be to Articles and Sections of this Third Amendment, unless expressly stated herein to the contrary. References in this Third Amendment to "hereby," "herein," "hereinafter," "hereinabove," "hereinbelow," "hereof," and "hereunder" shall be to this Third Amendment in its entirety and not only to the particular Article or Section in which such reference appears. 1.04 Articles and Sections. This Third Amendment, for convenience only, has been divided into Articles and Sections and it is understood that the rights, powers, privileges, duties, and other legal relations of the parties hereto shall be determined from this Third Amendment as an entirety and without regard to such division into Articles and Sections and without regard to headings prefixed to such Articles and Sections. 1.05 Number and Gender. Whenever the context requires, reference herein made to the single number shall be understood to include the plural and likewise the plural shall be understood to include the singular. Words denoting sex shall be construed to include the masculine, feminine, and neuter, when such construction is appropriate, and specific enumeration shall not exclude the general, but shall be construed as cumulative. Definitions of terms defined in the singular and plural shall be equally applicable to the plural or singular, as the case may be. ARTICLE II. AMENDMENTS The Borrowers and the Banks hereby amend the Agreement in the following particulars: 2.01 Amendment of Section 1.02. Section 1.02 of the Agreement is hereby amended as follows: The following definitions are amended to read as follows: "Bank One Credit Borrowing Base" shall mean 65.34% of the Credit Borrowing Base. "CIBC Credit Borrowing Base" shall mean 34.66% of the Credit Borrowing Base. "CIBC Letter of Credit Limit" means 34.66% of Bank One's Letter of Credit Limit. "Commitment Percentage" shall mean 65.34%, as to Bank One, and as to CIBC, 34.66%. 2 5 2.02 Amendment of Section 2.03. The sixth sentence of Section 2.03 is hereby amended to read as follows: "Bank One will make Advances equal to 65.34% of the total request available to the requesting Borrower by depositing or wire transferring, as applicable, the same in immediately available funds in or to, as applicable, the account specified by such requesting Borrower." 2.03 Amendment of Section 2.07. There is added to Section 2.07(b) the following: "Agent shall also notify CIBC in writing of the amount of such demand for payment and CIBC shall promptly pay to Bank One CIBC's pro rata share of such total amount." There is added to Section 2.07(c) the following: "Bank One shall remit promptly to CIBC its pro rata share of such fees." 2.04 Amendment of Section 3.03. The sixth sentence of Section 3.03 of the Agreement is hereby amended to read as follows: "CIBC will make Advances equal to 34.66% of the total request available to the requesting Borrower by depositing or wire transferring, as applicable, the same in immediately available funds in or to, as applicable, the account specified by such requesting Borrower." 2.05 Amendment of Section 3.06. The last sentence of Section 3.06 of the Agreement is hereby amended to read as follows: "During the period from the date hereof to the date of the first redetermination of the CIBC Credit Borrowing Base hereafter, the CIBC Credit Borrowing Base shall be $26,000,000." ARTICLE III. CONDITIONS The obligation of the Banks to amend the Agreement as provided herein is subject to the fulfillment of the following conditions precedent: 3.01 Receipt of Documents. The Banks shall have received, reviewed, and approved the following documents and other 3 6 items, appropriately executed when necessary and in form and substance satisfactory to the Banks: (a) multiple counterparts of this Third Amendment, as requested by the Banks; (b) Notice of Final Agreement; and (c) such other agreements, documents, items, instruments, opinions, certificates, waivers, consents, and evidence as the Banks may reasonably request. 3.02 Accuracy of Representations and Warranties. The representations and warranties contained in Article IV of the Agreement and this Third Amendment shall be true and correct. 3.03 Matters Satisfactory to Banks. All matters incident to the consummation of the transactions contemplated hereby shall be satisfactory to the Banks. ARTICLE IV. REPRESENTATIONS AND WARRANTIES The Borrowers hereby expressly re-make, in favor of the Banks, all of the representations and warranties set forth in Article IV of the Agreement, and represent and warrant that all such representations and warranties remain true and unbreached. ARTICLE V. RATIFICATION Each of the parties hereto does hereby adopt, ratify, and confirm the Agreement and the other Loan Documents, in all things in accordance with the terms and provisions thereof, as amended by this Third Amendment. ARTICLE VI. MISCELLANEOUS 6.01 Scope of Amendment. The scope of this Third Amendment is expressly limited to the matters addressed herein and this Third Amendment shall not operate as a waiver of any past, present, or future breach, Default, or Event of Default under the Agreement, except to the extent, if any, that any such breach, Default, or Event of Default is remedied by the effect of this Third Amendment. 6.02 Agreement as Amended. All references to the Agreement in any document heretofore or hereafter executed in connection with the transactions contemplated in the Agreement 4 7 shall be deemed to refer to the Agreement as amended by this Third Amendment. 6.03 Parties in Interest. All provisions of this Third Amendment shall be binding upon and shall inure to the benefit of the Borrowers, the Banks and their respective successors and assigns. 6.04 Rights of Third Parties. All provisions herein are imposed solely and exclusively for the benefit of the Banks and the Borrowers, and no other Person shall have standing to require satisfaction of such provisions in accordance with their terms and any or all of such provisions may be freely waived in whole or in part by the Banks at any time if in its sole discretion it deems it advisable to do so. 6.05 ENTIRE AGREEMENT. THIS THIRD AMENDMENT CONSTITUTES THE ENTIRE AGREEMENT BETWEEN THE PARTIES HERETO WITH RESPECT TO THE SUBJECT HEREOF AND SUPERSEDES ANY PRIOR AGREEMENT, WHETHER WRITTEN OR ORAL, BETWEEN SUCH PARTIES REGARDING THE SUBJECT HEREOF. FURTHERMORE IN THIS REGARD, THIS THIRD AMENDMENT, THE AGREEMENT, THE NOTE, THE SECURITY INSTRUMENTS, AND THE OTHER WRITTEN DOCUMENTS REFERRED TO IN THE AGREEMENT OR EXECUTED IN CONNECTION WITH OR AS SECURITY FOR THE NOTE REPRESENT, COLLECTIVELY, THE FINAL AGREEMENT AMONG THE PARTIES THERETO AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES. 6.06 GOVERNING LAW. THIS THIRD AMENDMENT, THE AGREEMENT AND THE NOTE SHALL BE DEEMED TO BE CONTRACTS MADE UNDER AND SHALL BE CONSTRUED IN ACCORDANCE WITH AND GOVERNED BY THE LAWS OF THE STATE OF TEXAS. THE PARTIES ACKNOWLEDGE AND AGREE THAT THIS AGREEMENT AND THE NOTE AND THE TRANSACTIONS CONTEMPLATED HEREBY BEAR A NORMAL, REASONABLE, AND SUBSTANTIAL RELATIONSHIP TO THE STATE OF TEXAS. 6.07 JURISDICTION AND VENUE. ALL ACTIONS OR PROCEEDINGS WITH RESPECT TO, ARISING DIRECTLY OR INDIRECTLY IN CONNECTION WITH, OUT OF, RELATED TO, OR FROM THIS THIRD AMENDMENT, THE AGREEMENT OR ANY OTHER LOAN DOCUMENT MAY BE LITIGATED IN COURTS HAVING SITUS IN HARRIS COUNTY, TEXAS. EACH OF THE BORROWERS AND THE BANKS HEREBY SUBMITS TO THE JURISDICTION OF ANY LOCAL, STATE, OR FEDERAL COURT LOCATED IN HARRIS COUNTY, TEXAS, AND HEREBY WAIVES ANY RIGHTS IT MAY HAVE TO TRANSFER OR CHANGE THE JURISDICTION OR VENUE OF ANY LITIGATION BROUGHT AGAINST IT BY THE BORROWERS OR THE BANKS IN ACCORDANCE WITH THIS SECTION. 5 8 IN WITNESS WHEREOF, this Third Amendment to Amended and Restated Credit Agreement is executed effective the date first hereinabove written. BORROWERS: KCS RESOURCES, INC. By: /s/ Henry A. Jurand ---------------------------- Printed Name: Henry A. Jurand Title: Treasurer KCS PIPELINE SYSTEMS, INC. By: /s/ Henry A. Jurand ---------------------------- Printed Name: Henry A. Jurand Title: Treasurer GUARANTOR: KCS ENERGY, INC. By: /s/ Henry A. Jurand ---------------------------- Printed Name: Henry A. Jurand Title: Vice-President BANKS: BANK ONE, TEXAS, NATIONAL ASSOCIATION By: /s/ Melanie M. Ottens ---------------------------- Melanie M. Ottens Vice President CIBC INC. By: /s/ Gary C. Gaskill ---------------------------- Printed Name: Gary C. Gaskill Title: Vice President 6 9 NOTICE OF FINAL AGREEMENT To: KCS Resources, Inc. (collectively "Borrowers") KCS Pipeline Systems, Inc. 379 Thomall Street Edison, New Jersey 08837 KCS Energy, Inc. ("Guarantor") 379 Thomall Street Edison, New Jersey 08837 As of the effective date of this Notice, Borrower and BANK ONE, TEXAS, NATIONAL ASSOCIATION and CIBC, INC. ("Banks") have consummated a transaction pursuant to which Banks have agreed to make a loan or loans to Borrower, to renew and extend an existing loan or loans to Borrower, and/or to otherwise extend credit or make financial accommodations to or for the benefit of Borrower, in an aggregate amount up to $100,000,000 (collectively, whether one or more, the "Loan"). In connection with the Loan, Borrower and Banks have executed and delivered and may hereafter execute and deliver certain agreements, instruments and documents (collectively hereinafter referred to as the "Written Loan Agreement"). It is the intention of Borrower and Banks that this Notice be incorporated by reference into each of the written agreements, instruments and documents comprising the Written Loan Agreement. Borrower and Banks each warrants and represents that the entire agreement made and existing by or among Borrower, and Banks with respect to the Loan is and shall be contained within the Written Loan Agreement, as amended and supplemented hereby, and that no agreements or promises exist or shall exist by or between Borrower and Banks that are not reflected in the Written Loan Agreement. THE WRITTEN LOAN AGREEMENT REPRESENTS THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES. Effective Date: March 15, 1995 BANK ONE, TEXAS, NATIONAL ASSOCIATION By: MELANIE M. OTTENS -------------------- Melanie M. Ottens Vice President 10 CIBC, INC. By: /s/ Gary C. Gaskill ---------------------- Name: Gary C. Gaskill -------------------- Title: Vice President ------------------- ACKNOWLEDGED AND AGREED: BORROWERS: KCS RESOURCES, INC. By: /s/ Henry A. Jurand ------------------------- Name: Henry A. Jurand ----------------------- Title: Treasurer ---------------------- KCS PIPELINE SYSTEMS, INC. By: /s/ Henry A. Jurand ------------------------- Name: Henry A. Jurand ----------------------- Title: Treasurer ---------------------- GUARANTOR: KCS ENERGY, INC. By: /s/ Henry A. Jurand ------------------------- Name: Henry A. Jurand ----------------------- Title: Vice President ---------------------- EX-10.XXX 4 1ST AMENDMENT DATED 4/1/95 TO LOAN AGREEMENT 1 Exhibit (10) xxx FIRST AMENDMENT TO THE LOAN AGREEMENT dated as of July 1, 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 2 FIRST AMENDMENT TO THE LOAN AGREEMENT THIS FIRST AMENDMENT TO THE LOAN AGREEMENT, dated as of July 1, 1995 (this "Amendment") among KCS Energy Marketing, Inc., a New Jersey corporation (the "Borrower"), KCS Energy, Inc., a Delaware corporation (the "Parent"), Proliq, Inc. a New Jersey corporation ("Proliq" and, together with the Parent, the "Guarantors") and Canadian Imperial Bank of Commerce (the "Lender"), acting through certain offices in the United States of America ("CIBC"), as such terms are defined in the Agreement. W I T N E S S E T H: WHEREAS, KCS Energy Marketing, Inc. KCS Energy, Inc., Proliq, Inc. and CIBC have heretofore entered into a certain Loan Agreement, dated as of January 11, 1995, (the "Agreement"); WHEREAS, KCS Energy Marketing, Inc. KCS Energy, Inc., Proliq, Inc. and CIBC now desire to further amend the Agreement in certain respects as hereinunder provided; NOW THEREFORE, the parties hereto agree as follows: SECTION 1. Definitions. Unless otherwise defined herein or the context otherwise requires, the terms used herein shall have the meanings assigned to such terms in the Agreement. SECTION 2. Amendments to the Agreement. The following amendments are made to the Agreement. SECTION 2.1.1 SECTION 1 of the definition of "Loan Commitment" is hereby amended by changing the amount "$25,000,000" therein to "$35,000,000" effective August 20, 1995. SECTION 2.1.2 SECTION 1 of the definition of "Reserve" section 4(a)(ii) is hereby amended by changing the percentage "5.375%" therein to "5.25%". SECTION 2.1.3 SECTION 1 of the definition of "Standard Concentration Limit" is hereby amended by changing the amount "$600,000" therein to "4% of the outstanding Loan amount". SECTION 2.1.4 SECTION 3.1(e)(i)(b) Payment of Interest is hereby amended by changing the percentage "1.375%" therein to "1.25%". SECTION 3. Representations and Warranties. KCS Energy Marketing, Inc., KCS Energy, Inc. and Proliq, Inc. hereby repeats and reaffirms as of the effective date of this Amendment the representations and warranties of KCS Energy Marketing, Inc., KCS Energy, Inc. and Proliq, Inc. contained in the Agreement with the same force and effect as though such representations and warranties had been made as of the effective date of this Amendment, provided, that (i) all references in such representations and warranties to the Agreement shall refer to the Agreement as amended by this Amendment, and (ii) the reference in Section 6.10(b) to September 30, 1994 shall be deemed to refer to March 31, 1995. 1 3 SECTION 4. Ratification of and References to the Agreement. KCS Energy Marketing, Inc, KCS Energy, Inc., Proliq, Inc. and CIBC hereby agree that, except as amended hereby, the Agreement shall remain in full force and effect and is hereby ratified, approved and confirmed in all respects. All references in the Agreement in any other agreement or document shall hereafter be deemed to refer to the Agreement as amended hereby. SECTION 5. Execution in Counterparts, Effectiveness, etc. This Amendment may be executed by the parties hereto in several counterparts, each of which shall be deemed to be an original and all of which shall constitute together but one and the same agreement. This Amendment shall become effective when counterparts executed on behalf of KCS Energy Marketing, Inc, KCS Energy, Inc., Proliq, Inc. and CIBC hereof have been received by CIBC. SECTION 6. Governing Law. THIS AMENDMENT SHALL BE DEEMED TO BE A CONTRACT MADE UNDER AND GOVERNED BY THE INTERNAL LAWS OF THE STATE OF NEW YORK. SECTION 7. Severability of Provisions. Any provision of this Amendment which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof or affecting the validity or enforceability of such provision in any other jurisdiction. SECTION 8. Successors and Assigns. This Amendment shall be binding upon, and shall inure to the benefit of, the parties hereto and their respective successors and assigns. 2 4 IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed by their respective officers thereunto duly authorized as of the day and year first above written. KCS Energy Marketing Inc., as Borrower By: /s/ Henry A. Jurand --------------------------- Name: Title: KCS Energy, Inc., as Guarantor By: /s/ Henry A. Jurand --------------------------- Name: Title: Proliq, Inc., as Guarantor By: /s/ Henry A. Jurand --------------------------- Name: Title: Canadian Imperial Bank of Commerce as Lender By: /s/ Barbara Duberstein --------------------------- Name: Barbara Duberstein Title: Authorized Signatory 3 EX-11 5 STATEMENT RE COMPUTATION OF PER SHARE EARNINGS 1 Exhibit 11 Statement re Computation of Per Share Earnings Earnings per share were calculated as follows:
For the Years Ended September 30, --------------------------------- 1995 1994 1993 ---- ---- ---- In Thousands Except per share amount Net income $22,777 $23,281 $13,678 ============== ============== ============== Average shares of common stock outstanding 11,467 11,477 10,916 Add: Net shares assumed to be issued for dilutive stock options 292 351 620 -------------- -------------- -------------- Average shares of common stock and common stock equivalents outstanding 11,759 11,828 11,536 ============== ============== ============== Earnings per share of common stock and common stock equivalents $1.94 $1.97 $1.19 ============== ============== ==============
EX-21 6 SUBSIDIARIES OF THE REGISTRANT 1 Exhibit 21. KCS ENERGY, INC. LIST OF WHOLLY-OWNED SUBSIDIARIES KCS Resources, Inc. KCS Pipelines Systems, Inc. Enercorp Gas Marketing, Inc. KCS Energy Risk Management, Inc. National Enerdrill Corporation Proliq, Inc. (Formerly Utility Propane Company) KCS Energy Marketing, Inc. KCS Power Marketing, Inc. KCS Michigan Resources EX-23 7 CONSENT OF ARTHUR ANDERSEN, LLP 1 Exhibit 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTS As independent public accountants, we hereby consent to the use of our reports included in this Form 10-K, into KCS Energy, Inc.'s previously filed Registration Statement File Nos. 33-25707, 33-28899, 33-45923 and 33-63982. Arthur Andersen LLP New York, New York December 22, 1995 EX-27 8 FINANCIAL DATA SCHEDULE
5 YEAR SEP-30-1995 OCT-01-1995 SEP-30-1995 4,187 0 44,441 347 1,206 55,369 249,324 82,797 271,982 58,114 0 0 0 124 95,501 271,982 423,580 423,580 330,600 330,600 55,031 0 6,036 34,332 11,555 22,777 0 0 0 22,777 1.94 1.94
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