-----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, BJrnYtePLBEzKDY109fKUEBSiKIukRm4HaDPztPd/BaFftyOtehMokEIwJ8mNy1g ggbf1myIxmjL7PF7YUswKQ== 0000014525-95-000032.txt : 19951221 0000014525-95-000032.hdr.sgml : 19951221 ACCESSION NUMBER: 0000014525-95-000032 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19950930 FILED AS OF DATE: 19951220 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: BROOKLYN UNION GAS CO CENTRAL INDEX KEY: 0000014525 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS DISTRIBUTION [4924] IRS NUMBER: 110584613 STATE OF INCORPORATION: NY FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-00722 FILM NUMBER: 95602844 BUSINESS ADDRESS: STREET 1: ONE METROTEC CENTER CITY: BROOKLYN STATE: NY ZIP: 11201 BUSINESS PHONE: 7184032000 MAIL ADDRESS: STREET 1: ONE METROTEC CENTER CITY: BROOKLYN STATE: NY ZIP: 11201 10-K 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-K (Mark One) 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 number 1-722 THE BROOKLYN UNION GAS COMPANY (Exact name of Registrant as specified in its charter) New York 11-0584613 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) ONE METROTECH CENTER, BROOKLYN, NEW YORK 11201-3850 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code 718-403-2000 Securities registered pursuant to Section 12(b) of the Act: Name of Each Exchange on Title of Each Class Which Registered Common Capital Stock-$.33 1/3 par value New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ( ) Aggregate market value of registrant's voting Common Stock held by non-affiliates as of December 13, 1995 was $1,385,422,629. On December 13, 1995 the Company had 49,041,509 shares of Common Stock outstanding. DOCUMENTS INCORPORATED BY REFERENCE Part of Documents Form 10-K Definitive Proxy Statement dated December 28, 1995 Part III
PART I Item 1. Business The Company 2 Subsidiaries 3 Gas Supply 5 Regulation and Rate Matters 6 Competition 7 Research and Development 8 Employees 8 Environmental Matters 9 Item 2. Properties 9 Item 3. Legal Proceedings 10 Item 4. Submission of Matters to a Vote of Security Holders 10 PART II Item 5. Market for the Registrant's Common Stock and Related Security Holder Matters 10 Item 6. Selected Financial Data 13 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 14 Item 8. Financial Statements and Supplementary Data 23 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 47 PART III Item 10. Directors and Executive Officers of the Registrant 47 Item 11. Executive Compensation 47 & 49 Item 12. Security Ownership of Certain Beneficial Owners and Management 47 Item 13. Certain Relationships and Related Transactions 47 Part IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 48 Signatures 56
Part I Item 1. Business The Company The Brooklyn Union Gas Company (Company) was incorporated in the State of New York in 1895 as a combination of existing companies, the first of which was granted a franchise in 1849. The Company distributes natural gas at retail, primarily in a territory of approximately 187 square miles, which includes the Boroughs of Brooklyn and Staten Island and two-thirds of the Borough of Queens, all in New York City. The population of the territory served is approximately 4,000,000. As of September 30, 1995, the Company had approximately 1,125,000 active meters, of which approximately 1,086,000 were residential. The Company is subject to the regulatory jurisdiction of the New York State Public Service Commission (PSC). The Company's executive offices are located at One MetroTech Center, Brooklyn, New York 11201-3850. Its telephone number is (718)403-2000. Financial and other information is also available through the World Wide Web at http://www.bug.com. The Company's business is influenced by seasonal weather conditions. Annual revenues are substantially realized during the heating season (November 1 to April 30) as a result of the large proportion of heating sales, primarily residential, compared to total sales. Accordingly, results of operations historically are most favorable in the second quarter (the three months ended March 31) of the Company's fiscal year, with results of operations being next most favorable in the first quarter. Results for the third quarter are marginally unprofitable, and losses are incurred in the fourth quarter. The effect on utility earnings of variations in revenues caused by abnormal weather during the heating season is largely offset by the operation of a Weather Normalization Adjustment contained in the Company's tariff (see Item 1., "Business - Regulation and Rate Matters"). Also, results of operations are affected by the timing and amounts of approved rate changes. The heating capacity of gas is measured in therms. One therm equals 100,000 BTUs, the heat content of approximately 100 cubic feet of natural gas. The heat content of approximately 1,000,000 cubic feet of gas represents 10,000 therms or 1 MDTH. Accordingly, one billion cubic feet (BCF) of gas equals approximately 1,000 MDTH. For the fiscal year ended September 30, 1995, utility firm gas sales were 123,356 MDTH, of which 75% were residential, 12% commercial, 8% governmental and 5% industrial. Other utility gas sales and transportation deliveries to off-system and interruptible customers amounted to 49,910 MDTH. In addition, utility capacity release transactions amounted to approximately 32,170 MDTH. Subsidiaries The PSC has authorized the Company to invest up to 20% of its consolidated capitalization in non-utility energy-related businesses through fiscal 1996. This authorization is based upon the Company's cash investments less dividends received. At September 30, 1995, the total investment in non-utility subsidiaries computed on this basis was approximately 14% of capitalization. In August 1995, the Company filed a petition with the PSC to organize its utility operations and those of its subsidiaries within a holding company. (See Part II, Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations - 'Rate and Regulatory Matters - Holding Company Petition and Price Cap Proposal'.") If the holding company petition is approved, the Company will no longer require this investment authorization. The Company's principal wholly-owned subsidiaries participate and own investments in gas exploration, production, marketing, and cogeneration. Subsidiaries also have minority interests in pipeline and storage projects. In fiscal 1995, earnings from subsidiaries were $12.8 million, or 27 cents per share, representing 14% of consolidated earnings. For further information regarding operating results of the subsidiaries, see Part II, Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations." Gas Exploration, Production and Marketing Fuel Resources Inc. (FRI) operates in the Arkoma Basin, and its subsidiaries operate in West Virginia, East Texas and Canada. The Houston Exploration Company (THEC) operates in the Gulf of Mexico. In 1995, total gas production was approximately 23 BCF and proved net gas reserves at year-end were 202 BCF. Such reserves are divided equally between FRI and THEC. (For additional information, see Part II, Item 8., "Financial Statements and Supplementary Data," Note 8., "Supplemental Gas and Oil Disclosures.") BRING Gas Services Corp. (BRING), FRI's marketing subsidiary, combined its operations with those of Pennzoil Gas Marketing, Inc., a wholly-owned subsidiary of Pennzoil Corporation, effective as of April 1, 1995. BRING owns a 50% equity interest in the new entity, PennUnion Energy Services, L.L.C. Solex Energy Company, Inc., FRI's Canadian affiliate, acquired an operating gas processing plant located in British Columbia, Canada in 1995. Investments in Energy Services Cogeneration Gas Energy Inc. (GEI) and Gas Energy Cogeneration Inc. (GECI) participate in the development, operation and ownership of cogeneration projects. A GEI subsidiary is a 50% partner in a 100- megawatt facility at John F. Kennedy International Airport (JFK) in Queens, New York. This facility commenced operations in 1995. In October 1993, GEI purchased an 11.3% interest in a previously completed 174-megawatt gas cogeneration plant located in Lockport, New York. GECI is a 50% partner in a 40-megawatt facility that serves the State University of New York at Stony Brook, Long Island. This facility also commenced operations in 1995. Additionally, GECI is a 45% partner in a 50-megawatt gas cogeneration plant that has been producing heat and power at a Northrop Grumman facility located in Bethpage, Long Island, New York. The scope of cogeneration activities also includes providing fuel-management services. GEI subsidiaries provide such services to the JFK, Stony Brook and Northrop Grumman facilities and to another 50-megawatt facility which provides heating and cooling to Nassau Veterans Memorial Coliseum and Nassau Community College. In 1995, these subsidiaries, as fuel managers, provided 12,700 MDTH of gas to cogeneration projects. Pipeline and Other North East Transmission Co., Inc. (NETCO) owns an 11.4% interest in the Iroquois Gas Transmission System (Iroquois), a 375- mile pipeline that currently transports more than 800 MDTH of Canadian gas supply daily to markets in the northeastern United States. The Company currently receives up to 70 MDTH of gas per day through Iroquois. For information regarding governmental investigations of alleged violations involving the Iroquois project, see Part II, Item 8., "Financial Statements and Supplementary Data," Note 6., "Investment in Iroquois Pipeline." Through its affiliates, Brooklyn Union has equity investments in two gas storage facilities located in New York State. Gas Supply General Changes in regulatory policies and market forces have shifted the industry from traditional cost-based regulation involving gas sales, transportation, storage and other related services on a bundled basis by the interstate pipelines toward market-based sales on an unbundled basis. These policy changes have made the market more competitive with respect to gas supply and related services. Accordingly, the PSC has initiated a proceeding to establish policy and implement utility tariff revisions in line with market objectives of providing utility customers with wider choices in gas supply and related services at the local level. (See Part II, Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations - 'Rate and Regulatory Matters - Restructuring Proceeding'.") This proceeding could affect utility gas merchant activities and the Company is managing its gas procurement practices accordingly. In 1995, 66% of gas supply was purchased from domestic sources under long-term contracts, 23% from Canadian sources under long- term contracts and 11% from spot market sources. The Company opened the first New York-based market hub for buyers and sellers of natural gas in the Northeast in fiscal 1994. With interconnections and access to several major pipelines, the New York Market Hub offers transportation, balancing and exchange services to a wide variety of customers, including utilities, municipalities, marketers and large-volume customers. In 1995, the Company delivered 39,200 MDTH of gas and related services to customers in 16 states as well as Washington, D.C. and Ontario, Canada. In addition, capacity release transactions amounted to approximately 32,170 MDTH. Long-Term Supply Under long-term contracts and regulatory certificates applicable to gas supply and pipeline transportation and storage services, the Company's suppliers will provide maximum firm daily total deliveries of 966 MDTH of gas for the 1995-96 winter, consisting of 376 MDTH per day of firm domestic gas supply, 100 MDTH per day of firm Canadian gas supply and 490 MDTH per day of domestic storage and winter services. The Company's major providers of domestic interstate pipeline capacity and related services are: Transcontinental Gas PipeLine Corporation, Texas Eastern Transmission Corporation, Tennessee Gas Pipeline Company (Tennessee), CNG Transmission Corporation and Texas Gas Transmission Company, which provide unbundled firm transportation and storage services. These pipelines are the conduit for the delivery of domestic supplies purchased from natural gas sellers to the Company's market. Total maximum daily U.S. supplies are 866 MDTH of gas. Canadian supplies include 70 MDTH of gas per day purchased from western Canadian suppliers and marketers transported by Iroquois and 30 MDTH of gas per day purchased from the Boundary Gas Project and transported by Tennessee. Canadian gas is produced primarily in the Province of Alberta, and is transported within Canada primarily by TransCanada PipeLines, Ltd. Spot Market Supply The Company continues to purchase gas on the spot market when contractually and economically feasible. In fiscal 1995, spot purchases totaled 17,756 MDTH of gas. Peak-day Supply The Company plans for peak-day demand on the basis of an average temperature of 0oF. Gas demand on such a design peak-day is estimated at 1,128 MDTH during the 1995-96 winter. The highest 24-hour firm sendout experienced by the Company was 1,022 MDTH on January 19, 1994, when the average temperature was 4oF. For the 1995-96 winter, the Company has the capability to provide a maximum peak-day supply of approximately 1,257 MDTH, consisting of firm flowing supply, pipeline storage supply, seasonal winter supply, and vaporized liquefied natural gas (LNG). The Company's LNG plant has a storage capacity of 1,660 MDTH and peak-day sendout capacity of 291 MDTH, or 23% of peak-day supply. Gas Costs The average cost of gas purchased for firm customers was $3.12 per DTH in fiscal 1995, $3.55 per DTH in 1994 and $3.49 per DTH in 1993. Gas prices have been competitive with costs of most other energy sources, including alternate grades of fuel oil, although gas continues to be priced at some premium to No. 2 grade fuel oil. Gas costs reflect the results of the Company's hedging program. Regulation and Rate Matters Utility retail sales, which include sales of gas, transportation and balancing services by the Company, are made primarily under rate schedules and tariffs filed with and subject to the jurisdiction of the PSC. In general, the schedules provide for block rates that result in reductions in the unit price as use increases. They contain gas cost adjustment provisions that permit the Company to pass on to firm customers increases and decreases in the cost of gas from levels included in base rates. Revenue requirements for ratemaking purposes are established on the basis of firm sales projections assuming normal weather. Net revenues (revenues less gas costs) from tariff sales for gas, transportation and balancing services on an interruptible basis, as well as from off-system gas sales, are refunded to firm customers, subject to sharing provisions. Service is provided to certain large-volume customers, principally in the multi-family and commercial markets, under a temperature controlled (TC) rate that is competitive with the price of alternate grades of fuel oil. These large-volume customers use gas for space and water heating under the TC rate, except that when the temperature falls below a specified level, then oil, the alternate fuel, is used. Service is provided to the small apartment house market under a similar rate. Further, the PSC has authorized more pricing flexibility to the Company in the TC market. The Company offers negotiated "customized" rates to large-volume customers both within and outside its service territory. In some instances, the Company uses financial instruments to protect margins on these sales. ( See Part II, Item 8., "Financial Statements and Supplementary Data," Note 5B., "Derivative Financial Instruments.") The Company's tariff contains a Weather Normalization Adjustment that permits recovery from firm heating customers of firm net revenue shortfalls due to warmer-than-normal weather during a heating season. In a colder-than-normal heating season, the Company is required to refund to these customers net revenues from firm gas sales in excess of those which would have been realized under normal weather conditions. Effective October 1, 1994, the adjustment was modified to exclude weather variations (positive or negative) of less than 2.2% from normal during each billing cycle. For information regarding the status of rate settlements and other regulatory proceedings, see Part II, Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations - 'Rate and Regulatory Matters'." Also, for additional information on the effects of rate regulation see Part II, Item 8., "Financial Statements and Supplementary Data, 'Summary of Significant Accounting Policies - Regulatory Assets'." Competition As discussed above, changes in Federal and more recently State regulatory policies have resulted in increased competition in interstate and local gas markets. The Company has responded to these changes by increasing sales to off-system customers, primarily through its New York Market Hub, while maintaining its position in local markets for which new tariffs have been filed with the PSC in accordance with its restructuring proceeding. (See Part II, Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations - 'Rate and Regulatory Matters - Restructuring Proceeding'.") In local markets, gas also competes with fuel oil. The Company has expanded existing markets and is developing new ones to increase gas sales. In the residential heating market, gas is sold in competition with No. 2 grade fuel oil. During the year, gas at the burner tip was generally competitive with alternate grades of fuel oil, although it was priced at some premium to No. 2 grade fuel oil. Conversions from oil to gas heat continued during fiscal 1995. Approximately 77% of one- and two-family homes in the Company's service area now use gas for space heating. The Company's share of the multi-family market is approximately 45%. In this market, gas service under the TC rate is competitively priced with alternate grades of fuel oil. As discussed under "Regulation and Rate Matters" above, the PSC has authorized more pricing flexibility to the Company in this market. In the commercial and industrial markets, the Company offers special area development and business incentive gas rates to businesses that move to or expand operations in designated areas in the Company's territory. The Company believes that there are promising new markets for use of natural gas as a vehicle fuel as well as in cogeneration, air conditioning and refrigeration applications. The Company continues to be committed to obtaining greater operational efficiencies, through workforce reductions achieved through early retirement programs and normal attrition, as well as tax reduction efforts, advanced construction methods and use of state-of-the-art computer technology. The Company is unique among investor-owned utilities in that all of its outstanding long-term debt used to finance utility gas facilities is tax-exempt. Research and Development In fiscal 1995, the Company spent $11.9 million on research and development (R&D) programs. Of this amount, $2.1 million went to support programs of the Gas Research Institute. The Company also provided $2.7 million to other research associations, including the New York State Energy Research and Development Authority (NYSERDA) and the New York Gas Group. The balance of $7.1 million was devoted primarily to the Company's internal R&D programs relating to efficient gas utilization and operations technologies. These programs include development and demonstration of gas heat pumps, fuel cells, new technologies to reduce meter reading costs and vehicles powered by compressed natural gas, as well as refueling stations. In addition, the Company made significant efforts to develop innovative operation systems which reduce utility costs. These new systems deploy state-of-the-art hardware such as pen-based hand- held computers and object-oriented software for precise risk analysis and modeling. Employees The Company and its subsidiaries employed 3,378 people at September 30, 1995, compared to 3,506 at September 30, 1994. The decrease reflects normal workforce reductions and the effect of early retirement programs. In November 1995, a new labor agreement was ratified by the membership of Local 101 of the Transport Workers Union, which represents approximately 1,900 employees. The agreement provides for total wage increases of approximately 9.3% over its three-year term. The agreement also provides certain productivity savings and a gainsharing incentive tied to attainment of certain corporate goals. A similar agreement applicable to 200 employees represented by Local 3 of the International Brotherhood of Electrical Workers was ratified in August 1995. Environmental Matters For information regarding environmental matters affecting the Company, see Part II, Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations - 'Environmental Matters'," and Part II, Item 8., "Financial Statements and Supplementary Data," Note 7., "Environmental Matters." Item 2. Properties In fiscal 1995, consolidated capital expenditures were $214.0 million, of which $108.7 million was primarily for utility property additions and $105.3 million was for subsidiaries. Consolidated capital expenditures are estimated to be approximately $195 million for each of fiscal years 1996 and 1997. The Company holds franchises to lay gas mains in the streets, highways and public places in the Boroughs of Brooklyn and Staten Island, and the former Second and Fourth Wards of the Borough of Queens. The Company has consents and permits which, with immaterial exceptions, give it the right to carry on its utility operations, substantially as now carried on, in the territory served. The Company's franchises are unlimited in duration, except that a franchise to transmit and distribute gas in the former Fifth Ward of the Borough of Staten Island expires in 2006. Gas sales revenues in the former Fifth Ward are approximately 2.4% of the total gas sales revenues of the Company. As of September 30, 1995, the Company's distribution pipeline system consisted of approximately 2,005 miles of cast iron main, 1,680 miles of steel main and 255 miles of mains with plastic inserts, with requisite accessory compressor and regulating stations, and one gas storage holder having a capacity of 15 MDTH. The distribution system for the most part is located under public streets. The Company owns and operates an LNG plant, located at its Greenpoint Energy Center in Brooklyn, to liquefy and store gas during the summer months for vaporization and use during the winter months. This plant has a storage capacity of 1,660 MDTH of natural gas in liquid form and has a vaporization capacity of 291 MDTH per day. The Company leases its corporate headquarters at One MetroTech Center in downtown Brooklyn. The lease agreement has a remaining term of 16 years and renewal options. The Company owns or leases certain other buildings and facilities for use in the conduct of its business. The Company's gross lease payments are approximately $14.3 million per year. Principal consolidated properties of subsidiaries and their affiliates include gas and oil leasehold interests, producing wells and related equipment and structures. For information required by this item concerning the gas and oil exploration, development and producing activities of the Company's subsidiaries, see Part II, Item 8., "Financial Statements and Supplementary Data," Note 8., "Supplemental Gas and Oil Disclosures." Item 3. Legal Proceedings For information regarding governmental investigations of alleged violations involving the Iroquois project, see Part II, Item 8., "Financial Statements and Supplementary Data," Note 6., "Investment in Iroquois Pipeline." For information regarding environmental matters affecting the Company, see Part II, Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations - Environmental Matters," and Part II, Item 8., "Financial Statements and Supplementary Data," Note 7., "Environmental Matters." Item 4. Submission of Matters to a Vote of Security Holders There was no matter submitted to a vote of security holders during the fourth quarter of the fiscal year covered by this report through solicitation of proxies or otherwise. Part II Item 5. Market for the Registrant's Common Stock and Related Security Holder Matters The following is information regarding the Company's common stock. For additional information required by this item, see Part II, Item 6., "Selected Financial Data" and Part II, Item 8., "Financial Statements and Supplementary Data," Note 4., "Capitalization." Stock Listings The Company's common stock and preferred stock are traded on the New York Stock Exchange under the trading symbol BU. Daily stock reports are carried by most major newspapers under the headings BrklyUG for the common stock and BkUG for the preferred stock. Dividends Quarterly dividends on common stock are payable on the first of February, May, August and November; preferred dividends are payable on the first of March, June, September and December. All dividends paid by the Company are taxable as ordinary income. Annual Meeting The next annual meeting of shareholders will be held at the Company's General Office at 10:00 a.m. on Thursday, February 1, 1996. Transfer Agent and Registrar of Stock First Chicago Trust Company of New York P.O. Box 2500 Jersey City, N.J. 07303-2500 (201)324-0498 Independent Public Accountants Arthur Andersen LLP 1345 Avenue of the Americas New York, NY 10105 (212)708-4000 SUPPLEMENTARY INFORMATION (UNAUDITED) QUARTERLY INFORMATION SUMMARY OF QUARTERLY INFORMATION The following is a table of financial data for each quarter of fiscal 1995 and 1994. The Company's business is influenced by seasonal weather conditions and the timing of approved base utility tariff rate changes. The effect on utility earnings of variations in revenues caused by abnormal weather is largely mitigated by operation of a weather normalization adjustment contained in the Company's tariff.
First Second Third Fourth Quarter Quarter Quarter Quarter (Thousands of Dollars Except Per Share Data) 1995 Operating revenues 358,348 481,615 217,696 158,625 Operating income(loss) 55,153 85,902 6,326 (8,871) Income (loss) applicable to common stock 42,753 73,555 (6,188) (18,622) Per common share: Earnings (loss) (a) 0.90 1.53 (0.13) (0.38) Dividends declared 0.3475 0.3475 0.3475 0.3475 1994 Operating revenues 371,478 548,970 240,661 177,521 Operating income(loss) 53,125 83,561 4,085 (6,467) Income (loss) applicable to common stock 42,073 73,465 (7,690) (20,815) Per common share: Earnings (loss) (a) 0.90 1.57 (0.16) (0.44) Dividends declared 0.3375 0.3375 0.3375 0.3375 (a) Quarterly earnings per share are based on the average number of shares outstanding during the quarter. Because of the increasing number of common shares outstanding in each quarter, the sum of quarterly earnings per share does not equal earnings per share for the year.
SUMMARY OF QUARTERLY STOCK INFORMATION
First Second Third Fourth Quarter Quarter Quarter Quarter 1995 High 25 3/8 24 3/4 26 3/8 26 3/8 Low 21 1/2 22 23 3/4 23 1/4 Close 22 1/4 24 1/8 26 1/4 24 5/8 Shares Traded (000) 2,695 3,977 2,543 3,219 1994 High 27 1/2 28 7/8 25 1/8 25 3/4 Low 24 7/8 23 22 1/8 23 1/2 Close 27 3/8 23 3/4 24 3/8 24 7/8 Shares Traded (000) 3,978 2,542 2,206 1,931
Item 6. Selected Financial Data
For the Year Ended September 30, 1995 1994 1993 1992 1991 (Thousands of Dollars Except Per Share Data) Income Summary Operating revenues Utility sales $1,152,331 $1,279,638 $1,145,315 $1,038,061 $951,711 Gas production and other 63,953 58,992 60,189 36,799 25,550 Total operating revenues 1,216,284 1,338,630 1,205,504 1,074,860 977,261 Operating expenses Cost of gas 446,559 560,657 466,573 402,137 373,048 Operation and maintenance 381,194 381,696 363,792 333,984 302,171 Depreciation and depletion 72,020 69,611 64,779 73,930 42,644 General taxes 134,718 150,743 144,827 135,549 136,245 Federal income tax 43,283 41,619 42,433 30,812 27,017 Operating income 138,510 134,304 123,100 98,448 96,136 Income (loss) from energy services investments 9,458 5,689 1,150 (1,041) 136 Gain on sale of investment in Canadian gas company - - 20,462 - - Write-off of investment in propane company - - (17,617) - - Other, net (4,309) (2,338) (3,379) 2,935 2,949 Federal income tax benefit 1,243 921 950 1,593 3,050 Interest charges 53,067 51,192 48,103 42,062 40,462 Net income 91,835 87,384 76,563 59,873 61,809 Dividends on preferred stock 337 351 364 2,078 3,847 Income available for common stock $91,498 $87,033 $76,199 $57,795 $57,962 Financial Summary Common stock information Per share Earnings ($) 1.90 1.85 1.73 1.35 1.45 Cash dividends declared ($) 1.39 1.35 1.32 1.29 1.27 Book value, year-end ($) 16.94 16.27 15.55 14.56 14.37 Market value, year-end ($) 24 5/8 24 7/8 25 3/4 22 3/8 20 5/8 Average shares outstanding (000) 48,211 46,980 44,042 42,882 39,894 Shareholders 33,669 35,233 30,925 31,367 30,749 Daily average shares traded 49,100 42,100 33,100 26,900 30,500 Capital expenditures ($) 214,006 199,572 204,514 173,467 147,745 Total assets ($) 2,116,922 2,029,074 1,897,847 1,748,027 1,717,493 Common equity ($) 826,290 774,236 721,076 632,254 607,573 Preferred stock, redeemable ($) 6,900 7,200 7,500 7,800 44,467 Long-term debt ($) 720,569 701,377 689,300 682,031 685,413 Total capitalization ($) 1,553,759 1,482,813 1,417,876 1,322,085 1,337,453 Earnings to fixed charges (times) 3.17 3.21 3.19 2.86 2.95 Utility Operating Statistics Gas data (MDTH) Firm sales 123,356 133,513 128,972 122,476 108,694 Other gas and transportation 49,910 42,392 25,032 23,706 15,963 Maximum daily capacity, year-end 1,256 1,256 1,258 1,199 1,179 Maximum daily sendout 963 1,022 915 904 837 Total active meters (000) 1,125 1,122 1,119 1,117 1,111 Heating customers (000) 454 446 441 436 428 Degree days 4,240 4,974 4,802 4,659 3,971 Colder (Warmer) than normal (%) (11.2) 3.1 - (4.0) (19.0)
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Earnings and Dividends In fiscal 1995, consolidated income available for common stock was $91.5 million, or $1.90 per share, compared to $87.0 million, or $1.85 per share, in 1994, and $76.2 million, or $1.73 per share, in 1993. This was the third consecutive year of record earnings. Consolidated earnings, including income from equity investments, for the last three fiscal years are summarized below:
__________________________________________________________________________ 1995 1994 1993 __________________________________________________________________________ (Thousands of Dollars) Income Available for Common Stock Utility $78,677 $76,665 $69,083 _________________________________________________________________________ Gas exploration and production Operations United States 7,849 5,707 2,707 Canadian (includes gas processing) 227 - 2,739 Gain on sale of Canadian investment - - 12,500 __________________________________________________________________________ 8,076 5,707 17,946 _________________________________________________________________________ Energy services Pipeline and other 2,075 3,358 2,792 Cogeneration 2,670 1,303 907 Propane Operations - - ( 3,078) Write-off - - (11,451) __________________________________________________________________________ 4,745 4,661 (10,830) __________________________________________________________________________ Consolidated $91,498 $87,033 $76,199 __________________________________________________________________________
In 1995, utility operations provided an equity return of 12.3%. The return, which included incentives authorized by the New York State Public Service Commission (PSC), was higher than the allowed rate of 11.0%. The Company has earned at or above its allowed return on utility common equity in 16 of the last 17 years. In the last three years, income available for common stock from utility operations has benefited from additions of new firm gas heating customers, principally as a result of customer conversions from oil to gas for space heating in homes and buildings, rate relief and earnings incentives provided under rate stipulations (see "Rate and Regulatory Matters"). In 1995, such incentive-based earnings were related largely to higher margins on sales to large-volume customers and attaining a 95% customer satisfaction rating in benchmarks used by the PSC. The effect on utility revenues of variations in weather largely was offset by the weather normalization adjustment included in the Company's tariff. However, effective October 1, 1994, the adjustment was modified to exclude weather variations (positive or negative) of less than 2.2% from normal. This modification adversely affected utility net revenues by approximately $4.9 million in 1995. Sales growth normalized for weather slackened from levels attained in recent years. Utility operating margins have improved due to cost reduction efforts. In 1995, earnings from gas exploration and production increased despite lower market prices. In 1994 and 1993, earnings from gas exploration and production operations increased primarily due to higher U.S. production. In 1993, earnings also included an after tax gain of $12.5 million on the sale of a subsidiary's investment in a Canadian gas exploration and production company. Canadian gas processing operations began anew in 1995. Earnings from investments in energy services are attributable to a number of factors. Earnings from pipeline and other in all periods reflect higher throughput on the Iroquois Gas Transmission System, L.P., in which a Company subsidiary holds an 11.4% interest. In 1995, earnings were reduced by a provision for the subsidiary's proportionate share of estimated costs of legal matters involving the Iroquois project. Higher earnings from cogeneration investments reflect equity income from gas-fired plants at John F. Kennedy International Airport and the campus of the State University of New York at Stony Brook, both of which were completed in 1995, and the acquisition in 1994 of an interest in a previously completed cogeneration plant located in Lockport, New York. The consolidated rate of return on average common equity was 10.9% in 1995, compared to 11.0% in 1994 and 10.9% in 1993. In December 1994, the Board of Directors authorized an increase in the annual dividend on common stock to $1.39 per share from $1.35 per share. This increase became effective on February 1, 1995, when the quarterly dividend was raised to 34 3/4 cents per share from 33 3/4 cents per share. Common dividends have been increased in 19 consecutive years and paid continuously for 47 years.
Sales, Gas Costs and Net Revenues Firm utility gas sales volume in fiscal 1995 was 123,356 MDTH compared to 133,513 MDTH in 1994 and 128,972 MDTH in 1993. Measured by annual degree days, weather was 11.2% warmer than normal in 1995, 3.1% colder than normal in 1994 and normal in 1993. Sales growth in all markets resulted primarily from conversions to natural gas from oil for space heating, especially by large apartment buildings. In 1995, the growth in firm sales normalized for weather fell short of the rate experienced in recent years, reflecting reduced consumption per customer related to the extremely warm weather. _________________________________________________________________ 1995 1994 1993 _________________________________________________________________ (Thousands of Dollars) Utility sales $ 1,152,331 $ 1,279,638 $ 1,145,315 Cost of gas (446,559) (560,657) (466,573) _________________________________________________________________ Net revenues $ 705,772 $ 718,981 $ 678,742 _________________________________________________________________ Gas production and other $ 63,953 $ 58,992 $ 60,189 _________________________________________________________________
In 1995, lower utility sales primarily reflect lower billings for gas costs due to warm weather. Further, utility sales (and net revenues) reflect reductions of approximately $13.2 million related to sharing of margins on sales to certain large-volume customers. As previously mentioned, modification of the weather normalization adjustment caused a reduction in utility net revenues of $4.9 million in 1995. For additional information regarding utility sales and net revenues in the last three years, see "Rate and Regulatory Matters." During the year, gas at the burner tip was competitive with alternative grades of fuel oil, although it continued to be priced at some premium to No. 2 grade fuel oil. Residential heating sales in markets where the competing fuel is No. 2 grade fuel oil and sales to other small-volume customers were approximately 75% of firm sales volume in 1995. Demand in these markets is less sensitive to periodic differences between gas and oil prices. In large-volume heating markets, gas service is provided under rates that are set to compete with prices of alternative fuel, including No. 6 grade heating oil. There is substantial sales potential in these markets, which include large apartment houses, government buildings and schools. Moreover, a significant market for off-system sales has developed as a result of Federal Energy Regulatory Commission (FERC) initiatives. In 1995, other gas and transportation sales to off-system and interruptible customers amounted to 49,910 MDTH. In addition, capacity release transactions amounted to approximately 32,170 MDTH. These revenue producing transactions reflect optimal use of available pipeline capacity and the Company's New York-based market hub. The cost of gas, $446.6 million in 1995, was $114.1 million or 20.4% lower than in 1994. The lower cost reflects lower heating sales due to warmer weather and lower average gas prices. The cost of gas for firm customers was $3.12 per DTH (one DTH equals 10 therms) in 1995, compared to $3.55 per DTH in 1994 and $3.49 per DTH in 1993. The Company and its gas exploration and production subsidiary employ derivative financial instruments, natural gas futures and swaps, for the purpose of managing commodity price risk. In connection with utility operations, the Company primarily uses derivative financial instruments to fix margins on sales to large- volume customers to which gas is sold at a price indexed to the prevailing price of oil, their alternate fuel. Derivative financial instruments are used by the Company's gas exploration and production subsidiary to manage the risk associated with fluctuations in the price received for natural gas production. Hedging strategies are managed independently. (See Part II, Item 8., "Financial Statements and Supplementary Data," Note 5B., "Derivative Financial Instruments," for additional information.) The increase in revenues from gas production and other in 1995 is due to the acquisition of a gas processing plant located in British Columbia, Canada by the Company's Canadian affiliate. Revenues from U.S. operations were down as a result of lower production and pricing due to reduced demand related to weather. In 1995, gas production was approximately 22.7 billion cubic feet (BCF), or 0.7 BCF below last year's production. Wellhead prices prevailing in 1995 were lower than in 1994. However, hedging helped reduce the adverse effects of lower wellhead prices. In 1995, wellhead prices averaged approximately $1.47 per MCF compared to $1.97 per MCF last year. The effective price (average wellhead price received for production including realized hedging gains and losses) was $1.77 per MCF in 1995 compared to $1.84 per MCF in 1994. The decrease in revenues from gas production and other in 1994 is due to the sale of Canadian gas exploration and production operations at the end of 1993 to realize the profit and value embodied in the investment. (See Part II, Item 8., "Financial Statements and Supplementary Data," Note 8., "Supplemental Gas and Oil Disclosures," for additional information.) Expenses, Other Income and Preferred Dividends The decrease in operation expense in 1995 reflects the effects of warm weather compared to last year and various cost reduction efforts. In 1994, severe winter weather caused higher utility gas distribution operation expense. The benefit of ongoing cost reduction programs substantially outweighed the adverse effects of generally higher labor and material costs. Moreover, consolidated operation expense in 1995 included approximately $9.0 million of costs related to Canadian gas processing operations, which commenced anew in the second half of the year. Maintenance expense includes costs related to city and state construction projects. The increase in depreciation and depletion expense in 1995 reflects higher depreciation charges related to utility property additions. The effect of higher utility depreciation expense more than offset lower depletion expense due to reduced gas production of subsidiaries. The increase in consolidated expense in 1994 reflects higher utility depreciation expense as well as higher depletion charges related to increased gas production in that year. General taxes principally include state and city taxes on utility revenues and property. The applicable property base generally has increased, although the Company has been able to realize significant savings by the aggressive pursuit of reductions in property value assessments. Taxes based on revenues reflect the variations in utility revenues each year. Federal income tax expense reflects changes in pre-tax income. Also, the Company adopted Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS-109) in 1994. Adoption of SFAS-109 had no effect on net income. (See Part II, Item 8., "Financial Statements and Supplementary Data," Note 1., "Federal Income Tax.") Interest charges on long-term debt in each of the last three fiscal years generally reflect higher average subsidiary borrowings. Other interest expense primarily reflects accruals of carrying charges related to regulatory settlement items. The increase in other income in 1995 primarily reflects the increase in earnings from energy services investments as discussed above. Dividends on preferred stock reflect reductions in the level of preferred stock outstanding due to sinking fund redemptions. Capital Expenditures Consolidated capital expenditures were $214.0 million in fiscal 1995, $199.6 million in fiscal 1994 and $204.5 million in 1993. Capital expenditures related to utility operations were $108.7 million in 1995, $103.8 million in 1994 and $110.8 million in 1993. Utility expenditures in all years principally were for the renewal and replacement of mains and services. Plant additions to serve new customers and develop new markets were $28.0 million in 1995, $28.8 million in 1994 and $24.9 million in 1993. Capital expenditures related to gas exploration, production and processing activities were $83.0 million in 1995, $71.3 million in 1994 and $66.3 million in 1993. The 1995 amount reflects increased off-shore development activities and the purchase of a Canadian gas processing plant. Net proved gas reserves at September 30, 1995 were approximately 202 BCF. These reserves are located off-shore in the Gulf of Mexico and on-shore in the Arkoma Basin, East Texas and West Virginia. Capital expenditures related to energy services investments were $22.3 million in 1995, $24.5 million in 1994 and $27.4 million in 1993. Expenditures in all years were primarily related to the construction of the John F. Kennedy International Airport cogeneration project and, in 1995, include $5.6 million related to the Stony Brook cogeneration plant. In 1994, capital expenditures also include $10.9 million related to the acquisition of an interest in a previously completed cogeneration plant located in Lockport, New York. Consolidated capital expenditures for fiscal years 1996 and 1997 are estimated to be approximately $195 million in each year, including $85 million per year related to non-utility activities. The level of such expenditures is reviewed periodically and can be affected by timing, scope and changes in investment opportunities. The PSC has authorized the Company to invest up to 20% of its consolidated capitalization in non-utility energy-related businesses. This authorization is based on the Company's cash investments less dividends received. At September 30, 1995, the total investment in non-utility subsidiaries computed on this basis was approximately 14% of capitalization. Financing Cash provided by operating activities continues to be strong and is the principal source for financing capital expenditures. In 1995, operating cash flow was enhanced substantially by the timing of weather normalization and gas cost recoveries, and reflects higher margins received from sales to large-volume customers and market hub activities. The Company issued 1,800,000 new shares of common stock on October 6, 1993, providing net proceeds of $44.9 million. Proceeds from common stock issued through employee and shareholder stock purchase plans have provided the Company approximately $28.0 million in 1995, $29.8 million in 1994 and $27 million in 1993. In 1993, the Company converted $55 million of Series C Variable Rate Gas Facilities Revenue Bonds to a fixed rate of 5.60% and $50 million of Series D Variable Rate Gas Facilities Revenue Bonds to a fixed rate equivalent of 5.64%. In addition, $75 million of 9 1/8% Gas Facilities Revenue Bonds was refunded in 1993. The interest rate on the refunding bonds, which mature in 2020, is 6.37%. Increased subsidiary borrowings included in long- term debt provided an additional $19.2 million to finance consolidated capital expenditures. At September 30, 1995, the consolidated annualized cost of long-term debt was 7.1%. The Company's 9% and 8.75% Gas Facilities Revenue Bonds became callable on May 15, 1995 and July 1, 1995, respectively, at optional redemption prices of $102. The Company is evaluating the possibility of refunding these bond issues. Financial Flexibility and Liquidity At September 30, 1995, the Company had cash and temporary cash investments of $40.5 million and available bank lines of credit of $75 million, which lines are available to secure the issuance of commercial paper. The lines of credit can be increased to $150 million by December 1995. Related borrowings primarily are used to finance seasonal working capital requirements, which in recent years have not been significant. At September 30, 1995, there were no borrowings outstanding. In addition, subsidiaries have lines of credit totaling $84 million, which for the most part support borrowings under revolving loan agreements. At September 30, 1995, the common equity component of the Company's capitalization was 53.2%. Fixed charge coverage ratios were 3.17 times in fiscal 1995, 3.21 times in 1994 and 3.19 times in 1993. Rate and Regulatory Matters Rate Settlement Plan In October 1994, the PSC approved a new three-year rate settlement agreement which provided for no base rate increase in fiscal 1995; however, the Company was permitted to amortize to income approximately $1.3 million of deferred credits. Previously, the PSC had approved $31.3 million of additional revenues for fiscal 1994, including $3.0 million of deferred credits, and $31.5 million of additional revenues for fiscal 1993, including $10.9 million of deferred credits. In addition to earnings sharing provisions, the plan provides new incentives, more flexible pricing in large-volume competitive markets, and rate design modifications to improve the Company's competitive position. The Company is permitted to retain 100% of any earnings from discrete incentives (up to 100 basis points on utility equity.) With respect to earnings sharing provisions, the Company will retain 75% of the first 100 basis points of earnings in excess of the allowed return on utility equity unrelated to discrete incentives, and 50% of any additional earnings above that level. In addition, the Company will retain a portion of margins above a specified level of sales to certain large-volume customers. In September 1995, the PSC approved the Company's second stage rate filing covering fiscal 1996. The approval provides for no base rate increase; however, it permits the amortization of $7.5 million in deferred credits. The rate of return on utility common equity will be 10.65% for fiscal 1996, reflecting generally lower prevailing capital costs, and the incentive provisions currently in place would continue and remain available to permit earned rates of return to rise above the allowed level. These revisions became effective on October 1, 1995. Additionally, base rate increases, if any, in the third year of the agreement would continue to be limited to inflation and partially would be offset by the use of additional available credits. Restructuring Proceeding In December 1994, the PSC issued its order in the gas industry restructuring case. The proceeding was instituted by the PSC in response to the restructuring of interstate pipeline services by FERC Order 636, which took effect in November 1993. The PSC order addresses incentives and margin-sharing issues in a manner that is generally consistent with the Company's current rate settlement plan and provides utilities broad discretion to employ market-based pricing (subject to caps) for services offered to large-volume, or non-core, customers with dual-fuel capability. The order allows the Company to continue to offer customers a complete array of bundled sales services as well as gas-supply pricing flexibility generally comparable to that offered by unregulated competitors to large-volume customers. Further, the Company will offer core customers, reliant solely on gas as a heating or cooling fuel, unbundled sales and transportation, including access to available pipeline transportation and storage capacity. The order reduces the minimum transportation service volume requirement for customers, while encouraging the ultimate elimination of such a requirement. Lastly, the order initiated a new proceeding currently underway to evaluate gas purchasing practices and revised gas cost recovery mechanisms and invited proposals for providing service to small-volume customers aggregated into gas purchasing groups. The PSC also has now lifted its orders prohibiting any Company gas marketing subsidiary from operating within the Company's territory. The Company is fully prepared to meet the requirements of the PSC order. It has filed tariffs applicable to both core and non- core markets in compliance with the PSC order, and has proposed a pilot incentive gas cost recovery mechanism, which was approved by the PSC in September 1995. The mechanism became effective as of September 1, 1995, and provides for the Company to share the benefits of, or absorb a portion of the costs related to, variations in its weighted average cost of gas as compared with a market-based index. Under the terms of the incentive mechanism, the maximum award or penalty that could be realized is $2.0 million in gas cost recoveries. Holding Company Petition and Price Cap Proposal The Company filed a petition with the PSC to organize its utility operations and those of its subsidiaries within a holding company. This form of corporate organization would provide the Company with the flexibility to take advantage of timely investment and market-entry opportunities and allow the Company to compete more effectively against other energy providers. The Company plans to expand gas marketing and energy management services to large- volume customers, potentially through new subsidiaries to be incorporated separately and owned by the holding company. In conjunction with the formation of the holding company, the Company has proposed to institute a price cap plan for gas services provided to firm tariff customers and to modify the ratemaking applicable to margins for large-volume, non-core transactions. Essentially, any rate increase applicable to core customers would be limited to general price inflation. Further, a specified level of margins on services to non-core customers would be imputed and reflected in overall revenue requirements at the outset of the price cap period. Thus, the Company would realize any benefit or loss associated with changes in such sales margins from the level initially fixed. Environmental Matters The Company is subject to various Federal, state and local laws and regulatory programs related to the environment. These environmental laws govern both the normal, ongoing operations of the Company as well as the cleanup of historically contaminated properties. Ongoing environmental compliance activities, which historically have not been material, are integrated with the Company's regular operations and maintenance activities. As of September 30, 1995, the Company had an accrued liability of $29.3 million and a related unamortized regulatory asset of $33.2 million representing costs associated with investigation and remediation at former manufactured gas plant sites. (See Part II, Item 8 ., "Financial Statements and Supplementary Data," Note 7., "Environmental Matters.") Inflation In recent years, the impact of inflation has diminished. Purchased gas costs are passed on to customers through the Gas Adjustment Clause in the Company's tariff. Gas generally remains competitively priced with alternative fuels. Recovery of the cost of utility property is based on historical cost depreciation charges that are included in utility rates. Such charges are less than current costs or inflation-adjusted costs. However, the Company believes its utility rates generally provide an opportunity to earn a fair return on shareholder investment reflective of its cost of capital and, therefore, maintain access to capital markets in order to finance property additions and replacements. Item 8. Financial Statements and Supplementary Data Financial Statement Responsibility The Consolidated Financial Statements of the Company and its subsidiaries were prepared by management in conformity with generally accepted accounting principles. The Company's system of internal controls is designed to provide reasonable assurance that assets are safeguarded and that transactions are executed in accordance with management's authorizations and recorded to permit preparation of financial statements that present fairly the financial position and operating results of the Company. The Company's internal auditors evaluate and test the system of internal controls. The Company's Vice President and General Auditor reports directly to the Audit Committee of the Board of Directors, which is composed solely of outside directors. The Audit Committee meets periodically with management, the Vice President and General Auditor and Arthur Andersen LLP to review and discuss internal accounting controls, audit results, accounting principles and practices and financial reporting matters. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To The Brooklyn Union Gas Company: We have audited the accompanying Consolidated Balance Sheet and Consolidated Statement of Capitalization of The Brooklyn Union Gas Company (a New York corporation) and subsidiaries as of September 30, 1995 and 1994, and the related Consolidated Statements of Income, Retained Earnings 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. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position and capitalization of The Brooklyn Union Gas Company 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. As discussed in Notes 1 and 2 to the Consolidated Financial Statements, the Company changed its method of accounting for income taxes and postretirement benefits effective as of October 1, 1993. Our audits were made for the purpose of forming an opinion on the basic consolidated financial statements taken as a whole. The schedule listed in Item 14 is the responsibility of the Company's management and is presented for the purpose of complying with the Securities and Exchange Commission's rules and is not part of the basic consolidated financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic consolidated 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 consolidated financial statements taken as a whole. ARTHUR ANDERSEN LLP October 23, 1995 New York, New York Summary of Significant Accounting Policies Principles of Consolidation The Consolidated Financial Statements reflect the accounts of the Company and its subsidiaries. All significant intercompany transactions are eliminated. All other adjustments are of a normal, recurring nature. Utility Gas Property - Depreciation and Maintenance Utility gas property is stated at original cost of construction, which includes allocations of overheads and taxes and an allowance for funds used during construction. Depreciation is provided on a straight-line basis in amounts equivalent to composite rates on average depreciable property of 3.4% in 1995, 3.3% in 1994 and 3.2% in 1993. The cost of property retired, plus the cost of removal less salvage, is charged to accumulated depreciation. The cost of repair and minor replacement and renewal of property is charged to maintenance expense. Gas Exploration and Production Property - Depletion and Depreciation The Company's gas exploration and production subsidiaries follow the full cost method of accounting. All productive and nonproductive costs identified with acquisition, exploration and development are capitalized. Provisions for depletion are based on the units-of-production method and, when necessary, include provisions related to the asset ceiling test limitations required by the regulations of the Securities and Exchange Commission. Costs of unevaluated gas and oil property are excluded from the amortization base until proved reserves are established or an impairment is determined. Provisions for depreciation of all other non-utility property are computed on a straight-line basis over useful lives of three to fifteen years. Investments in Energy Services Certain subsidiaries own as their principal assets investments in energy-related businesses that are accounted for under the equity method. Revenues Utility customers generally are billed bi-monthly on a cycle basis. Revenues include unbilled amounts related to the estimated gas usage that occurred from the last meter reading to the end of each month. Revenue requirements to establish utility rates are based on sales to firm customers. Changes in gas costs from amounts recovered in base tariff rates are included in billed firm revenues through the operation of a tariff provision, the Gas Adjustment Clause (GAC). Net revenues from tariff sales for gas and transportation service on an interruptible basis as well as from off-system gas sales and tariff gas balancing services and capacity release credits are refunded to firm customers subject to sharing provisions in the Company's tariff. The GAC provision requires an annual reconciliation of recoverable gas costs with GAC revenues. Any difference is deferred pending recovery from or refund to firm customers during a subsequent twelve-month period. Revenues also reflect provisions for refund to firm customers of margins in excess of tariff levels. The Company's tariff contains a weather normalization adjustment that provides for recovery from or refund to firm customers of shortfalls or excesses of firm net revenues during a heating season due to variations from normal weather, which is the basis for projecting base tariff revenue requirements. Effective October 1, 1994, the adjustment was modified to exclude weather variations (positive or negative) of less than 2.2% from normal during each billing cycle. As of April 1,1995, the Company's gas marketing activities are being accounted for under the equity method pursuant to a combination with Pennzoil Gas Marketing, Inc., a wholly-owned subsidiary of Pennzoil Corporation, through a limited liability corporation. Prior to that combination, gas sales by the Company's marketing subsidiary were classified in gas production and other revenue net of their related gas purchase and transportation costs. Hedge Accounting The Company and its gas exploration and production subsidiaries employ derivative financial instruments, natural gas futures and swaps, for the purpose of managing commodity price risk. Hedging strategies are managed on an individual company basis and meet the criteria for hedge accounting treatment under Statement of Financial Accounting Standards (SFAS) No. 80, "Accounting for Futures Contracts." Accordingly, gains and losses are recognized when the underlying transaction is completed, at which time these gains and losses are included in earnings as an offset to revenues or costs recognized when the gas is sold, purchased or transported in accordance with a hedged transaction, and are reflected as cash flows from operations in the accompanying Consolidated Statement of Cash Flows as margin positions are established and maintained. Further, in cases where the transaction results in the acquisition of an asset, deferred gains and losses are included as part of the carrying amount of the asset acquired. The Company regularly assesses the relationship between natural gas commodity prices in "cash" and futures markets. The correlation between prices in these markets has been well within a range generally deemed to be acceptable. If correlation fell out of an acceptable range, the Company would account for its financial instrument positions as trading activities. Federal Income Tax The Company adopted SFAS-109, "Accounting for Income Taxes" at the beginning of fiscal 1994. The Company recorded a regulatory asset for the net cumulative effect of having to provide deferred Federal income tax expense on all differences between the tax and book bases of assets and liabilities at the current tax rate. Prior to adoption of SFAS-109, pursuant to PSC policy, deferred taxes were not provided for certain construction costs incurred before fiscal 1988 and for bases differences related to differences between tax and book depreciation methods. An amortization of the regulatory asset is included in operation expense commencing in 1994, while amounts comparable to this amortization previously were included as part of Federal income tax expense. Investment tax credits, which were available prior to the Tax Reform Act of 1986, were deferred in operating expense and are amortized as a reduction of Federal income tax in other income over the estimated life of the related property. Regulatory Assets Regulatory assets arise from the allocation of costs and revenues to accounting periods for utility ratemaking purposes differently from bases generally applied by nonregulated companies. Regulatory assets are recognized in accordance with SFAS-71, "Accounting for Certain Types of Regulation." The Company had net regulatory assets as of September 30, 1995 and 1994 of $109,636,000 and $105,155,000, respectively. These amounts are included in Deferred Charges and Deferred Credits-Other in the Consolidated Balance Sheet at September 30, 1995 and 1994. In the event that it were no longer subject to the provisions of SFAS-71, the Company estimates that the write-off of these net regulatory assets could result in a charge to net income of approximately $69,000,000 which would be classified as an extraordinary item. SFAS-121, issued in March 1995 and effective for 1996, establishes accounting standards for the impairment of long-lived assets. This statement is not expected to have a material impact on the Company's financial condition or results of operations upon adoption. CONSOLIDATED STATEMENT OF INCOME
For the Year Ended September 30, 1995 1994 1993 (Thousands of Dollars) Operating Revenues Utility sales $ 1,152,331 $1,279,638 $1,145,315 Gas production and other 63,953 58,992 60,189 1,216,284 1,338,630 1,205,504 Operating Expenses Cost of gas 446,559 560,657 466,573 Operation 326,381 327,356 309,070 Maintenance 54,813 54,340 54,722 Depreciation and depletion 72,020 69,611 64,779 General taxes 134,718 150,743 144,827 Federal income tax (See Note 1) 43,283 41,619 42,433 Operating Income 138,510 134,304 123,100 Other Income Income from energy services investments 9,458 5,689 1,150 Gain on sale of investment in Canadian gas company - - 20,462 Write-off of investment in propane company - - (17,617) Other, net (4,309) (2,338) (3,379) Federal income tax benefit (See Note 1) 1,243 921 950 Income Before Interest Charges 144,902 138,576 124,666 Interest Charges Long-term debt 47,939 46,900 45,344 Other 5,128 4,292 2,759 Net Income 91,835 87,384 76,563 Dividends on Preferred Stock 337 351 364 Income Available for Common Stock $ 91,498 $ 87,033 $ 76,199 Earnings Per Share of Common Stock (Average shares outstanding of 48,211,220, 46,979,597 and 44,042,365, respectively) $ 1.90 $ 1.85 $ 1.73 CONSOLIDATED STATEMENT OF RETAINED EARNINGS For the Year Ended September 30, 1995 1994 1993 (Thousands of Dollars) Balance at Beginning of Year $ 279,466 $ 255,979 $ 238,867 Income Available for Common Stock 91,498 87,033 76,199 370,964 343,012 315,066 Less: Cash dividends declared ($1.39, $1.35 and $1.32 per common share, respectively) 67,229 63,652 58,914 Other adjustments 26 (106) 173 Balance at End of Year $ 303,709 $ 279,466 $ 255,979 The accompanying summary of significant accounting policies and notes are integral parts of these statements.
CONSOLIDATED BALANCE SHEET September 30, 1995 1994 (Thousands of Dollars) Assets Property Utility, at cost $ 1,690,193 $ 1,599,452 Accumulated depreciation (393,263) (354,925) Gas exploration and production, at cost 353,847 276,659 Accumulated depletion (138,136) (115,890) 1,512,641 1,405,296 Investments in Energy Services (See Note 6) 121,023 91,283 Current Assets Cash 15,992 11,610 Temporary cash investments 24,550 41,881 Accounts receivable 146,018 193,130 Allowance for uncollectible accounts (13,730) (14,963) Gas in storage, at average cost 88,810 96,076 Materials and supplies, at average cost 13,203 11,356 Prepaid gas costs 15,725 14,667 Other 19,856 31,441 310,424 385,198 Deferred Charges 172,834 147,297 $ 2,116,922 $ 2,029,074 Capitalization and Liabilities Capitalization (See accompanying statement and Note 4) Common equity $ 826,290 $ 774,236 Preferred stock, redeemable 6,900 7,200 Long-term debt 720,569 701,377 1,553,759 1,482,813 Current Liabilities Accounts payable 103,705 132,491 Dividends payable 17,536 16,609 Taxes accrued 3,635 15,213 Customer deposits 22,252 22,445 Customer budget plan credits 24,790 18,358 Interest accrued and other 39,438 45,807 211,356 250,923 Deferred Credits and Other Liabilities Federal income tax 247,882 230,316 Unamortized investment tax credits 20,948 22,000 Other 82,977 43,022 351,807 295,338 $ 2,116,922 $ 2,029,074 The accompanying summary of significant accounting policies and notes are integral parts of these statements.
CONSOLIDATED STATEMENT OF CAPITALIZATION
September 30, 1995 1994 (Thousands of Dollars) Common Equity Common stock, $.33 1/3 par value, authorized 70,000,000 shares; outstanding 48,788,320 and 47,590,015 shares, respectively, stated at $ 522,581 $ 494,770 Retained earnings (See accompanying statement) 303,709 279,466 826,290 774,236 Preferred Stock, Redeemable $100 par value, cumulative, authorized 900,000 shares 4.60% Series B, 72,000 and 75,000 shares outstanding, respectively 7,200 7,500 Less: Current sinking fund requirements 300 300 6,900 7,200 Long-term Debt Gas facilities revenue bonds (issued through New York State Energy Research and Development Authority) 9% Series 1985A due May 2015 98,500 98,500 8 3/4% Series 1985 due July 2015 55,000 55,000 6.368% Series 1993A and Series 1993B due April 2020 75,000 75,000 7 1/8% Series 1985 I due December 2020 62,500 62,500 7% Series 1985 II due December 2020 62,500 62,500 6.75% Series 1989A due February 2024 45,000 45,000 6.75% Series 1989B due February 2024 45,000 45,000 5.6% Series 1993C due June 2025 55,000 55,000 6.95% Series 1991A and Series 1991B due July 2026 100,000 100,000 5.635% Series 1993D-1 and Series 1993D-2 due July 2026 50,000 50,000 648,500 648,500 Subsidiary borrowings 72,069 52,877 720,569 701,377 $ 1,553,759 $ 1,482,813 The accompanying summary of significant accounting policies and notes are integral parts of these statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
For the Year Ended September 30, 1995 1994 1993 (Thousands of Dollars) CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 91,835 $ 87,384 $ 76,563 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and depletion 77,696 75,386 71,376 Deferred Federal income tax 11,037 10,897 7,599 Gain on sale of investment in Canadian gas company - - (20,462) Write-off of investment in propane company - - 17,617 Amortization of investment tax credit (1,052) (1,074) (1,074) Income from energy services investments (9,458) (5,689) (1,150) Dividends received from energy services investments 3,595 4,392 7,421 Allowance for equity funds used during construction (1,274) (2,076) (1,671) Change in accounts receivable, net 44,712 31,906 (61,097) Change in accounts payable (29,283) (34,121) 41,094 Gas inventory and prepayments 6,208 5,498 (31,063) Other 16,799 21,518 7,883 Cash provided by operating activities 210,815 194,021 113,036 CASH FLOWS FROM FINANCING ACTIVITIES Sale of common stock 27,974 29,828 71,866 Common stock proceeds receivable - 44,910 (44,910) Issuance of long-term debt 19,192 12,077 186,900 47,166 86,815 213,856 Repayments Preferred stock (300) (300) (300) Long-term debt - - (180,000) 46,866 86,515 33,556 Dividends paid (67,566) (64,003) (59,278) Other (34) 106 2,156 Cash (used in) provided by financing activities (20,734) 22,618 (23,566) CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (excluding allowance for equity funds used during construction) (212,732) (197,496) (202,843) Trust funds, utility construction - - 54,610 Proceeds from sale of investment in Canadian gas company - 11,691 30,027 Other 9,702 1,398 7,400 Cash used in investing activities (203,030) (184,407) (110,806) Change in Cash and Temporary Cash Investments (12,949) 32,232 (21,336) Cash and Temporary Cash Investments at Beginning of Year 53,491 21,259 42,595 Cash and Temporary Cash Investments at End of Year $ 40,542 $ 53,491 $ 21,259 Temporary cash investments are short-term marketable securities purchased with maturities of three months or less that are carried at cost which approximates their fair value. Supplemental disclosures of cash flows Income taxes $ 36,000 $ 36,900 $ 32,100 Interest $ 53,047 $ 50,872 $ 51,804 The accompanying summary of significant accounting policies and notes are integral parts of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. FEDERAL INCOME TAX Income tax expense (benefit) is reflected as follows in the Consolidated Statement of Income:
Year Ended September 30, 1995 1994 1993 (Thousands of Dollars) Operating Expenses Current $ 32,970 $ 39,466 $ 29,172 Deferred 10,313 2,153 13,261 43,283 41,619 42,433 Other Income Current (915) (8,591) 5,786 Deferred 724 8,744 (5,662) Amortization of investment tax credits (1,052) (1,074) (1,074) (1,243) (921) (950) Total Federal income tax $ 42,040 $ 40,698 $ 41,483
The Company adopted Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes" as of October 1, 1993. The adoption of SFAS-109 did not have a material effect on consolidated net income because the Company recorded a regulatory asset for the increase in accumulated deferred Federal income taxes not previously provided pursuant to regulatory orders. The components of the Company's net deferred income tax liability reflected as Deferred Credits and Other Liabilities - Federal income tax in the Consolidated Balance Sheet are as follows:
September 30, 1995 1994 (Thousands of Dollars) Deferred Credits and Other Liabilities - Federal income tax Property-related Utility $ 180,708 $ 176,486 Net tax regulatory asset 28,214 29,087 Gas production and other 49,402 30,841 Regulatory settlement items (9,261) (9,879) Gas cost and other (1,181) 3,781 Net deferred income tax liability $ 247,882 $ 230,316
As required by standards in effect prior to the adoption of SFAS- 109, the components of deferred tax expense related to the following items in 1993 are: property related - $9,782,000; rate settlement items - $(245,000); write-off of propane investment - $(7,720,000); gas costs and other - $5,781,000. The following is a reconciliation between reported income tax and tax computed at the statutory rate of 35% for 1995 and 1994 and 34.75% for 1993:
Year Ended September 30, 1995 1994 1993 (Thousands of Dollars) Computed at statutory rate $ 46,856 $ 44,828 $ 41,021 Adjustments related to: Utility property - - 1,179 Gas production and other (2,730) (1,303) 858 Nontaxable interest income (870) (556) (396) Amortization of investment tax credits (1,052) (1,074) (1,074) Other, net (164) (1,197) (105) Total Federal income tax $ 42,040 $ 40,698 $ 41,483 Effective income tax rate 31% 32% 35%
2. POSTRETIREMENT BENEFITS A. Pension: The Company has a noncontributory defined benefit pension plan covering substantially all employees. Benefits are based on years of service and compensation. The Company records expense in accordance with treatment established by the New York State Public Service Commission (PSC) applicable to its adoption of SFAS-87, "Employers' Accounting for Pensions," SFAS-88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits" and SFAS-106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." Accordingly, the Company's revenue requirement reflects the aggregate expenses related to pensions and other postretirement benefit obligations as determined under the applicable accounting standards. In December 1994, the Company completed a voluntary early retirement program for bargaining employees. In September 1994, the Company completed a similar voluntary early retirement program for management employees. As a result, the Company recorded special retirement charges in fiscal 1995 and 1994 of $5,416,000 and $8,465,000, respectively. The Company's funding policy for pensions is in accordance with requirements of Federal law and regulations. There were no pension contributions in 1995, 1994 and 1993.
The calculation of net periodic pension cost follows: Year Ended September 30, 1995 1994 1993 (Thousands of Dollars) Service cost, benefits earned during the year $ 11,533 $ 15,100 $ 14,244 Special retirement charge 5,416 8,465 - $ 16,949 $ 23,565 $ 14,244 Interest cost on projected benefit obligation 35,128 29,511 24,617 Return on plan assets (82,626) (12,430) (76,671) Net amortization and deferral 34,786 (32,798) 44,976 Total pension cost $ 4,237 $ 7,848 $ 7,166
The following table sets forth the plan's funded status and amounts recognized in the Company's Consolidated Balance Sheet. Plan assets principally are investment grade common stock and fixed income securities.
September 30, 1995 1994 (Thousands of Dollars) Actuarial present value of benefit obligations: Vested $(401,159) $(333,890) Accumulated $(423,434) $(353,172) Projected $(545,825) $(446,676) Plan assets at fair value $ 555,906 $ 497,280 Plan assets in excess of projected benefit obligation $ 10,081 $ 50,604 Unrecognized net loss (gain) from experience and changes in assumptions 10,880 (21,007) Unrecognized transition asset (32,566) (37,218) Accrued pension cost $ (11,605) $ (7,621) Assumptions: Obligation discount 7.00% 8.00% Asset return 7.50% 8.00% Average annual increase in compensation 5.50% 5.50%
B. Retiree Health Care and Life Insurance: The Company sponsors noncontributory defined benefit plans under which it provides certain health care and life insurance benefits for retired employees. The Company has been funding a portion of future benefits over employees' active service lives through a Voluntary Employee Beneficiary Association (VEBA) trust. Contributions to VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code. The Company's policy is to fund the cost of postretirement benefits to the extent rate recoveries are allowed for pension and postretirement benefit costs. The Company adopted SFAS-106 as of October 1, 1993. SFAS-106 requires that the costs of postretirement benefits other than pensions be accrued over employee service lives by the time of retirement eligibility. Its adoption did not have a material effect on consolidated net income because utility rates in fiscal 1994 reflected full recovery of annual SFAS-106 costs. The transition obligation upon adoption totaled $77.1 million, which is being amortized over twenty years. Prior to the adoption of SFAS- 106, such costs, including payments to retirees and trust fund contributions, amounted to $17,078,000 in 1993. Net periodic postretirement benefit cost included the following components:
Year Ended September 30, 1995 1994 (Thousands of Dollars) Service cost, benefits earned during the year $ 2,590 $ 2,826 Interest cost on accumulated postretirement benefit obligation 9,958 7,916 Return on plan assets (6,746) (340) Net amortization and deferral 6,752 141 Postretirement benefit cost $12,554 $10,543
The following table sets forth the plans' funded status, reconciled with amounts recognized in the Company's Consolidated Balance Sheet.
September 30, 1995 1994 (Thousands of Dollars) Actuarial present value of accumulated postretirement benefit obligation Retirees $ (87,022) $ (53,218) Fully eligible active plan participants (10,980) (17,106) Other active plan participants (56,157) (32,890) $(154,159) $(103,214) Plan assets at fair value, primarily stocks and bonds $ 72,638 $ 56,163 Accumulated postretirement benefit obligation in excess of plan assets $ (81,521) $ (47,051) Unrecognized net loss (gain) from past experience different from that assumed and from changes in assumptions 25,345 (16,875) Unrecognized transition obligation 67,781 71,547 Prepaid postretirement benefit cost $ 11,605 $ 7,621 Assumptions: Obligation discount 7.00% 8.00% Asset return 7.50% 8.00%
The measurement also assumes a health care cost trend rate of 9.0% in 1995, decreasing to 5.0% by the year 2007 and remaining at that level thereafter. A 1.0% increase in the health care cost trend rate would have the effect of increasing the accumulated postretirement benefit obligation as of September 30, 1995 and the net periodic SFAS-106 expense by approximately $15,830,000 and $1,752,000, respectively. The measurement for the year ended September 30, 1994 assumed a health care cost trend rate of 9.5% in 1994 decreasing to 5.0% by 2007. 3. FIXED OBLIGATIONS A. Leases: Lease costs included in operation expense were $14,706,000 in 1995, $15,547,000 in 1994 and $14,247,000 in 1993. The future minimum lease payments under the Company's various leases, all of which are operating leases, are approximately $14,300,000 per year over the next five years and $163,100,000 in the aggregate for years thereafter. The Company has a lease agreement with a remaining term of 16 years for its corporate headquarters. B. Fixed Charges Under Firm Contracts: The Company has entered into various contracts for gas delivery and supply services. The contracts have varying terms that extend from one to twenty years. Certain of these contracts require payment of monthly charges in the aggregate amount of approximately $4.2 million per month in all events and regardless of the level of service available. Such charges are recovered as gas costs. 4. CAPITALIZATION A. Common and Preferred Stock: In 1995 and 1994, the Company issued 1,198,305 and 1,209,734 shares of common stock for $27,974,000 and $29,828,000, respectively, under the Automatic Dividend Reinvestment and Stock Purchase Plan, the Discount Stock Purchase Plan for Employees, and the Employee Savings Plan. At September 30, 1995, 1,200,070 unissued shares of common stock were reserved for issuance under these plans. On October 6, 1993, the Company issued 1,800,000 shares of common stock providing net proceeds of $44,910,000. Other changes to common stock reflect the amortization of premiums paid on preferred stock redeemed in prior years which were deferred in order to reflect the ratemaking treatment. Annual amortization was approximately $155,000 in each of the past two years. The 4.60% Series B preferred stock is subject to an annual sinking fund requirement of 3,000 shares at par value. B. Gas Facilities Revenue Bonds and Other: The Company can issue tax-exempt bonds through the New York State Energy Research and Development Authority. Whenever bonds are issued for new gas facilities projects, proceeds are deposited in trust and subsequently withdrawn by the Company to finance qualified expenditures. There are no sinking fund requirements for any Gas Facilities Revenue Bonds. The Company's 9.0% and 8.75% Gas Facilities Revenue Bonds became callable on May 15, 1995 and July 1, 1995, respectively, each issue at the optional redemption price of 102% of par value plus accrued interest. The Company is evaluating the possibility of refunding these bond issues. Other long-term debt consists primarily of debt of a subsidiary under a revolving loan agreement with no payments currently due. The annual average interest rate on this debt was 6.8% in fiscal 1995. 5. FINANCIAL INSTRUMENTS A. Fair Value of Financial Instruments: The Company's long-term debt consists primarily of publicly traded Gas Facilities Revenue Bonds, the fair value of which is estimated based on quoted market prices for the same or similar issues. The fair value of these bonds at September 30, 1995 and 1994 was $673,408,300 and $651,255,200, respectively, and the carrying value was $648,500,000 in both years. Subsidiary debt is carried at an amount approximating fair value because its interest rate is based on market rates. The fair value of the Company's redeemable preferred stock is estimated based on quoted market prices for similar issues. At September 30, 1995 and 1994, the fair value of this stock was $5,228,800 and $4,796,640, respectively, and the carrying value was $6,900,000 and $7,200,000, respectively. All other financial instruments included in the Consolidated Balance Sheet are stated in amounts that approximate fair values. B. Derivative Financial Instruments: The Company and its gas exploration and production subsidiaries employ derivative financial instruments, natural gas futures and swaps, for the purpose of managing commodity price risk. The utility tariff applicable to certain large-volume customers permits gas to be sold at prices established monthly within a specified range expressed as a percentage of prevailing alternate fuel prices (oil). Commencing in fiscal 1995, the Company initiated a hedging strategy designed to fix margins on specified portions of the sales to this market. Implementation of the strategy involves establishment of long positions in gas futures with offsetting short positions in oil futures of equivalent energy value over the same time period. The long gas futures position replicates the cost of gas to serve this market while the short oil futures position correspondingly fixes the selling price of gas to the target customers at the desired relationship to the price of the alternative fuel. A similar strategy involving swaps contracts is utilized for customers whose alternate fuel is No. 6 oil. These contracts cover 463,000 barrels of oil and extend through September 1996. The Company also entered into a series of swaps transactions to minimize its exposure to differences in the market prices of gas at certain receipt points in producing areas. These basis swaps contracts cover 14.5 billion cubic feet of gas through October 1996. With respect to natural gas production operations, the Company generally uses swaps (for production beyond 18 months), and standard New York Mercantile Exchange futures contracts (for production within 18 months) to hedge the price risk related to known production plans and capabilities. These contracts include a fixed price/volume and are structured as both straight and participating swaps. In either case, the Company pays the other parties the amount by which the floating variable price (settlement price) exceeds the fixed price and receives the amount by which the settlement price is below the fixed price. The settlement volume of participating swaps is reduced by 50% if the settlement price exceeds a defined limit. The following table summarizes the notional amounts and related fair values of the Company's derivative financial instrument positions outstanding at September 30, 1995 and 1994. In 1994, these amounts included marketing activities which were combined with those of Pennzoil Gas Marketing, Inc., through a limited liability company in 1995. Fair values are based on dealer quotes for the same or similar instruments. Differences between the notional contract amounts and fair values represent implicit gains or losses if the instruments were settled at market.
September 30, 1995 1994 (Thousands of Dollars) Notional Fair Notional Fair Amount Value Amount Value Futures contracts $89,640 $86,394 $ 43,047 $ 39,911 Swaps contracts $80,073 $82,705 $123,291 $116,161
Futures contracts expire and are renewed monthly. As of September 30, 1995, no such contract extended beyond September 1996. Further, swaps contracts are settled monthly and extend through March 1998. Margin deposits with brokers at September 30, 1995 amounted to $1,662,400. Deferred losses on closed positions were $748,000 and $1,225,000 at September 30, 1995 and 1994, respectively. The Company and its subsidiaries are exposed to credit risk in the event of nonperformance by counterparties to futures and swaps contracts, as well as nonperformance by the counterparties of the transactions against which they are hedged. The Company believes that the credit risk related to the futures and swaps contracts is no greater than that associated with the primary contracts which they hedge, as these contracts are with major investment grade financial institutions, and that elimination of the price risk lowers the Company's overall business risk. 6. INVESTMENT IN IROQUOIS PIPELINE A Company subsidiary, North East Transmission Co., Inc. (NETCO), owns an 11.4% interest in Iroquois Gas Transmission System, L.P. (Iroquois), which partnership owns and operates a 375-mile pipeline from Canada to the Northeast. NETCO's investment in Iroquois was $23.4 million at September 30, 1995. In 1992, Iroquois was informed by the U.S. Attorneys' Offices of various districts of New York of a civil investigation of alleged violations of the U.S. Army Corps of Engineers (COE) permit, a related State Water Quality Certification and/or the Federal Clean Water Act. Further, agency investigations of matters related to the construction of the Iroquois pipeline have been commenced by COE and the Federal Energy Regulatory Commission. Iroquois also has received inquiries from the Federal Department of Transportation and the PSC concerning certain construction activities. Civil penalties could be imposed if violations of Iroquois' governmental authorizations are shown to have occurred. No proceedings in connection with these investigations and inquiries have been commenced. Also in 1992, a criminal investigation of Iroquois was initiated and is being conducted by Federal authorities pertaining to various matters related to the construction of the pipeline. To date, no criminal charges have been filed. Iroquois' management believes the pipeline construction and right-of-way activities were conducted in a responsible manner. However, Iroquois deems it probable that indictments will be sought in connection with this investigation and in them substantial fines and other sanctions. The Company has been informed that Iroquois and its counsel have met and expect to continue to meet with those responsible for the civil and criminal investigations, from time to time, both to gain an informed understanding of the focus and direction of the investigations in order to defend itself and to explore possible resolutions that may be acceptable to all parties. A comprehensive resolution of these matters could have a material adverse effect on Iroquois' financial condition. Although no agreements have been reached regarding the disposition of these matters, based on discussions with Iroquois' management, in 1995 the Company recorded a provision which it believes to be adequate to cover its proportionate share of estimated costs of legal proceedings involving Iroquois. The provision and ultimate resolution of these matters has not and is not expected to materially affect the Company's results of operations and financial position. 7. ENVIRONMENTAL MATTERS Historically, the Company, or predecessor entities to the Company, owned or operated several former manufactured gas plant (MGP) sites. These sites have been identified for the New York State Department of Environmental Conservation (DEC) for inclusion on appropriate waste site inventories. In certain circumstances, former MGP sites can give rise to environmental cleanup responsibilities for the Company. Two MGP sites are under active consideration by the Company. One site, which is located on property still owned by the Company, is the former Coney Island MGP facility located in Brooklyn, New York. This site is the subject of continuing interim remedial action under the direction of the U.S. Coast Guard. Moreover, the Company recently has executed a consent order with the DEC with respect to addressing the overall remediation of the Coney Island site in accordance with state law. A schedule of investigative and cleanup activities is being developed, leading to a cleanup over the next several years. The other site currently is owned by the City of New York. The Company and the City are in the process of discussing a mutual approach to sharing potential environmental responsibility for this site. The Company believes it is likely that, at a minimum, investigative costs will be incurred by the Company with respect to that site. The DEC is maintaining open files and requiring the Company to continue monitoring or related investigatory efforts at two other Company-owned properties. Except as described above, no administrative or judicial proceedings or claims involving other former MGP sites have been initiated. Although the potential cost of cleanup with respect to these other sites may be material if the Company ever is compelled to address these sites, the Company cannot at this time determine the cost or extent of any cleanup efforts if cleanup ultimately should be required. Based upon the terms of the consent order for the Coney Island site and costs of investigation for the other MGP site under active consideration, the Company believes that the minimum cost of MGP- related environmental cleanup will be approximately $34 million, which, based upon current information, will be primarily for the Coney Island site. This amount includes approximately $4.9 million of costs expended as of September 30, 1995. The Company's actual MGP-related costs may be substantially higher, depending upon remediation experience, eventual end use of the sites, and environmental conditions not addressed in the consent order or current investigative plans. Such potential additional costs are not subject to estimation at this time. As of September 30, 1995, the Company had an accrued liability of $29.3 million and a related unamortized regulatory asset of $33.2 million. By order issued February 16, 1995, the PSC approved the Company's July 1993 petition to defer the costs associated with environmental site investigation and remediation incurred in 1993 and thereafter. Accordingly, recovery of these costs began in fiscal 1995. The recovery of these costs in rates is conditioned upon the absence of a PSC determination that such costs have not been reasonably or prudently incurred. In addition, the Company must demonstrate that it has taken all reasonable steps to obtain cost recovery from all available funding sources, including other potentially responsible parties. The PSC has initiated a generic proceeding to assess the extent of the potential liability for cleanup of MGP sites by the State's gas utilities and has indicated that it may consider in that proceeding generic policies regarding the recovery of such costs through gas utility rates. Any such policies may affect the Company's ability to reflect such costs in rates following the last year of the current rate agreement. At this time, the Company is unable to predict the outcome of that proceeding. NOTE 8. SUPPLEMENTAL GAS AND OIL DISCLOSURES
CAPITALIZED COSTS RELATING TO GAS AND OIL PRODUCING ACTIVITIES September 30, 1995 1994 (Thousands of Dollars) Unproved properties not being amortized $35,082 $25,335 Properties being amortized-productive and nonproductive 299,398 240,572 Total capitalized costs 334,480 265,907 Accumulated depletion (132,809) (109,885) Net capitalized costs $201,671 $156,022 At September 30, 1995, the Company had an immaterial deficiency in its asset ceiling test; however, such deficiency was eliminated by subsequent price changes.
The following is a summary of the costs (in thousands of dollars) which are excluded from the amortization calculation as of September 30, 1995, by year of acquisition: 1995-$23,114; 1994-$9,889; and prior years-$2,077. The Company cannot accurately predict when these costs will be included in the amortization base, but it is expected these costs will be evaluated within the next five years. COSTS INCURRED IN PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES United Total States Canada 1995* 1994* 1993 1993 1993 (Thousands of Dollars) Acquisition of properties- Unproved properties $10,996 $11,022 $5,289 $4,937 $352 Proved properties 14,983 28,370 40,091 30,541 9,550 Exploration 5,907 18,961 2,831 2,831 - Development 37,953 9,781 16,588 11,238 5,350 Total costs incurred $69,839 $68,134 $64,799 $49,547 $15,252
RESULTS OF OPERATIONS FROM GAS AND OIL PRODUCING ACTIVITIES
Total United Canada States 1995* 1994* 1993 1993 1993 (Thousands of Dollars) Revenues from gas and oil producing activities- Sales to unaffiliated parties $40,810 $41,185 $43,076 $31,745 $11,331 Sales to affiliates - 2,023 1,482 1,482 - Revenues 40,810 43,208 44,558 33,227 11,331 Production and lifting costs 5,762 5,360 8,608 4,232 4,376 Depletion 22,906 24,978 22,525 20,990 1,535 Total expenses 28,668 30,338 31,133 25,222 5,911 Income before taxes 12,142 12,870 13,425 8,005 5,420 Income taxes 1,957 3,306 4,129 1,691 2,438 Results of gas and oil producing activities (excluding corporate overhead and interest costs) $10,185 $9,564 $9,296 $6,314 $2,982 * Gas and oil operations were conducted predominantly in the United States in 1995 and 1994.
8. SUPPLEMENTAL GAS AND OIL DISCLOSURES (CONTINUED) The gas and oil reserves information is based on estimates of proved reserves attributable to the Company's interest as of September 30 of the years presented. These estimates principally were prepared by independent petroleum consultants. Proved reserves are estimated quantities of natural gas and crude oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: 1) Estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions. 2) The estimated future cash flows are compiled by applying year-end prices of gas and oil relating to the Company's proved reserves to the year-end quantities of those reserves except for the reserves devoted to future production that is hedged. These reserves are priced at their respective hedge amount. Future price changes are considered only to the extent provided by contractual arrangements in existence at year-end. 3) The future cash flows are reduced by estimated production costs, costs to develop the proved reserves and certain abandonment costs, all based on year-end economic conditions. 4) Future income tax expenses are based on year-end statutory tax rates giving effect to the remaining tax basis in the gas and oil properties and other deductions, credits and allowances relating to the Company's proved gas and oil reserves. 5) Future net cash flows are discounted to present value by applying a discount rate of 10%. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company's gas and oil reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. RESERVE QUANTITY INFORMATION Natural Gas (MMcf)
United Total States Canada 1995* 1994* 1993 1993 1993 Proved Reserves- Beginning of Year 142,858 108,847 111,664 84,171 27,493 Revisions of previous estimates 13,539 (2,297) 9,036 1,438 7,598 Extensions and discoveries 38,985 25,890 4,696 3,915 781 Production (21,822) (22,814) (26,596) (21,007) (5,589) Purchases of reserves in place 21,495 34,931 91,016 40,330 50,686 Sales of reserves in place - (1,699) (80,969) - (80,969) Proved Reserves- End of Year 195,055 142,858 108,847 108,847 - Proved Developed Reserves- Beginning of Year 110,225 100,454 93,417 65,924 27,493 End of Year 151,594 110,225 100,454 100,454 - *Gas and oil reserves were located predominantly in the United States in 1995 and 1994.
8. SUPPLEMENTAL GAS AND OIL DISCLOSURES (CONTINUED) CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS (MBBLS) United Total States Canada 1995* 1994* 1993 1993 1993 Proved Reserves- Beginning of Year 807 443 2,304 520 1,784 Revisions of previous estimates 245 (140) 184 (91) 275 Extensions and discoveries 155 155 3 3 - Production (148) (96) (320) (109) (211) Purchases of reserves in place 103 495 121 120 1 Sales of reserves in place - (50) (1,849) - (1,849) Proved Reserves- End of Year 1,162 807 443 443 - Proved Developed Reserves- Beginning of Year 543 407 2,239 455 1,784 End of Year 974 543 407 407 - * Gas and oil reserves were located predominantly in the United States in 1995 and 1994.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED GAS AND OIL RESERVES
Total* 1995 1994 (Thousands of dollars) Future cash flow $314,627 $249,437 Future costs- Production (57,941) (47,149) Development (29,948) (22,241) Future net inflows before income tax 226,738 180,047 Future income taxes (43,705) (26,930) Future net cash flows 183,033 153,117 10% discount factor (49,512) (44,983) Standardized measure of discounted future net cash flows $133,521 $108,134 * Gas and oil reserves were located predominantly in the United States in 1995 and 1994.
8. SUPPLEMENTAL GAS AND OIL DISCLOSURES (CONTINUED) CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVE QUANTITIES 1995 1994 1993 United Total* Total* Total States Canada (Thousands of dollars) Standardized measure- beginning of year $108,134 $110,406 $90,665 $76,695 $13,970 Sales and transfers, net of production costs (35,048) (37,848) (35,950) (28,995) (6,955) Net change in sales and transfer prices, net of production costs (2,786) (25,005) 4,001 7,011 (3,010) Extensions and discoveries and improved recovery, net of future production 28,868 15,536 6,554 5,994 560 Changes in estimated future development costs (2,351) (1,016) (8,281) (8,281) - Development costs incurred during the period that reduced future development costs 10,360 6,381 12,354 12,354 - Revisions of quantity estimates 13,858 (2,917) 6,195 1,926 4,269 Accretion of discount 11,763 12,397 11,033 8,921 2,112 Net change in income taxes (7,856) 4,001 (3,079) (1,045) (2,034) Purchases of reserves in place 15,176 27,561 61,410 40,548 20,862 Sales of reserves in place - (2,110) (27,539) - (27,539) Changes in production rates (timing) and other (6,597) 748 (6,956) (4,721) (2,235) Standardized measure-end of year $133,521 $108,134 $110,406 $110,406 $ - * Gas and oil reserves were located predominantly in the United States in 1995 and 1994.
8. SUPPLEMENTAL GAS AND OIL DISCLOSURES (CONTINUED) Average Sales Prices and Production Costs - Per Unit For the year ended September 30, 1995 1994 1993 Average Sales Price* Natural Gas ($/MCF) United States 1.47 1.97 2.12 Canada - - 1.39 Total 1.47 1.97 1.97 Oil, Condensate and Natural Gas Liquid ($/Bbl) United States 16.92 15.63 17.70 Canada - - 16.90 Total 16.92 15.63 17.17 *Represents the cash price received which excludes the effect of any hedging transactions. Production Cost Per Equivalent MCF ($) United States .25 .23 .18 Canada - - .64 Total .25 .23 .29 Acreage** As of September 30, 1995 Gross Net Producing 251,894 116,417 Undeveloped 118,935 56,133 Number of Producing Wells** As of September 30, 1995 Gross Net Gas wells 1000 533 Oil wells 18 6 **Located predominantly in the United States. Drilling Activity (Net) For the years ended September 30, 1995 1994 1993 Pro- Dry Total Pro- Dry Total Pro- Dry Total ducing ducing ducing Net developmental wells United States 10.0 3.4 13.4 6.6 - 6.6 5.4 - 5.4 Canada - - - - - - 5.0 - 5.0 Total 10.0 3.4 13.4 6.6 - 6.6 10.4 - 10.4 Net exploratory wells (U.S.) 1.4 0.4 1.8 2.5 1.2 3.7 - 0.5 0.5 At September 30, 1995 the Company, through a subsidiary, was involved in the drilling of one developmental well of which it was the sole owner. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure There have been no changes in accountants. In addition, there have been no disagreements between the Company and its independent public accountants concerning any matter of accounting principles or practices or financial disclosure required to be disclosed by this item. Part III Item 10. Directors and Executive Officers of the Registrant Information regarding the Company's directors is incorporated herein by reference to pages 1 through 7 of the Company's definitive Proxy Statement, dated December 28, 1995, for its Annual Meeting of Shareholders to be held on February 1, 1996. Information regarding the Company's executive officers, who are elected annually by the directors, is found on page 49 hereof. Item 11. Executive Compensation Information regarding compensation of the Company's executive officers is incorporated herein by reference to pages 7 through 11 of the Company's definitive Proxy Statement, dated December 28, 1995, for its Annual Meeting of Shareholders to be held on February 1, 1996. Item 12. Security Ownership of Certain Beneficial Owners and Management Information regarding beneficial ownership and management ownership is incorporated herein by reference to "Proposal (1) - Election of Directors" in the Company's definitive Proxy Statement, on pages 1 through 7, dated December 28, 1995, for its Annual Meeting of Shareholders to be held on February 1, 1996. Item 13. Certain Relationships and Related Transactions There are no transactions, or series of similar transactions, or contemplated transactions which have occurred since the beginning of the last fiscal year of the Company which exceed $60,000 and involve any director or executive officer of the Company. No executive officer or director of the Company was indebted to the Company or its subsidiaries at any time since the beginning of the last fiscal year of the Company in an amount in excess of $60,000. Part IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K (a) 1. All Financial Statements Page in Form 10-K Report of Independent Public Accountants 24 Summary of Significant Accounting Policies 25 Consolidated Statement of Income for the Years Ended September 30, 1995, 1994 and 1993 28 Consolidated Statement of Retained Earnings for the Years Ended September 30, 1995, 1994 and 1993 28 Consolidated Balance Sheet at September 30, 1995 and 1994 29 Consolidated Statement of Capitalization at September 30, 1995 and 1994 30 Consolidated Statement of Cash Flows for the Years Ended September 30, 1995, 1994 and 1993 31 Notes to Consolidated Financial Statements 32 (a) 2. Financial Statement Schedules Separate financial statements for The Brooklyn Union Gas Company are omitted for the reason that the Company's total assets for the fiscal year ended September 30, 1995, exclusive of investments in and advances to its consolidated subsidiaries, constitute more than 75% of the total assets shown by the Consolidated Balance Sheet as of September 30, 1995, and the Company's total gross revenues, exclusive of interest and dividends received or equity in income from the consolidated subsidiaries, constitute more than 75% of the total gross revenues shown by the Consolidated Statement of Income for the year ended September 30, 1995. The following additional data should be read in conjunction with the financial statements included in Part II, Item 8. Schedules not included herein have been omitted because they are not applicable or the required information is shown in such financial statements or notes thereto. Executive Officers of the Registrant - ------------------------------------ All Executive Officers serve one-year terms.
Age as of Sept. 30, Period Served Name and Position 1995 In Such Capacity Business Experience in Past 5 Years Robert B. Catell, President 58 1991 to Present President and Chief Executive Officer and Chief Executive Officer 1990 to 1991 President and Chief Operating Officer 1986 to 1990 Executive Vice President and Chief Operating Officer Craig G. Matthews 52 1994 to Present Executive Vice President Executive Vice President 1991 to 1994 Executive Vice President and Chief Financial Officer 1988 to 1991 Group Senior Vice President and Chief Financial Officer Helmut W. Peter 63 1992 to Present Executive Vice President Executive Vice President 1991 to 1992 Executive Vice President and Chief Engineer 1988 to 1991 Group Senior Vice President and Chief Engineer Anthony J. DiBrita 54 1992 to Present Senior Vice President Senior Vice President 1989 to 1992 Vice President Vincent D. Enright, Senior Vice 51 1994 to Present Senior Vice President and Chief President and Chief Financial Financial Officer Officer 1992 to 1994 Senior Vice President 1984 to 1992 Vice President William K. Feraudo 45 1994 to Present Senior Vice President Senior Vice President 1989 to 1994 Vice President Wallace P. Parker, Jr. 46 1994 to Present Senior Vice President Senior Vice President 1990 to 1994 Vice President 1987 to 1990 Assistant Vice President Lenore F. Puleo 42 1994 to Present Senior Vice President Senior Vice President 1990 to 1994 Vice President Maurice K. Shaw, Senior Vice 56 1993 to Present Senior Vice President President and Corporate Affairs Officer 1987 to 1993 Senior Vice President and Chief Marketing Officer Edward J. Sondey 57 1992 to Present Senior Vice President Senior Vice President 1981 to 1992 Vice President Tina G. Barber, Vice President 46 1994 to Present Vice President and Chief and Chief Information Officer Information Officer 1992 to 1994 Vice President Richard M. Desmond, Vice 61 1992 to Present Vice President, Comptroller and President, Comptroller and Chief Accounting Officer Chief Accounting Officer 1984 to 1992 Vice President and Comptroller Robert H. Preusser, Vice President 58 1992 to Present Vice President and Chief Engineer and Chief Engineer 1987 to 1992 Vice President Roger J. Walz, Vice President 50 1990 to Present Vice President and General Auditor and General Auditor 1988 to 1990 General Auditor Robert R. Wieczorek, Vice President 53 1994 to Present Vice President, Secretary Secretary and Treasurer and Treasurer 1989 to 1994 Vice President, Treasurer, and Assistant Secretary
SCHEDULE II THE BROOKLYN UNION GAS COMPANY AND SUBSIDIARIES CONSOLIDATED SCHEDULE OF VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED SEPTEMBER 30, 1995, 1994 AND 1993 ____________________________________________________________________ (Thousands of Dollars)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E Balance at Additions Balance at Beginning Charged to End of Description of Period Expense Deductions Period ______________________________ ____________ ______________ ______________ ______________ Year Ended September 30, 1995 Allowance for uncollectible accounts $14,963 $17,494 $18,727 (a) $13,730 ____________ ______________ ______________ ______________ Reserve for injuries and damages Public Liability $5,350 $4,368 $3,818 (b) $5,900 Workers' Compensation $1,425 $500 $335 (b) $1,590 ____________ ______________ ______________ ______________ $6,775 $4,868 $4,153 $7,490 ____________ ______________ ______________ ______________ Year Ended September 30, 1994 Allowance for uncollectible accounts $14,212 $18,737 $17,986 (a) $14,963 ____________ ______________ ______________ ______________ Reserve for injuries and damages $6,816 $3,447 $3,488 (b) $6,775 ____________ ______________ ______________ ______________ Year Ended September 30, 1993 Allowance for uncollectible accounts $11,609 $19,113 $16,510 (a) $14,212 ____________ ______________ ______________ ______________ Reserve for injuries and damages $6,900 $3,241 $3,325 (b) $6,816 ____________ ______________ ______________ ______________
(a) Write-off of bad debts, net recoveries. (b) Cost of injury and damage claims. (a) 3. Exhibits (3) Articles of incorporation and by-laws By-laws of the Company, dated June 28, 1995, incorporated by reference from Form 8-K dated September 5, 1995. Restated Certificate of Incorporation of the Company filed August 1, 1989, and Certificate of Amendment filed July 2, 1993; incorporated by reference from Exhibit 4(b) to Form S-3 Registration Statement No. 33-50249. (4) Instruments defining the rights of security holders, including indentures: Official Statement, dated May 15, 1985, respective of $98,500,000 New York State Energy Research and Development Authority, 9% Gas Facilities Refunding Revenue Bonds Series 1985A, incorporated by reference from Form 10-K for the year ended September 30, 1985. Participation Agreement, dated as of May 15, 1985, between the New York State Energy Research and Development Authority and The Brooklyn Union Gas Company relating to the 9% Gas Facilities Refunding Revenue Bonds Series 1985A, incorporated by reference from Form 10-K for the year ended September 30, 1985. Indenture of Trust, dated as of May 15, 1985, between the New York State Energy Research and Development Authority and Chemical Bank, as Trustee, relating to 9% Gas Facilities Refunding Revenue Bonds Series 1985A, incorporated by reference from Form 10-K for the year ended September 30, 1985. Official Statement, dated July 17, 1985, respective of $55,000,000 of New York State Energy Research and Development Authority, 8-3/4% Gas Facilities Revenue Bonds Series 1985, incorporated by reference from Form 10-K for the year ended September 30, 1985. Participation Agreement, dated as of July 1, 1985, between the New York State Energy Research and Development Authority and The Brooklyn Union Gas Company relating to the 8-3/4% Gas Facilities Revenue Bonds Series 1985, incorporated by reference from Form 10-K for the year ended September 30, 1985. Indenture of Trust, dated as of July 1, 1985, between the New York State Energy Research and Development Authority and Chemical Bank, as Trustee, relating to 8-3/4% Gas Facilities Revenue Bonds Series 1985, incorporated by reference from Form 10-K for the year ended September 30, 1985. Official Statement, dated December 4, 1985, respective of $125,000,000 of New York State Energy Research and Development Authority Variable Rate Gas Facilities Revenue Bonds Series 1985 I and 1985 II, incorporated by reference from Form 10-K for the year ended September 30, 1985. Participation Agreement, dated as of December 1, 1985, between the New York State Energy Research and Development Authority and The Brooklyn Union Gas Company relating to the Variable Rate Gas Facilities Revenue Bonds Series 1985 I and 1985 II, incorporated by reference from Form 10-K for the year ended September 30, 1985. Indenture of Trust, dated December 1, 1985, between New York State Energy Research and Development Authority and Chemical Bank, as Trustee, relating to the Variable Rate Gas Facilities Revenue Bonds Series 1985 I and 1985 II, incorporated by reference from Form 10-K for the year ended September 30, 1985. Official Statement, dated February 23, 1989, respective of $90,000,000 of the New York State Research and Development Authority Adjustable Rate Gas Facilities Revenue Bonds Series 1989A and Series 1989B, incorporated by reference from Form S-8 Registration Statement No. 33-29898. Participation Agreement, dated as of February 1, 1989, between the New York State Energy Research and Development Authority and The Brooklyn Union Gas Company relating to the Adjustable Rate Gas Facilities Revenue Bonds Series 1989A, incorporated by reference from Form 10-K for the year ended September 30, 1989. Participation Agreement, dated as of February 1, 1989, between the New York State Energy Research and Development Authority and The Brooklyn Union Gas Company relating to the Adjustable Rate Gas Facilities Revenue Bonds Series 1989B, incorporated by reference from Form 10-K for the year ended September 30, 1989. Indenture of Trust, dated February 1, 1989, between the New York State Energy Research and Development Authority and Manufacturers Hanover Trust Company, as Trustee, relating to the Adjustable Rate Gas Facilities Revenue Bonds Series 1989A, incorporated by reference from Form 10-K for the year ended September 30, 1989. Indenture of Trust, dated February 1, 1989, between the New York State Energy Research and Development Authority and Manufacturers Hanover Trust Company, as Trustee, relating to the Adjustable Rate Gas Facilities Revenue Bonds Series 1989B, incorporated by reference from Form 10-K for the year ended September 30, 1989. Official Statement, dated July 24, 1991, respective of $50,000,000 of the New York State Research and Development Authority Gas Facilities Revenue Bonds Series 1991A and $50,000,000 of the New York State Research and Development Authority Gas Facilities Revenue Bonds Series 1991B, incorporated by reference from Form 10-K for the year ended September 30, 1991. Participation Agreement, dated as of July 1, 1991,between the New York State Energy Research and Development Authority and The Brooklyn Union Gas Company relating to the Gas Facilities Revenue Bonds Series 1991A and 1991B, incorporated by reference from Form 10-K for the year ended September 30, 1991. Indenture of Trust, dated as of July 1, 1991, between the New York State Energy Research and Development Authority and Manufacturers Hanover Trust Company, as Trustee, relating to the Gas Facilities Revenue Bonds Series 1991A and 1991B, incorporated by reference from Form 10-K for the year ended September 30, 1991. Official Statement, dated July 23, 1992, respective of $37,500,000 of the New York State Energy Research and Development Authority Gas Facilities Revenue Bonds Series 1993A and $37,500,000 of the New York State Energy Research and Development Authority Gas Facilities Revenue Bonds Series 1993B, incorporated by reference from Form 10-K for the year ended September 30, 1992. Participation Agreement, dated as of July 1, 1992, between the New York State Energy Research and Development Authority and The Brooklyn Union Gas Company relating to the Gas Facilities Revenue Bonds Series 1993A and 1993B, incorporated by reference from Form 10-K for the year ended September 30, 1992. Indenture of Trust, dated as of July 1, 1992, between the New York State Energy Research and Development Authority and Chemical Bank, as Trustee, relating to the Gas Facilities Revenue Bonds Form Series 1993A and 1993B, incorporated by reference from Form 10-K for the year ended September 30, 1992. Official Statement, dated April 29, 1992, respective of $90,000,000 of the New York State Energy Research and Development Authority, 6.75% Gas Facilities Revenue Bonds, replacing $45,000,000 Series 1989A and $45,000,000 Series 1989B, incorporated by reference from Form 10-K for the year ended September 30, 1992. First Supplemental Participation Agreement dated as of May 1, 1992 to Participation Agreement dated February 1, 1989 between the New York State Energy Research and Development Authority and The Brooklyn Union Gas Company relating to Adjustable Rate Gas Facilities Revenue Bonds, Series 1989A & B, incorporated by reference from Form 10-K for the year ended September 30, 1992. First Supplemental Trust Indenture dated as of May 1, 1992 to Trust Indenture dated February 1, 1989 between the New York State Energy Research and Development Authority and Manufacturers Hanover Trust Company, as Trustee, relating to Adjustable Rate Gas Facilities Revenue Bonds, Series 1989A & B, incorporated by reference from Form 10-K for the year ended September 30, 1992. Official Statement, dated July 15, 1993, respective of $25,000,000 of the New York State Energy Research and Development Authority Gas Facilities Revenue Bonds Series D-1 and $25,000,000 of the New York State Energy Research and Development Authority Gas Facilities Revenue Bonds Series D-2, incorporated by reference from Form S-8 Registration Statement No. 33-66182. Participation Agreement, dated July 15, 1993, between the New York State Energy Research and Development Authority and The Brooklyn Union Gas Company relating to the Gas Facilities Revenue Bonds Series D-1 1993 and Series D-2 1993, incorporated by reference from Form S-8 Registration Statement No. 33-66182. Indenture of Trust, dated July 15, 1993, between The New York State Energy Research and Development Authority and Chemical Bank as Trustee, relating to the Gas Facilities Revenue Bonds Series D-1 1993 and Series D-2 1993, incorporated by reference from Form S-8 Registration Statement No. 33-60182. Official Statement, dated July 8, 1993, respective of $55,000,000 of the New York State Energy Research and Development Authority Gas Facilities Revenue Bonds Series C, incorporated by reference from Form 10-K for the year ended September 30, 1993. First Supplemental Participation Agreement dated as of July 1, 1993 to Participation Agreement dated as of June 1, 1990, between the New York State Energy Research and Development Authority and The Brooklyn Union Gas Company relating to Gas Facilities Revenue Bonds Series C, incorporated by reference from Form 10-K for the year ended September 30, 1993. First Supplemental Trust Indenture dated as of July 1, 1993 to Trust Indenture dated as of June 1, 1990 between the New York State Energy Research and Development Authority and Chemical Bank, as Trustee, relating to Gas Facilities Revenue Bonds Series C, incorporated by reference from Form 10-K for the year ended September 30, 1993. (10) Material contracts Deferred Compensation Plan Preamble, dated, December 17, 1986, incorporated by reference from Form 10-K for the year ended September 30, 1987. Corporate Incentive Compensation Plan Description, incorporated by reference from Form 10-K for the year ended September 30, 1989. Marketing Incentive Compensation Plan Description, incorporated by reference from Form 10-K for the year ended September 30, 1989. Deferral Plan for Incentive Awards Description, incorporated by reference from Form 10-K for the year ended September 30, 1989. Agreement of Lease between Forest City Jay Street Associates and The Brooklyn Union Gas Company dated September 15, 1988, incorporated by reference from Form 10-K for the year ended September 30, 1990. (11) Statement re: Computation of per share earnings. See Part II, Item 8., "Financial Statements and Supplementary Data - Consolidated Statement of Income for the Years Ended September 30, 1995, 1994 and 1993," for information required by this item. (12) Statement re: Computation of consolidated ratio of earnings to fixed charges (21) Subsidiaries of the registrant (23) Consents of experts (27) Financial data schedule (b) Reports on Form 8-K: There was a Form 8-K report filed on September 5, 1995, noting that the Company amended its by-laws on June 28, 1995. No financial statements were included in that report. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant, and in the capacities indicated on December 13, 1995. THE BROOKLYN UNION GAS COMPANY Signature Title s/Robert B. Catell President and Chief Executive (Robert B. Catell) Officer s/Craig G. Matthews Executive Vice President (Craig G. Matthews) s/Vincent D. Enright Senior Vice President and (Vincent D. Enright) Chief Financial Officer s/Richard M. Desmond Vice President, Comptroller (Richard M. Desmond) and Chief Accounting Officer s/Kenneth I. Chenault Director (Kenneth I. Chenault) s/Andrea S. Christensen Director (Andrea S. Christensen) s/Donald H. Elliott Director (Donald H. Elliott) s/Alan H. Fishman Director (Alan H. Fishman) s/James L. Larocca Director (James L. Larocca) s/Edward D. Miller Director (Edward D. Miller) s/Richardson Pratt, Jr. Director (Richardson Pratt, Jr.) s/James Q. Riordan Director (James Q. Riordan) EX-12 2 Exhibit 12 THE BROOKLYN UNION GAS COMPANY AND SUBSIDIARIES Computation of Consolidated Ratio of Earnings to Fixed Charges Fiscal Year Ended September 30, 1995 1994 1993 1992 1991 _________ _________ _________ _________ _________ (Thousands of Dollars) Earnings Net Income $ 91,835 $ 87,384 $ 76,563 $ 59,873 $ 61,809 Federal Income Tax 42,040 40,698 41,483 29,219 23,640 Interest on Long-Term Debt 47,939 48,084 46,353 40,990 38,162 Other Interest Charges 5,128 2,787 2,617 2,046 3,747 Portion of Rentals Representing Interest 4,883 5,196 4,256 5,310 1,401 Adjustment Related to Equity Investee 174 (601) 729 3,239 1,524 Earnings Available to Cover --------- --------- --------- --------- --------- Fixed Charges $ 191,999 $ 183,548 $ 172,001 $ 140,677 $ 130,283 ========= ========= ========= ========= ========= Fixed Charges Interest on Long-Term Debt* $ 50,521 $ 49,280 $ 47,017 $ 41,766 $ 39,063 Other Interest Charges 5,128 2,787 2,617 2,046 3,747 Portion of Rentals Representing Interest 4,883 5,196 4,256 5,310 1,401 --------- --------- --------- --------- --------- Total Fixed Charges $ 60,532 $ 57,263 $ 53,890 $ 49,122 $ 44,211 ========= ========= ========= ========= ========= Ratio of Earnings to Fixed Charges 3.17 3.21 3.19 2.86 2.95 ========= ========= ========= ========= ========= * Includes capitalized interest of $2,582,000 in 1995, $1,196,225 in 1994, $663,836 in 1993 $775,726 in 1992 and $901,137 in 1991.
EX-21 3 Exhibit 21 PRINCIPAL OPERATING SUBSIDIARIES FUEL RESOURCES INC. 1330 Post Oak Boulevard Houston, Texas 77056 R. Gerald Bennett President and Chief Executive Officer THE HOUSTON EXPLORATION COMPANY 1331 Lamar Houston, Texas 77010 James G. Floyd President and Chief Executive Officer GAS ENERGY INC. GAS ENERGY COGENERATION INC. 111 Livingston Street Brooklyn, New York 11201 David S. Milne, Jr. President and Chief Executive Officer EX-23 4 Exhibit 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report included in this Form 10-K, into the Company's previously filed Registration Statements File Nos. 33-66182, 33-61283 and 33-51561. ARTHUR ANDERSEN LLP December 13, 1995 New York, New York EX-27 5
UT 0000014525 BROOKLYN UNION GAS CO. 1 U.S. DOLLARS 12-MOS SEP-30-1995 OCT-01-1994 SEP-30-1995 1 PER-BOOK 1,296,930,000 336,734,000 310,424,000 172,834,000 0 2,116,922,000 16,263,000 506,318,000 303,709,000 826,290,000 0 6,900,000 720,569,000 0 0 0 0 300,000 0 0 562,863,000 2,116,922,000 1,216,284,000 43,283,000 1,034,491,000 1,077,774,000 138,510,000 6,392,000 144,902,000 53,067,000 91,835,000 337,000,000 91,498,000 67,229,000 46,206,000 210,815,000 1.90 1.90
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