-----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, PQ1dS5AFzTkVXoMxc5OpCr0WwSUwV0dXuM38eaBxk/taExPuJg3ZflhbGDlohOCD nt0qkyK4q21+IB0m0kIb1A== 0000014525-96-000027.txt : 19961219 0000014525-96-000027.hdr.sgml : 19961219 ACCESSION NUMBER: 0000014525-96-000027 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19960930 FILED AS OF DATE: 19961218 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: 96682691 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, 1996 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 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. (X) Aggregate market value of registrant's voting Common Stock held by non-affiliates as of December 16, 1996 was approximately $1.5 billion. On December 18, 1996 the Company had 49,993,378 shares of Common Stock outstanding. DOCUMENTS INCORPORATED BY REFERENCE Part of Documents Form 10-K Prospectus/Proxy Statement dated December 20, 1996 Part III PART I Item 1. Business The Company 2 Gas Supply 4 Regulation and Rate Matters 5 Competition 6 Environmental Matters 8 Research and Development 8 Subsidiaries 8 Employees 11 Item 2. Properties 11 Item 3. Legal Proceedings 12 Item 4. Submission of Matters to a Vote of Security Holders 12 PART II Item 5. Market for the Registrant's Common Stock and Related Security Holder Matters 12 Item 6. Selected Financial Data 14 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 15 Item 8. Financial Statements and Supplementary Data 25 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 50 PART III Item 10. Directors and Executive Officers of the Registrant 50 Item 11. Executive Compensation 50 Item 12. Security Ownership of Certain Beneficial Owners and Management 50 Item 13. Certain Relationships and Related Transactions 50 Part IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 51 Signatures 58 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, 1996, the Company had approximately 1,126,000 active meters, of which approximately 1,089,000 were residential. The Company is subject to the regulatory jurisdiction of the New York State Public Service Commission (PSC). Its subsidiaries participate and own investments in gas and oil exploration, production and processing, gas pipeline transportation and storage, cogeneration, marketing and other energy-related services. Gas exploration and production investments are fully consolidated. Other investments are accounted for on the equity method. 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 gas distribution 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 usually incurred in the fourth quarter. The Company's tariff contains a weather normalization adjustment that provides for recovery from or refund to firm customers of material shortfalls or excesses of firm net revenues during a heating season due to variations from normal weather. (See Item 1., "Business - Regulation and Rate Matters" and Part II, Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations - 'Rate and Regulatory Matters' "). 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, 1996, utility firm gas sales were 141,948 MDTH, of which 75% were residential, 13% commercial, 8% governmental and 4% industrial. Other utility gas sales and transportation deliveries to off-system and interruptible on-system customers amounted to 42,950 MDTH. In September 1996, the New York State Public Service Commission (PSC) granted the Company's petition to restructure into a holding company, to be named KeySpan Energy Corporation (KeySpan). If the Company's common shareholders approve the restructuring at its Annual Meeting in February 1997, KeySpan would become the parent holding company of Brooklyn Union and its subsidiaries (which would become subsidiaries of KeySpan). This would be completed through a share exchange whereby the Company's common shareholders would receive KeySpan common stock on a share for share basis, thus becoming the owners of KeySpan. The PSC by order also approved a settlement agreement that contains restrictions and limitations on certain investments by KeySpan, limitations on the level of dividend payments from Brooklyn Union to KeySpan under certain circumstances, prohibitions on certain intercompany loans, guarantees and pledges, and restrictions on transactions among the affiliated holding company group. For further information, see Part II, Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Item 1., "Business - Competition". 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 set forth a policy framework and has issued an order on May 1, 1996 regarding utility compliance tariff filings, including the Company's, in line with market objectives of providing utility customers with wider choices in gas supply and related services at the local level. As a result of the order, all customers who choose to do so can arrange to purchase their gas directly from qualified marketers. The Company continues to serve as the transporter of gas within its local distribution network, and the related rates provide full margin recovery of all costs of service. (See Part II, Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations - 'Rate and Regulatory Matters'.") In 1996, 66% of gas supply was purchased from domestic sources under long-term contracts, 21% from Canadian sources under long- term contracts and 13% 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 utilities, municipalities, marketers and large-volume customers. In 1996, the Hub placed 29,638 MDTH of gas for delivery to customers in 14 states and one Canadian province. Long-Term Sources of Supply Under long-term contracts and regulatory certificates applicable to gas supply and pipeline transportation and storage services, the Company's suppliers are authorized and obligated to provide maximum firm daily total deliveries of 992 MDTH of gas for the 1996-97 winter. This supply consists of 375 MDTH per day of firm gas supply from U.S. sources, 100 MDTH per day of firm Canadian gas supply, 492 MDTH per day of storage and winter services related to U.S. sources, and 25 MDTH of on-system peaking supply. The Company's major providers of interstate pipeline capacity and related services are: Transcontinental Gas PipeLine Corporation, Texas Eastern Transmission Corporation, Iroquois Gas Transmission System, Tennessee Gas Pipeline Company, 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 U.S. and Canadian supplies purchased from natural gas sellers to the Company's market. 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 1,122 MDTH during the 1996-97 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 1996-97 winter, the Company has the capability to provide a maximum peak-day supply of 1,284 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. Effective November 1, 1996, a new winter peaking service, the Brooklyn Navy Yard Peaking Supply, was added to the Company's gas supply portfolio. It can provide a maximum daily quantity of 25 MDTH and a total available seasonal quantity of 480 MDTH. Gas Costs The average cost of gas purchased for firm customers was $3.49 per DTH in 1996, $3.12 per DTH in 1995 and $3.55 per DTH in 1994. Regulation and Rate Matters The agreement reached in the holding company filing included a new multi-year rate plan that became effective on October 1, 1996. After an initial rate reduction of approximately $3.0 million in fiscal 1997, the non-gas component in customer bills will be under specific price caps. Hence, the total amount for this component in rates that the Company can charge customers, in the aggregate, will remain constant for the subsequent five years, although rates in certain customer classes may be increased in order to reflect cost responsibility more appropriately. The Company also will be permitted to charge for various ancillary services. 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. Amendments have been made to rate schedules and tariffs to reflect the conditions and rates under which delivery and other services are provided to customers who opt to have their gas supplied by third parties. Rate schedules also have been established governing the provision of certain services to such marketers. 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 currently in billings to firm customers through the operation of a tariff provision, the Gas Adjustment Clause (GAC). Revenue requirements to establish utility rates are based on tariff sales to customers. Net revenues 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. Prior to October 1, 1996, net revenues from tariff sales for gas and transportation services to on-system customers made on an interruptible basis were refunded to firm customers subject to sharing provisions. 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. For information regarding the status of rate settlements and other regulatory proceedings, including the Company's rate order that became effective in October 1996, see Part II, Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations - 'Sales, Gas Costs and Net Revenues' and '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 and Basis for Financial Statement Presentation- Regulatory Assets'." Competition Within its utility service territory, the Company competes with suppliers of oil, electricity and other fuels for cooking, heating, air conditioning and other purposes. Regulatory changes have resulted in the unbundling of services in the natural gas industry. Beginning on May 1, 1996, customers in the Company's small-volume market have the option to purchase their gas supplies from sources other than the Company. Large volume customers have had this option for a number of years. Regardless of whether the Company's customers purchase gas from the Company or other suppliers, the customers pay the Company for transporting the gas. (See Part II, Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations - 'Sales, Gas Costs and Net Revenues' and 'Rate and Regulatory Matters'.") 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. Conversions from oil to gas heat continued during fiscal 1996. Approximately 78% 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 46%. In this market, gas service under large-volume rates is competitively priced with alternate grades of fuel oil. 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 continues to be committed to obtaining greater operational efficiencies through aggressive cost-containment programs, continuous reviews of business processes and the use of advanced technologies. Further, as a result of deregulation, a significant market for off-system gas sales, transportation and other services has developed. Competition is expected to intensify in this market as deregulation is more widely implemented in the Northeast. Moreover, many in the energy industry, including the Company, believe that the increasingly deregulated and more competitive environment may lead to industry consolidation, vertical integration and other strategic alliances as energy companies seek to offer a broader range of energy services to compete more effectively in attracting and retaining customers. For example, affiliations with other operating utilities could potentially result in economies and synergies, and vertical integration could provide a means to offer customers a more complete range of energy services. The Company believes that its proposed holding company structure, if approved by shareholders, would further expansion and diversification in energy-related businesses through investments, acquisitions and strategic alliances. The Company has been studying, and in some cases has held discussions regarding, utility and energy-related investments and transactions. The Company is unable to predict whether its activities will lead to investments and transactions that will result in enhanced competitive capabilities in the changing industry environment. In early December 1995, New York's Governor George Pataki endorsed a proposal to dismantle the Long Island Lighting Company (LILCO). Among other things, the proposal contemplates that the Long Island Power Authority (LIPA) would issue and sell tax-exempt bonds to purchase LILCO's electric transmission and distribution system and regulatory assets, and would assume a portion of LILCO's debt; LILCO's electric generating facilities and its gas business would be sold to other companies; and an energy company would contract with LIPA to manage the transmission and distribution of electricity to LILCO's customers. The Company has been following developments, and has had discussions and explored alternatives regarding the possibility of the Company participating in a combination or other transaction involving LILCO's gas and electric businesses and assets. The Company is unable to predict the course of developments or whether or how the Company might be involved should there be a transaction. 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 9., "Environmental Matters." Research and Development In fiscal 1996, the Company spent $12.8 million on research and development (R&D) programs. Of this amount, $2.4 million was spent to support programs of the Gas Research Institute. The Company also provided $2.1 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 $8.3 million was devoted primarily to the Company's internal R&D programs relating to efficient gas utilization and operations technologies. These programs covered cogeneration, power stations, refrigeration, fuel cells, as well as natural gas refueling stations. In addition, the Company continues to make significant efforts to develop innovative operation systems which reduce utility costs. Subsidiaries The Company's principal non-utility subsidiaries participate and own investments in gas exploration, production and processing; gas pipeline transportation and storage; cogeneration; marketing and other energy-related services. In fiscal 1996, earnings from subsidiaries were $40.5 million, or 82 cents per share, which included non-recurring gains from initial public offerings of $33.5 million and a reorganization charge of $7.8 million. Earnings excluding these non-recurring items were $14.8 million, or 30 cents per share. The Company's total investment in these businesses, computed in accordance with PSC specifications as a percentage of consolidated capitalization, was 13.4%, 14.2% and 12.8% as of September 30, 1996, 1995 and 1994, respectively. For further information regarding the subsidiaries, see Part II, Item 7., "Management's Discussion and Analysis of Financial Condition and Results of Operations", Part II, Item 8., "Financial Statements and Supplementary Data", Note 3., " The Houston Exploration Company", Note 8., "Investment in Iroquois Pipeline" and Note 10., "Supplemental Gas and Oil Disclosures". If the Company's common shareholders approve the holding company restructuring at the Company's Annual Meeting in February 1997, these non-utility subsidiaries will become subsidiaries of the holding company, KeySpan, and will no longer be subsidiaries of the Company. Gas Exploration, Production and Processing The Houston Exploration Company ("THEC") is an independent natural gas and oil company engaged in the exploration, development and acquisition of domestic natural gas and oil properties. THEC's offshore properties are located in the Gulf of Mexico, and its onshore properties are located in Texas, the Arkoma Basin and West Virginia. In contemplation of the initial public offering (IPO) of THEC's common stock, the Company implemented a reorganization of its exploration and production subsidiaries' assets and liabilities by transferring to THEC certain onshore producing properties and acreage not previously owned by THEC. As a result , all U. S. oil and gas properties of Fuel Resources Inc. ( FRI), a wholly owned subsidiary of the Company, were transferred to THEC. In September 1996, THEC completed the initial public offering of 7,130,000 shares of its common stock at an offering price of $15.50 per share and two smaller stock issuances, which reduced the Company's ownership from 100% to approximately 66%. The Company recorded a $35.4 million gain ($23.0 million after tax) as a result of these stock issuances and the related net increase in book value of the Company's investment in THEC. The proceeds to THEC from the IPO, after deductions for commissions and offering expenses, were approximately $101 million and were used to repay a portion of THEC's short-term borrowings incurred as a result of two major acquisitions in 1996 of properties and proved gas reserves in South Texas and the Gulf of Mexico for $84.7 million. In connection with the reorganization of the exploration and production properties, a reorganization charge of $7.8 million, net of federal income taxes, was recorded by THEC in fiscal 1996. (See Part II, Item 8., "Financial Statements and Supplementary Data," Note 3., "The Houston Exploration Company.") Total gas production was approximately 27.3 BCFe (one billion cubic feet of gas including oil equivalent volumes) during fiscal 1996 and net proved gas reserves at September 30, 1996 were approximately 322 BCFe. For information 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 10., "Supplemental Gas and Oil Disclosures". Solex Development Energy Company, a subsidiary of FRI, completed a public offering of trust units in the Taylor gas- processing plant in British Columbia, Canada, and realized a gain of $10.5 million, after taxes. This plant had been purchased in April 1995 and was sold to realize its value. The Company's subsidiary, KeySpan Energy Canada, Ltd., has an option to participate in the planned expansion of the plant. Investments in Energy Services Pipeline and Storage North East Transmission Co., Inc. (NETCO) increased its ownership interest by 8.0% in fiscal 1996 and as a result owns a 19.4% interest in the Iroquois Gas Transmission System L.P. (Iroquois), a 375-mile pipeline that currently transports approximately 860 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 the resolution of governmental investigations involving the Iroquois project, see Part II, Item 8., "Financial Statements and Supplementary Data," Note 8., "Investment in Iroquois Pipeline." Through a subsidiary, the Company has equity investments in two gas storage facilities located in New York State. Cogeneration Gas Energy Inc. (GEI) participates 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. GEI owns an 11.3% interest in a 174-megawatt gas cogeneration plant located in Lockport, New York. An affiliate is a 50% partner in a 40-megawatt facility that serves the State University of New York at Stony Brook, Long Island, which commenced operations in 1995, and 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. In 1996, these subsidiaries, as fuel managers, provided 15,000 MDTH of gas to these cogeneration projects. Marketing BRING Gas Services Corp., FRI's marketing subsidiary, in September 1996, sold its 50% interest in PennUnion Energy Services, L.L.C. to its partner, Pennzoil Gas Marketing Company, an affiliate of Pennzoil Company. KeySpan Energy Services Inc. (KES), formed in April 1996, sells natural gas both inside and outside the Company's utility service territory to large commercial and industrial customers, as well as groups of residential and small commercial customers. It has been authorized by the Federal Energy Regulatory Commission to market electricity interstate. KeySpan Energy Management Inc.(KEM), formed in October 1996, develops energy-related projects and provides a variety of technical and maintenance services for commercial and industrial customers. KEM has formed a strategic alliance with South Jersey Industries to develop energy projects in the mid-Atlantic region. Employees The Company and its subsidiaries employed 3,336 people at September 30, 1996, compared to 3,378 at September 30, 1995. 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 utility 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 utility employees represented by Local 3 of the International Brotherhood of Electrical Workers was ratified in August 1995. Item 2. Properties In fiscal 1996, consolidated capital expenditures were $ 302.3 million, of which $110.8 million was primarily for utility property additions and $191.5 million was for subsidiaries. Consolidated capital expenditures are estimated to be approximately $195 million for each of fiscal years 1997 and 1998. 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, 1996, the Company's distribution pipeline system consisted of approximately 1,987 miles of cast iron main, 1,677 miles of steel main and 288 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 a liquefied natural gas (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 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 15 years and renewal options. The Company and its subsidiaries own or lease certain other buildings and facilities for use in the conduct of their business. The Company's gross lease payments are approximately $14.1 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 concerning the gas exploration, production and processing activities of the Company's subsidiaries, see Part II, Item 8., "Financial Statements and Supplementary Data," Note 10., "Supplemental Gas and Oil Disclosures." Item 3. Legal Proceedings For information regarding the resolution of governmental investigations involving the Iroquois project, see Part II, Item 8., "Financial Statements and Supplementary Data," Note 8., "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 9., "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 5., "Capitalization." Stock Listings The Company's common stock is traded on the New York Stock Exchange (NYSE) under the trading symbol BU. The Houston Exploration Company (THEC) common stock is traded on the NYSE under the trading symbol THX. Daily stock reports are carried by most major newspapers under the heading BklyUG and HoustEX, respectively. Dividends Quarterly dividends on the Company's common stock have been 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. The PSC's holding company order contains limitations on the level of dividend payments from Brooklyn Union to KeySpan under certain circumstances, should the holding company restructuring be approved by shareholders. 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 6, 1997. Transfer Agent and Registrar of Stock First Chicago Trust Company of New York P.O. Box 2500 Jersey City, N.J. 07303-2500 (800)328-5090 Independent Public Accountants Arthur Andersen LLP 1345 Avenue of the Americas New York, NY 10105 (212)708-4000 Item 6. Selected Financial Data
For the Year Ended September 30, 1996 1995 1994 1993 1992 (Thousands of Dollars Except Per Share Data) Income Summary Operating revenues Utility sales $1,351,821 $1,152,331 $1,279,638 $1,145,315 $1,038,061 Gas production and other 80,181 63,953 58,992 60,189 36,799 - ------------------------------------------------------------------------------------------------ Total operating revenues 1,432,002 1,216,284 1,338,630 1,205,504 1,074,860 Operating expenses Cost of gas 610,053 446,559 560,657 466,573 402,137 Operation and maintenance 428,977 385,654 384,734 366,706 336,156 Depreciation and depletion 79,610 72,020 69,611 64,779 73,930 General taxes 143,296 134,718 150,743 144,827 135,549 Federal income tax 39,508 41,989 40,556 41,413 30,052 - ------------------------------------------------------------------------------------------------- Operating income 130,558 135,344 132,329 121,206 97,036 Income (loss) from energy services investments 13,523 9,458 5,689 1,150 (1,041) Gain on sale of investment in Canadian properties 16,160 - - 20,462 - Gain on sale of subsidiary stock 35,437 - - - - Write-off of investment in propane company - - - (17,617) - Other, net (1,188) 151 700 (465) 5,107 Federal income tax (expense) benefit (19,861) (51) (142) (70) 833 Interest charges 51,721 53,067 51,192 48,103 42,062 - ------------------------------------------------------------------------------------------------- Net income 122,908 91,835 87,384 76,563 59,873 Dividends on preferred stock 323 337 351 364 2,078 - ------------------------------------------------------------------------------------------------- Income available for common stock $122,585 $91,498 $87,033 $76,199 $57,795 ================================================================================================= Financial Summary Common stock information Per share Earnings ($) 2.48 1.90 1.85 1.73 1.35 Cash dividends declared ($) 1.42 1.39 1.35 1.32 1.29 Book value, year-end ($) 18.17 16.94 16.27 15.55 14.56 Market value, year-end ($) 27 7/8 24 5/8 24 7/8 25 3/4 22 3/8 Average shares outstanding (000) 49,365 48,211 46,980 44,042 42,882 Shareholders 33,320 33,669 35,233 30,925 31,367 Daily average shares traded 64,500 49,100 42,100 33,100 26,900 Capital expenditures ($) 302,280 214,006 199,572 204,514 173,467 Total assets ($) 2,289,603 2,116,922 2,029,074 1,897,847 1,748,027 Common equity ($) 905,808 826,290 774,236 721,076 632,254 Preferred stock, redeemable ($) 6,600 6,900 7,200 7,500 7,800 Long-term debt ($) 712,013 720,569 701,377 689,300 682,031 Total capitalization ($) 1,624,421 1,553,759 1,482,813 1,417,876 1,322,085 Earnings to fixed charges (times) 3.99 3.17 3.21 3.19 2.86 Utility Operating Statistics Gas data (MDTH) Firm sales 141,948 123,356 133,513 128,972 122,476 Other gas and transportation sales 42,950 49,910 42,392 25,032 23,706 Maximum daily capacity, year-end 1,284 1,256 1,256 1,258 1,199 Maximum daily sendout 994 963 1,022 915 904 Total active meters (000) 1,126 1,125 1,122 1,119 1,117 Heating customers (000) 461 454 446 441 436 Degree days 5,170 4,240 4,974 4,802 4,659 Colder (Warmer) than normal (%) 7.7 (11.2) 3.1 - (4.0)
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Earnings and Dividends In fiscal 1996, consolidated income available for common stock was $122.6 million, or $2.48 per share, compared to $91.5 million, or $1.90 per share, in 1995, and $87.0 million, or $1.85 per share, in 1994. This was the fourth consecutive year of record earnings. Consolidated earnings for the last three fiscal years are summarized below:
__________________________________________________________________________ 1996 1995 1994 __________________________________________________________________________ (Thousands of Dollars) Income Available for Common Stock Utility $ 82,090 $78,677 $76,665 _________________________________________________________________________ Gas exploration and production Operations (before reorganization charge) 7,627 7,843 5,707 Reorganization charge (7,800) - - Gain on sale of subsidiary stock 23,034 - - Gain on sale of Canadian plant 10,505 - - _________________________________________________________________________ 33,366 7,843 5,707 _________________________________________________________________________ Energy services Pipeline and storage 5,319 979 3,358 Cogeneration 414 2,670 1,303 Marketing 1,396 1,329 - _________________________________________________________________________ 7,129 4,978 4,661 _________________________________________________________________________ Consolidated $122,585 $91,498 $87,033 _________________________________________________________________________
In 1996, regulated utility operations provided an equity return of 12.80%. The return, which included incentives authorized by the New York State Public Service Commission (PSC), was higher than the allowed rate of 10.65%. The Company has earned at or above its allowed return on utility common equity in 17 of the last 18 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, as well as earnings incentives provided under rate stipulations (see "Rate and Regulatory Matters"). In 1996, such incentive-based earnings were related largely to higher margins on sales to large-volume and off-system customers and attaining a 93% 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. Utility operating margins have improved due to ongoing cost reduction efforts. In 1996, earnings from gas exploration, production and processing operations decreased, primarily due to a reorganization charge of $7.8 million, net of federal income taxes, recorded by the U.S. exploration and production subsidiary, The Houston Exploration Company (THEC). Excluding this charge, operating results were comparable in 1996 and 1995. However, earnings in 1996 also included an after-tax gain of $23.0 million on the issuance by THEC of 34% of its common stock in September 1996 (see Note 3 to the Consolidated Financial Statements, "The Houston Exploration Company" for additional information). Neither the Company, nor THEC, has plans for any further issuances of THEC stock, nor the stock of any of the Company's other subsidiaries - except for issuances under ongoing stock plans . Further, earnings included a gain of $10.5 million on the sale in July 1996 of an investment in a Canadian gas processing plant, which was sold to realize the substantial value embodied in the investment at the time. In 1995, earnings from gas exploration, production and processing operations increased, primarily due to higher U.S. natural gas production. Earnings from investments in energy services are attributable to various operations. In April 1996, a Company subsidiary increased its equity interest in the Iroquois Gas Transmission System, L.P. (Iroquois) by 8.0% to 19.4%, resulting in higher earnings during the year from Iroquois. In addition, earnings from pipeline and storage operations in all periods reflect higher throughput on Iroquois. In 1995, earnings were reduced by a provision for the Company's proportionate share of estimated costs of legal matters involving Iroquois. With respect to cogeneration investments, higher fuel prices caused earnings from these investments to decrease in 1996. In 1995, the increase in earnings reflected equity income from the start of operations at John F. Kennedy International Airport (JFK) and the campus of the State University of New York at Stony Brook. Earnings from gas marketing in 1996 were $1.4 million, similar to last year. Looking toward the future, the Company expects revenue growth as a result of the rationalization and refocusing of these operations. New wholly-owned subsidiaries have been formed to operate effectively as part of the Company's holding company strategy. One of these business units sells gas and expects to sell electricity inside and outside the traditional utility territory. The other will provide a variety of technical and maintenance management services for commercial and industrial customers. The initial focus will be conducted both independently and through strategic alliances. As an integral part of this marketing realignment, a Company subsidiary sold its 50% interest in the gas-marketing venture, PennUnion Energy Services, L.L.C., to the other partner. The consolidated rate of return on average common equity was 13.6% in 1996, 10.9% in 1995, and 11.0% in 1994. In December 1995, the Board of Directors authorized an increase in the annual dividend on common stock to $1.42 per share from $1.39 per share. This increase became effective on February 1, 1996, when the quarterly dividend was raised to 35 1/2 cents per share from 34 3/4 cents per share. Common dividends have been increased in 20 consecutive years and paid continuously for 48 years. Sales, Gas Costs and Net Revenues Firm utility gas sales volumes in fiscal 1996 were 141,948 MDTH compared to 123,356 MDTH in 1995 and 133,513 MDTH in 1994. Measured by annual degree days, weather was 7.7% colder than normal in 1996, 11.2% warmer than normal in 1995 and 3.1% colder than normal in 1994. Sales growth in all markets resulted primarily from conversions to natural gas from oil for space heating, especially by large apartment buildings. In 1996, the growth in firm sales normalized for weather was 2.4%, similar to that experienced in recent years.
_________________________________________________________________ 1996 1995 1994 _________________________________________________________________ (Thousands of Dollars) Utility sales $ 1,351,821 $ 1,152,331 $ 1,279,638 Cost of gas (610,053) (446,559) (560,657) _________________________________________________________________ Net revenues $ 741,768 $ 705,772 $ 718,981 _________________________________________________________________ Gas production and other $ 80,181 $ 63,953 $ 58,992 _________________________________________________________________
In 1996, higher utility sales primarily reflected higher billings due to colder weather. In 1995, the opposite occurred as lower utility sales primarily reflected lower billings for gas costs due to warm weather. 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. 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 1996. 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. Competition with other gas suppliers is expected to continue to increase as a result of deregulation. Moreover, a significant market for off-system gas sales, transportation and other services has developed as a result of deregulation. These sales or services reflect optimal use of available pipeline capacity as affected by weather and the Company's New York Market Hub in balancing on-system requirements to core customers with off-system services to increase total margins. In colder-than-normal winters, such as 1996, sales to on- system customers are higher whereas off-system services are comparatively lower. As a result, in 1996 gas and transportation sales and services to off-system and interruptible customers amounted to 42,950 MDTH compared with 49,910 MDTH in 1995. The Company and its gas exploration and production subsidiary employ derivative financial instruments, such as natural gas and oil futures, options and swaps, for the purpose of managing exposures to 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 in order to achieve a more predictable cash flow. Hedging strategies have been managed independently. (See Note 7B to the Consolidated Financial Statements, "Derivative Financial Instruments," for additional information.) The cost of gas, $610.1 million in 1996, was $163.5 million or 36.6% higher than in 1995. The higher cost reflects higher heating sales due to colder weather and higher average gas costs. The cost of gas in 1994 was $560.7 million reflecting higher volumes sold and higher average prices, both of which were primarily the result of cold weather in that year as compared to volumes and prices in 1995. The cost of gas for firm customers was $3.49 per DTH (one DTH equals 10 therms) in 1996, compared to $3.12 per DTH in 1995 and $3.55 per DTH in 1994. For the year ended September 30, 1996, the utility's cost of gas included hedging losses of $1.7 million related to its margin fixing strategy. The increase in revenues from gas production and other in 1996 is due primarily to the acquisition of additional natural gas properties (see Note 3 to the Consolidated Financial Statements, "The Houston Exploration Company", for additional information) and increased production from the gas processing plant located in British Columbia, Canada, which was purchased in April 1995 and was sold in July 1996. In 1996, gas production, including oil equivalents, was approximately 27.3 billion cubic feet (BCFe), or 4.6 BCFe above the level of production last year. In 1996, wellhead prices averaged approximately $2.11 per MCF compared with $1.47 per MCF last year. The realized price (average wellhead price received for production including recognized hedging gains and losses) was $1.82 per MCF in 1996 compared with $1.77 per MCF in 1995. Hence, the Company's hedging strategy stabilized the weather-related volatility inherent in the wellhead price which showed an increase on average of 64 cents per MCF in 1996 compared to 1995. The effective price increased 5 cents in 1996 compared to 1995. The effective price in 1996 included a hedging loss of $7.7 million while the effective price in 1995 included a hedging gain of $6.6 million. (See Note 10 to the Consolidated Financial Statements, "Supplemental Gas and Oil Disclosures", for additional information.) Expenses, Other Income and Preferred Dividends The increase in operation and maintenance expense in 1996 reflects the effects of colder weather compared to last year and the reorganization charge incurred by the U.S. exploration and production subsidiaries. The reorganization charge of $12.0 million reflects remuneration that certain former employees of the Company's other exploration and production subsidiary were paid as the result of the increase in the value of the gas and oil properties transferred to THEC. The decrease in 1995 reflected warmer weather 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 1996 and 1995 included costs related to Canadian gas processing operations, which ceased in July 1996 when the plant was sold. The increase in depreciation and depletion expense in 1996 reflects higher depletion charges of subsidiaries due to increased gas production and higher utility depreciation expense due to property additions. 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. The increase in earnings from energy services investments in 1996 is primarily due to the increase in earnings from Iroquois offset by lower cogeneration earnings, as previously discussed. Other income also includes pre-tax gains on the sale of the Canadian plant and on the issuance of 34% of THEC's common stock. Interest charges on long-term debt in each of the last three fiscal years generally reflect higher average subsidiary borrowings. In fiscal 1996, interest charges reflected lower utility interest costs due to debt refunding. Other interest expense primarily reflects accruals of carrying charges related to regulatory settlement items. Dividends on preferred stock reflect reductions in the level of preferred stock outstanding due to sinking fund redemptions. Capital Expenditures Consolidated capital expenditures were $302.3 million in 1996, $214.0 million in 1995 and $199.6 million in 1994. Capital expenditures related to utility operations were $110.8 million in 1996, $108.7 million in 1995 and $103.8 million in 1994. Utility expenditures in all years principally were for the renewal and replacement of mains and services. Capital expenditures related to gas exploration, production and processing activities were $169.0 million in 1996, $83.0 million in 1995 and $71.3 million in 1994. Expenditures in 1996 reflect two major acquisitions totaling $84.7 million for gas and oil reserves in South Texas and the Gulf of Mexico, as well as on- going exploration and development activities. Expenditures in 1996 primarily reflect increased off-shore development activities. Net proved gas reserves at September 30, 1996 were approximately 322 BCFe. These reserves are located off-shore in the Gulf of Mexico and on-shore in Texas, the Arkoma Basin and West Virginia. Capital expenditures related to energy services investments were $22.5 million in 1996, $22.3 million in 1995 and $24.5 million in 1994. Expenditures in 1996 primarily were for the acquisition of the additional interest in Iroquois. Also, in 1996 the cogeneration plant at JFK was refinanced and cash flows from investing activities include a return of capital from the proceeds. In 1995 and 1994, expenditures were primarily related to the construction of the JFK cogeneration project and, in 1995, also included $5.6 million related to the Stony Brook cogeneration plant. In 1994, capital expenditures also included the acquisition of an interest in a cogeneration plant located in Lockport, New York. Consolidated capital expenditures for fiscal years 1997 and 1998 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 on an ongoing basis and can be affected by timing, scope and changes in investment opportunities. Financing Cash provided by operating activities continues to be strong and is a substantial source for financing ongoing capital expenditures. In 1996, cash flow from utility operations was reduced by the timing of budget plan billing settlements related to cold weather. In September 1996, THEC issued 7,130,000 shares of its common stock in an initial public offering, providing net proceeds of $101.0 million, which were used to pay down debt and to complete the financing of gas reserve acquisitions and property additions discussed previously. In addition, proceeds from common stock issued through the Company's employee and shareholder stock purchase plans have provided the Company approximately $27.4 million in 1996, $28.0 million in 1995 and $29.8 million in 1994. The Company issued 1,800,000 new shares of common stock on October 6, 1993, providing net proceeds of $44.9 million. In March 1996, the Company refunded $153.5 million of Gas Facilities Revenue Bonds, including a $98.5 million series of 9% bonds and a $55 million series of 8.75% bonds. Both series were called for redemption at optional redemption prices equal to 102% of the face amount per bond plus accrued interest. The $153.5 million refunding series, which matures in 2021, was issued on January 29, 1996, with a coupon rate of 5.5% at a price of 99% of the principal amount of the bonds. The Company expects to initiate a call of its Gas Facilities Revenue Bonds, 7 1/8% Series 1985 I and 7% Series 1985 II, which are callable on December 1, 1996 at 102% of face amount per bond plus accrued interest to the call date. If authorization is received from government agencies, the bonds would be called early in calendar year 1997. At September 30, 1996, the consolidated annualized cost of long-term debt was 6.3%, compared to 7.1% in 1995 and 6.9% in 1994. Financial Flexibility and Liquidity At September 30, 1996, the Company had cash and temporary cash investments of $41.9 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 1996. Related borrowings primarily are used to finance seasonal working capital requirements, which in recent years have not been significant. At September 30, 1996, there were no borrowings outstanding. In addition, subsidiaries have lines of credit totaling $150 million, which for the most part support borrowings under revolving loan agreements. (See Note 5C to the Consolidated Financial Statements, "Other Long-Term Debt", for additional information.) At September 30, 1996, the common equity component of the Company's capitalization was 55.8%. Fixed charge coverage ratios were 3.99 times in 1996, 3.17 times in 1995 and 3.21 times in 1994. Rate and Regulatory Matters Rate Settlement Matters and Holding Company Agreement In September 1996, the New York State Public Service Commission (PSC) granted the Company's petition to restructure into a holding company, to be named KeySpan Energy Corporation. If the Company's shareholders approve the restructuring at its Annual Meeting in February 1997, KeySpan would become the parent holding company of Brooklyn Union and its subsidiaries (which would become subsidiaries of KeySpan) through a share exchange whereby the Company's common shareholders would receive KeySpan common stock, thus becoming the owners of KeySpan. The PSC's holding company order approved a settlement agreement among Brooklyn Union, the Staff of the Department of Public Service and several intervenor parties. This agreement contains restrictions and limitations on certain investments by KeySpan, limitations on the level of dividend payments from Brooklyn Union to KeySpan under certain circumstances, prohibitions on certain intercompany loans, guarantees and pledges, and restrictions on transactions among the affiliated holding company group. The agreement reached in the holding company filing included a new multi-year rate plan that became effective on October 1, 1996. After an initial rate reduction of approximately $3.0 million in fiscal 1997, the non-gas component in customer bills will be under specific price caps. Hence, the total amount for this component in rates that the Company can charge customers, in the aggregate, will remain constant for the subsequent five years, although rates in certain customer classes may be increased in order to reflect cost responsibility more appropriately. The Company also will be permitted to charge for various ancillary services. During the six-year term of the rate plan, the costs of gas purchased by the Company for its customers will be recovered currently in billed firm revenues through the operation of a tariff provision, the Gas Adjustment Clause (GAC). Further, in addition to recovering its specific gas costs in applicable rates, the Company's rates for transporting gas within its local distribution system provide for full margin recovery of its cost of service. (See Notes to Consolidated Financial Statements, "Summary of Significant Accounting Policies and Basis for Financial Statement Presentation -- Regulatory Assets".) Although there is no specific authorized rate of return on common equity, the rate plan includes provisions for rate changes if certain conditions applicable to inflation, exogenous costs or changes in financial condition occur. Under the agreement the Company generally is not subject to any earnings cap or provisions to share with customers any level of earnings from utility operations. However, incentive provisions remain for retention of 20% of margins on sales to off-system customers and capacity release credits, and expenditures related to remediation of the sites of former gas manufacturing plants are subject to a provision enabling the Company to retain any savings, while requiring it to absorb any costs, to the extent that expenditures vary by 10% compared with estimates. The agreement includes a customer service quality performance plan with a maximum forty basis-point pre-tax return penalty if service quality diminishes in certain categories over the term of the agreement. Also, the weather normalization adjustment was modified to provide that the Company may recover or be required to refund 87.5% of all margin shortfalls or surpluses resulting from weather that is warmer or colder-than-normal. In September 1995, the PSC approved the Company's second stage rate filing covering fiscal 1996. The approval provided for no base rate increase; however, $7.5 million in deferred credits were amortized to income in 1996. The authorized rate of return on utility common equity was set at 10.65% for fiscal 1996. In October 1994, the PSC approved a three-year rate settlement agreement which provided for no base rate increase in fiscal 1995; however, the Company amortized to income, as permitted, approximately $1.3 million of deferred credits in that year. The third year of this agreement was superseded by the PSC order in the holding company proceeding of September 1996 mentioned above. Restructuring Proceeding The PSC has set forth a policy framework to guide the transition of New York State's gas distribution industry in the deregulated gas industry environment. In March 1996, the PSC issued an order on utility compliance tariff filings, including the Company's, related to this framework. Pursuant to this order, beginning on May 1, 1996, customers in the Company's small-volume market have the option to purchase their gas supplies from sources other than the Company, which would serve as gas transporter. Large-volume customers have had this option for a number of years. Small-volume customers can be grouped together by marketers if their combined minimum threshold usage reaches 50,000 therms of gas per year, which approximates the usage of 35 homes. The PSC approved the Company's methodology of recovering the cost of pipeline capacity and storage service provided to marketing firms and transportation customers. In addition to transporting gas that customers purchase from marketers, utilities such as the Company will provide billing, meter reading and other services for aggregate rates that closely approximate the distribution charge reflected in otherwise applicable sales rates to supply these customers. The PSC order placed a limit on the amount of gas the Company would be obligated to transport in its core market under aggregation programs to 5% of total core sales in each of the next three years, with no more than 25% of any one service class permitted to convert to transportation service. 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 operations and maintenance activities. As of September 30, 1996, the Company had an accrued liability of $28.8 million representing costs associated with investigation and remediation at former manufactured gas plant sites. (See Note 9 to the Consolidated Financial Statements, "Environmental Matters," for additional information.) 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, 1996 and 1995, and the related Consolidated Statements of Income, Retained Earnings and Cash Flows for each of the three years in the period ended September 30, 1996. 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, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 1996, in conformity with generally accepted accounting principles. 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, 1996 New York, New York Summary of Significant Accounting Policies and Basis for Financial Statement Presentation 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 and certain reclassifications have been made to amounts in prior periods to conform them with the current period presentation. Further, the preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 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 1996 and 1995, and 3.3% in 1994. 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 subsidiary follows 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 properties 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 representing ownership interests of 50% or less 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 customers. Gas costs are recovered currently in billed firm revenues through the operation of a tariff provision, the Gas Adjustment Clause (GAC). Net revenues from off-system gas sales and tariff gas balancing services and capacity release credits are refunded to firm customers subject to certain limited sharing provisions in the Company's tariff. Prior to October 1, 1996, net revenues from tariff sales for gas and transportation services to on-system customers made on an interruptible basis were refunded to firm customers subject to sharing provisions. The GAC provision requires an annual reconciliation of recoverable gas costs and GAC revenues. Any difference is deferred pending recovery from or refund to firm customers during a subsequent twelve-month period. Derivative Financial Instruments The Company and THEC use derivative financial instruments primarily to hedge exposures in cash flows due to fluctuations in the price of natural gas and fuel oil, which in certain markets may strongly influence the Company's selling price for natural gas. Gains and losses on these instruments are recognized concurrently with the recognition of the related physical transactions. 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 were not to remain in an acceptable range, the Company would account for its financial instrument positions as trading activities. Federal Income Tax Prior to the adoption in 1994 of SFAS-109, "Accounting for Income Taxes", 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. In accordance with SFAS-109, 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. 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 The Company is subject to the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation". 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. With the exception of net tax regulatory assets all other significant assets and liabilities created by the ratemaking process, including the $33.2 million recorded for environmental remediation costs as of September 30, 1995, have been reflected in utility rates pursuant to the agreement approved by the PSC in its September 25, 1996 holding company order. Accordingly, at September 30, 1996 the Company had only a net tax regulatory asset of $74,885,000 compared to a regulatory asset of $109,636,000 related to taxes and environmental costs at September 30, 1995. In the event that it were no longer subject to the provisions of SFAS-71, the Company estimates that the write-off of this net regulatory tax asset could result in a charge to net income of approximately $48,675,000 which would be classified as an extraordinary item. Subsidiary Common Stock Issuances to Third Parties The Company follows an accounting policy of income statement recognition for parent company gains or losses from issuances of stock by subsidiaries. Research and Development Costs All research and development costs are expensed as incurred. For the years ended September 30, 1996, 1995 and 1994, these costs were $12.8 million, $11.9 million and $11.9 million, respectively. CONSOLIDATED STATEMENT OF INCOME
===================================================================================== For the Year Ended September 30, 1996 1995 1994 ===================================================================================== (Thousands of Dollars) Operating Revenues Utility sales $ 1,351,821 $1,152,331 $1,279,638 Gas production and other 80,181 63,953 58,992 ---------------------------------------------------------------------------------------- 1,432,002 1,216,284 1,338,630 ---------------------------------------------------------------------------------------- Operating Expenses Cost of gas 610,053 446,559 560,657 Operation and maintenance 428,977 385,654 384,734 Depreciation and depletion 79,610 72,020 69,611 General taxes 143,296 134,718 150,743 Federal income tax (See Note 1) 39,508 41,989 40,556 ---------------------------------------------------------------------------------------- Operating Income 130,558 135,344 132,329 Other Income Income from energy services investments 13,523 9,458 5,689 Gain on sale of investment in Canadian plant 16,160 - - Gain on sale of subsidiary stock (See Note 3) 35,437 - - Other, net (1,188) 151 700 Federal income tax (See Note 1) (19,861) (51) (142) ----------------------------------------------------------------------------------------- Income Before Interest Charges 174,629 144,902 138,576 Interest Charges Long-term debt 46,803 47,939 46,900 Other 4,918 5,128 4,292 ---------------------------------------------------------------------------------------- Net Income 122,908 91,835 87,384 Dividends on Preferred Stock 323 337 351 ---------------------------------------------------------------------------------------- Income Available for Common Stock $ 122,585 $ 91,498 $ 87,033 ======================================================================================== Earnings Per Share of Common Stock (Average shares outstanding of 49,365,435, 48,211,220 and 46,979,597, respectively) $ 2.48 $ 1.90 $ 1.85 ========================================================================================
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
======================================================================================= For the Year Ended September 30, 1996 1995 1994 --------------------------------------------------------------------------------------- (Thousands of Dollars) Balance at Beginning of Year $ 303,709 $ 279,466 $ 255,979 Income Available for Common Stock 122,585 91,498 87,033 ---------------------------------------------------------------------------------------- 426,294 370,964 343,012 Less: Cash dividends declared ($1.42, $1.39 and $1.35 per common share, respectively) 70,291 67,229 63,652 Other adjustments 30 26 (106) ----------------------------------------------------------------------------------------- Balance at End of Year $ 355,973 $ 303,709 $ 279,466 ========================================================================================= The accompanying Summary of Significant Accounting Policies and Basis for Financial Statement Presentation and Notes to Consolidated Financial Statements are integral parts of these statements.
=============================================================================================== CONSOLIDATED BALANCE SHEET September 30, 1996 1995 (Thousands of Dollars) Assets Property Utility, at cost $ 1,782,440 $ 1,690,193 Accumulated depreciation (429,476) (393,263) Gas exploration and production, at cost (See Note 3) 510,568 353,847 Accumulated depletion (165,414) (138,136) ------------------------------------------------------------------------------------------------ 1,698,118 1,512,641 ------------------------------------------------------------------------------------------------ Investments in Energy Services (See Note 8) 115,529 121,023 ------------------------------------------------------------------------------------------------ Current Assets Cash 18,524 15,992 Temporary cash investments 23,397 24,550 Accounts receivable 172,843 146,018 Allowance for uncollectible accounts (15,616) (13,730) Gas in storage, at average cost 91,813 88,810 Materials and supplies, at average cost 12,089 13,203 Prepaid gas costs 11,945 15,725 Other 38,888 19,856 ------------------------------------------------------------------------------------------------ 353,883 310,424 ------------------------------------------------------------------------------------------------ Deferred Charges 122,073 172,834 ------------------------------------------------------------------------------------------------ $ 2,289,603 $ 2,116,922 ================================================================================================ Capitalization and Liabilities Capitalization (See accompanying statement and Note 5) Common equity $ 905,808 $ 826,290 Preferred stock, redeemable 6,600 6,900 Long-term debt 712,013 720,569 ------------------------------------------------------------------------------------------------ 1,624,421 1,553,759 ------------------------------------------------------------------------------------------------ Current Liabilities Accounts payable 143,561 103,705 Dividends payable 18,229 17,536 Taxes accrued 10,905 3,635 Customer deposits 21,881 22,252 Customer budget plan credits 8,892 24,790 Interest accrued and other 37,244 39,438 ------------------------------------------------------------------------------------------------ 240,712 211,356 ------------------------------------------------------------------------------------------------ Deferred Credits and Other Liabilities Federal income tax 282,041 247,882 Unamortized investment tax credits 20,007 20,948 Other 43,573 82,977 ------------------------------------------------------------------------------------------------ 345,621 351,807 ------------------------------------------------------------------------------------------------ Minority Interest in Subsidiary Company (See Note 3) 78,849 - ------------------------------------------------------------------------------------------------ $ 2,289,603 $ 2,116,922 ================================================================================================ The accompanying Summary of Significant Accounting Policies and Basis for Financial Statement Presentation and Notes to Consolidated Financial Statements are integral parts of these statements.
CONSOLIDATED STATEMENT OF CAPITALIZATION
========================================================================================= September 30, 1996 1995 ----------------------------------------------------------------------------------------- (Thousands of Dollars) Common Equity Common stock, $.33 1/3 par value, authorized 70,000,000 shares; outstanding 49,857,448 and 48,788,320 shares, respectively $ 549,835 $ 522,581 Retained earnings (See accompanying statement) 355,973 303,709 ------------------------------------------------------------------------------------------ 905,808 826,290 ------------------------------------------------------------------------------------------ Preferred Stock, Redeemable $100 par value, cumulative, authorized 900,000 shares 4.60% Series B, 69,000 and 72,000 shares outstanding, respectively 6,900 7,200 Less: Current sinking fund requirements 300 300 ------------------------------------------------------------------------------------------ 6,600 6,900 ------------------------------------------------------------------------------------------ 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 8 3/4% Series 1985 due July 2015 - 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 5.5% Series 1996 due January 2021 153,500 - 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 Unamortized premium - Long-term debt (1,489) - Subsidiary borrowings 65,002 72,069 ----------------------------------------------------------------------------------------- 712,013 720,569 ----------------------------------------------------------------------------------------- $ 1,624,421 $ 1,553,759 ========================================================================================= The accompanying Summary of Significant Accounting Policies and Basis for Financial Statement Presentation and Notes to Consolidated Financial Statements are integral parts of these statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
============================================================================================================== For the Year Ended September 30, 1996 1995 1994 -------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 122,908 $ 91,835 $ 87,384 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and depletion 83,006 77,696 75,386 Deferred Federal income tax 25,985 11,037 10,897 Gain on sale of investment in Canadian operations (16,160) - - Gain on sale of subsidiary stock (35,437) - - Income from energy services investments (13,523) (9,458) (5,689) Dividends received from energy services investments 11,031 3,595 4,392 Change in accounts receivable, net (24,939) 44,712 31,906 Change in accounts payable 39,856 (29,283) (34,121) Gas inventory and prepayments 777 6,208 5,498 Other 8,863 14,439 18,474 --------------------------------------------------------------------------------------------------------------- Cash provided by operating activities 202,367 210,781 194,127 --------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Sale of common stock 27,407 27,974 29,828 Proceeds from sale of subsidiary stock 101,041 - - Common stock proceeds receivable - - 44,910 Issuance of long-term debt 153,500 19,192 12,077 Repayments of long-term debt and preferred stock (160,867) (300) (300) Dividends paid (70,614) (67,566) (64,003) ---------------------------------------------------------------------------------------------------------------- Cash provided by (used for)financing activities 50,467 (20,700) 22,512 ---------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (excluding allowance for equity funds used during construction) (301,307) (212,732) (197,496) Proceeds from sale of investment in Canadian plant 26,938 - 11,691 Partnership distribution 1996 and other 22,914 9,702 1,398 ---------------------------------------------------------------------------------------------------------------- Cash used in investing activities (251,455) (203,030) (184,407) ---------------------------------------------------------------------------------------------------------------- Change in Cash and Temporary Cash Investments 1,379 (12,949) 32,232 Cash and Temporary Cash Investments at Beginning of Year 40,542 53,491 21,259 ---------------------------------------------------------------------------------------------------------------- Cash and Temporary Cash Investments at End of Year $ 41,921 $ 40,542 $ 53,491 ================================================================================================================ 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 $ 37,053 $ 36,000 $ 36,900 Interest $ 53,210 $ 53,047 $ 50,872 ================================================================================================================ The accompanying Summary of Significant Accounting Policies and Basis for Financial Statement Presentation and Notes to Consolidated Financial Statements 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, 1996 1995 1994 (Thousands of Dollars) Operating Expenses Current $ 27,766 $ 31,676 $ 38,403 Deferred 11,742 10,313 2,153 39,508 41,989 40,556 Other Income Current 6,559 379 (7,528) Deferred 14,243 724 8,744 Amortization of investment tax credits (941) (1,052) (1,074) 19,861 51 142 Total Federal income tax $ 59,369 $ 42,040 $ 40,698
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, 1996 1995 (Thousands of Dollars) Utility property $ 176,565 $ 180,708 Gas production and other property 69,488 49,402 Net tax regulatory asset 26,210 28,214 Other 9,778 (10,442) Net deferred income tax liability $ 282,041 $ 247,882
The following is a reconciliation between reported income tax and tax computed at the statutory rate of 35%:
Year Ended September 30, 1996 1995 1994 (Thousands of Dollars) Computed at statutory rate $ 63,797 $ 46,856 $ 44,828 Adjustments related to: Gas production tax credits (1,962) (2,730) (1,303) Nontaxable interest income (678) (870) (556) Amortization of investment tax credits (941) (1,052) (1,074) Other, net (847) (164) (1,197) Total Federal income tax $ 59,369 $ 42,040 $ 40,698 Effective income tax rate 33% 31% 32%
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's funding policy for pensions is in accordance with requirements of Federal law and regulations. There were no pension contributions in 1996, 1995 and 1994. Special retirement programs were initiated in 1995 and 1994. The calculation of net periodic pension cost follows:
Year Ended September 30, 1996 1995 1994 (Thousands of Dollars) Service cost, benefits earned during the year $ 15,160 $ 11,533 $ 15,100 Special retirement charge - 5,416 8,465 15,160 16,949 23,565 Interest cost on projected benefit obligation 37,128 35,128 29,511 Return on plan assets (78,930) (82,626) (12,430) Net amortization and deferral 31,745 34,786 (32,798) Total pension cost $ 5,103 $ 4,237 $ 7,848
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, 1996 1995 (Thousands of Dollars) Actuarial present value of benefit obligations: Vested $(414,988) $(401,159) Accumulated $(439,278) $(423,434) Projected $(563,852) $(545,825) Plan assets at fair value $ 608,080 $ 555,906 Plan assets in excess of projected benefit obligation $ 44,228 $ 10,081 Unrecognized net loss (gain) from past experience different from that assumed and from changes in assumptions (32,755) 10,880 Unrecognized transition asset (27,914) (32,566) Accrued pension liability $ (16,441) $ (11,605) Assumptions: Obligation discount 7.25% 7.00% Asset return 7.75% 7.50% Average annual increase in compensation 5.50% 5.50%
B. Other - 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 in a tax effective manner as part of its overall strategy to manage the costs of its benefit programs for employees. Net periodic other postretirement benefit cost included the following components:
Year Ended September 30, 1996 1995 (Thousands of Dollars) Service cost, benefits earned during the year $ 3,178 $ 2,590 Interest cost on accumulated postretirement benefit obligation 10,673 9,958 Return on plan assets (9,382) (6,746) Net amortization and deferral 10,961 6,752 Other postretirement benefit cost $15,430 $12,554
The following table sets forth the plans' funded status, reconciled with amounts recognized in the Company's Consolidated Balance Sheet:
September 30, 1996 1995 (Thousands of Dollars) Actuarial present value of accumulated postretirement benefit obligation Retirees $ (88,278) $ (87,022) Fully eligible active plan participants (18,271) (10,980) Other active plan participants (63,762) (56,157) $(170,311) $(154,159) Plan assets at fair value, primarily stocks and bonds $ 93,452 $ 72,638 Accumulated postretirement benefit obligation in excess of plan assets $ (76,859) $ (81,521) Unrecognized net loss from past experience different from that assumed and from changes in assumptions 29,285 25,345 Unrecognized transition obligation 64,015 67,781 Prepaid other postretirement benefit $ 16,441 $ 11,605 Assumptions: Obligation discount 7.25% 7.00% Asset return 7.75% 7.50%
The measurement also assumes a health care cost trend rate of 8.5% annually 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, 1996 and the net periodic SFAS-106 expense by approximately $23,825,000 and $1,935,000, respectively. 3. THE HOUSTON EXPLORATION COMPANY (THEC) Certain former employees of Fuel Resources Inc., the subsidiary of the Company that previously owned certain onshore natural gas and oil producing properties and acreage, were entitled to receive remuneration for the increase in the value of these properties should these properties be sold or transferred. These former employees were paid, and a reorganization charge of $12.0 million was recorded in operation and maintenance expense in the accompanying Consolidated Statement of Income as a result of the transfer of these properties to THEC in 1996. In September, 1996, THEC completed an initial public offering (the IPO) of 7,130,000 shares of its common stock at an offering price of $15.50 per share. The cash proceeds to THEC from the IPO, after deductions for commissions and offering expenses, were $101.0 million and were used to repay a portion of THEC's short-term borrowings incurred as a result of two major acquisitions in 1996 of properties and proved gas reserves for $84.7 million. One of these acquisitions also required THEC to issue, in conjunction with the IPO, 762,387 shares (the number of shares being determined by the IPO price) of its common stock as consideration for the $11.8 million portion of the acquisition's purchase price that was to be funded with THEC's stock. Further, in September 1996, THEC issued, also in conjunction with the IPO, 145,161 shares of its common stock to its President for certain of his working interests, valued at $2.3 million, in properties owned by THEC. As a result of these three stock issuances, the Company's ownership in THEC was reduced from 100% to approximately 66% and the Company recorded a $35.4 million gain ($23.0 million after tax) in recognition of the net increase in the book value of the Company's investment in THEC. 4. FIXED OBLIGATIONS A. Leases: Lease costs included in operation expense were $13,894,000 in 1996, $14,706,000 in 1995 and $15,547,000 in 1994. The future minimum lease payments under the Company's various leases, all of which are operating leases, are approximately $14,143,000 per year over the next five years and $149,547,000 in the aggregate for years thereafter. The Company has a lease agreement with a remaining term of 15 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 remaining terms that cover from one to seventeen years. Certain of these contracts require payment of monthly charges in the aggregate amount of approximately $4.3 million per month in all events and regardless of the level of service available. Such charges are recovered as gas costs. 5. CAPITALIZATION A. Common and Preferred Stock: In 1996 and 1995, the Company issued 1,069,128 and 1,198,305 shares of common stock for $27,407,000 and $27,974,000, respectively, under the Dividend Reinvestment and Stock Purchase Plan, the Discount Stock Purchase Plan for Employees, and the Employee Savings Plan. At September 30, 1996, 2,355,942 unissued shares of common stock were reserved for issuance under these plans. 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 7 1/8% Series 1985 I and 7% Series 1985 II Gas Facilities Revenue Bonds became callable on December 1, 1996, at the optional redemption price of 102% of par value plus accrued interest. The Company is seeking authorization of government agencies for the call and refunding of these bond issues. C. Other Long-Term Debt: THEC has a $150 million unsecured line of credit which for the most part supports borrowings under a revolving loan agreement. Up to $5 million of this line is available for the issuance of letters of credit to support performance guarantees. This credit facility matures on July 1, 2000. At September 30, 1996, borrowings of $65 million were outstanding under this line of credit and $1.6 million was committed under outstanding letter of credit obligations. Borrowings under this facility bear interest, at THEC's option, at rates indexed at a premium to the Federal Funds rate or LIBOR, or based on the prime rate. The interest rate on this debt was 6.5% per annum at fiscal year-end. Covenants related to this line of credit require the maintenance of certain financial ratios and involve other restrictions regarding cash dividends, the purchase or redemption of stock and the pledging of assets. 6. STOCK OPTIONS AND AWARDS On November 15, 1995, the Company implemented the Long-Term Performance Incentive Compensation Plan and granted 202,800 nonqualified stock options and 13,000 performance shares to officers. The number of shares of Common Stock reserved for issuance under this Plan is 1,500,000 in the aggregate; however, no more than 750,000 shares will be available for issuance pursuant to the exercise of the stock options. The stock options were awarded at an exercise price of $27.00 (the fair market value on the grant date). They vest ratably over a three-year period from the grant date with a ten-year exercise period. The stock options were not exercisable as of September 30, 1996. The performance shares granted represent the target number of shares, as defined under the Plan, that will vest at the end of a three-year performance period ending on September 30, 1998. The actual number of performance shares to be earned is contingent upon achieving target levels of total shareholder return in relation to the Standard & Poor's Utilities Index. The actual awards will range from 0 to 200% of the target number of shares. In October 1995, the FASB issued Statement No. 123, "Accounting for Stock-Based Compensation". This statement requires companies to either recognize compensation costs attributable to employee stock options (or similar equity instruments) in net income or, in the alternative, provide pro forma footnote disclosure on net income and earnings per share. Implementation of this statement is required in the Company's 1997 fiscal year. The Company does not anticipate that the provisions of this statement will have a material effect on the Company's net income. 7. 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, 1996 and 1995 was $660,499,600 and $673,408,300, 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 current 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, 1996 and 1995, the fair value of this stock was $4,958,300 and $5,228,800, respectively, and the carrying value was $6,600,000 and $6,900,000, respectively. All other financial instruments included in the Consolidated Balance Sheet are stated at amounts that approximate fair values. B. Derivative Financial Instruments: The Company and THEC employ derivative financial instruments - natural gas futures, options 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 oil prices. The Company uses derivatives, primarily futures, to fix profit margins on specified portions of the sales to this market in line with pricing objectives. Implementation of the strategy involves establishment of long (buy) positions in gas futures contracts with offsetting short (sell) positions in oil futures contracts of equivalent energy value that are capped by options over the same time period. The long gas futures position follows, generally within a range of 80% to 120%, the cost of gas to serve this market while the short oil futures position correspondingly replicates, within the same range, the selling price of gas. The Company has developed a strong sense of the relationship between gas and oil prices in the target markets, and the implementation of its strategy has satisfactorily hedged its exposure to the loss of profit margins on the desired portion of anticipated sales. With respect to natural gas production operations, THEC generally uses swaps and standard New York Mercantile Exchange futures contracts or options to hedge the price risk related to known production plans and capabilities. These instruments include a fixed price/volume and the swaps are structured as both straight and participating swaps. In all cases, THEC 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. Two participating swap contracts covering 1,860,000 and 930,000 Mcf in 1997 and 1998, respectively, are priced at $1.98 and $2.05. The volumes under these two swaps are reduced by 50% in each month where the NYMEX prices for that month exceed the fixed price under the swap contract. The following table summarizes the notional amounts and related fair values of the Company's derivative financial instrument positions outstanding at September 30, 1996. Fair values are based on quotes for the same or similar instruments. Differences between the notional contract amounts and fair values represent implicit gains on gas contracts representing long positions or losses on oil contracts representing short positions if the instruments were settled at market. __________________________________________________________________
Gas Type of Fiscal Year Fixed Price Volume Notional Fair Instrument of Maturity per Mcf (Mcf) Amount Value (in thousands) Futures contracts 1997 $1.97-$2.39 13,630,000 $30,447 $30,613 Options 1997 $2.30-$3.00 3,020,000 $ - $ 964 Swap contracts 1997 $1.53-$2.09 16,858,000 $32,219 $32,165 1998 $1.53-$2.09 4,280,000 $ 8,054 $ 8,166
Oil Type of Fiscal Year Fixed Price Volume Notional Fair Instrument of Maturity per Gallon (Gallons) Amount Value (in thousands) Futures contracts 1997 $0.49-$0.58 122,556,000 $66,297 $81,530 1998 $0.52 6,342,000 $ 3,315 $ 3,592 Options 1997 $0.13-$0.22 63,672,000 $ 211 $ 1,018 __________________________________________________________________
Futures contracts expire and are renewed monthly. As of September 30, 1996, no such contract extended beyond January 1998. Further, swaps contracts are settled monthly and extend through March 1998. Margin deposits with brokers at September 30, 1996 and 1995 amounted to $23,619,000 and $1,662,400, respectively, and are recorded in Other in the current assets section of the balance sheet. Deferred gains (losses) on closed positions were $1,330,000 and ($748,000) at September 30, 1996 and 1995, respectively. The Company and THEC are exposed to credit risk in the event of nonperformance by counterparties to derivative 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, options and swap 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. 8. INVESTMENT IN IROQUOIS PIPELINE A Company subsidiary, North East Transmission Co., Inc. (NETCO), owns a 19.4% partnership interest in Iroquois Gas Transmission System, L.P. (Iroquois). Iroquois owns a 375-mile pipeline extending from Canada to the Northeast United States. NETCO's investment in Iroquois was $35.4 million at September 30, 1996. In 1992 Iroquois was informed that Federal criminal and civil investigations of the construction of certain of its pipeline facilities had been commenced. The investigations were to determine whether Iroquois violated various environmental and other laws in the construction of such facilities. In addition, beginning in late 1993, Iroquois was informed by the Federal Energy Regulatory Commission (FERC), the Army Corps of Engineers, the U.S. Department of Transportation (DOT) and the New York State Public Service Commission that each of these agencies had also commenced investigations regarding the construction of pipeline facilities. On May 23, 1996, as part of a comprehensive resolution of these investigations, Iroquois Pipeline Operating Company (IPOC), the operator of the pipeline, pleaded guilty to four felony violations of the Clean Water Act and entered into consent decrees under the Clean Water Act in four federal judicial districts. Although not a named defendant, Iroquois signed the plea agreement and consent decrees and is bound by their terms. Iroquois also entered into a related settlement with the State of New York. Under these various agreements, Iroquois and IPOC agreed to pay $22 million in fines and penalties, agreed to remediate 27 wetlands along the length of the pipeline, and agreed to implement under FERC and DOT orders two ten-year plans to address certain ground stability and pipeline safety concerns. Iroquois also entered into a separate settlement with the FERC. In September 1995, a provision was made in the Company's Consolidated Statement of Income for NETCO's share of the estimated settlement costs. This provision was adequate to account for NETCO's share of the above costs. 9. 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. The Company executed a consent order with the DEC 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 (City). The Company and the City are 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. Based upon the Coney Island site consent order and the estimated costs of investigation of the City site, the Company believes that the minimum cost of MGP-related environmental cleanup will be approximately $34 million, based upon current information, primarily for the Coney Island site. 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, 1996, the Company had an unpaid liability of $28.4 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. Recovery of these costs began in fiscal year 1995, and is conditioned upon 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 responsible parties and insurance sources. Moreover, the rate agreement that became effective on October 1, 1996, described in "Rate and Regulatory Matters" of Management's Discussion and Analysis of Results of Operations and Financial Condition, provides, among other things, that if the total cost of investigating and remediating the Coney Island site plus the cost of investigating the City site varies from the amount originally accrued for these activities, the Company will retain or absorb 10% of the variation. Under the rate agreement, similar ratemaking treatment will be available for any additional accrued liabilities for other MGP sites, should such accrual be required. NOTE 10. SUPPLEMENTAL GAS AND OIL DISCLOSURES (Unaudited) This information includes amounts attributable to a 34% minority interest in THEC at September30, 1996. In addition, gas and oil operations, and reserves, were predominantly located in the United States in all years.
CAPITALIZED COSTS RELATING TO GAS AND OIL PRODUCING ACTIVITIES - --------------------------------------------------------------------------- September 30, 1996 1995 - ---------------------------------------------------------------------------- (Thousands of Dollars) Unproved properties not being amortized $60,137 $35,082 Properties being amortized-productive and nonproductive 441,024 299,398 - --------------------------------------------------------------------------- Total capitalized costs 501,161 334,480 Accumulated depletion (160,128) (132,809) - --------------------------------------------------------------------------- Net capitalized costs $341,033 $201,671 - --------------------------------------------------------------------------- At September 30, 1996 and 1995, the Company had an immaterial deficiency in its asset ceiling test; however, such deficiency was eliminated by subsequent increases in the price of natural gas.
The following is a break-out of the costs (in thousands of dollars) which are excluded from the amortization calculation as of September 30, 1996, by year of acquisition: 1996-$36,557; 1995-$13,312; and prior years-$10,268. 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 - ------------------------------------------------------------------- 1996 1995 1994 - ------------------------------------------------------------------- (Thousands of Dollars) Acquisition of properties- Unproved properties $24,577 $10,996 $11,022 Proved properties 89,828 14,983 28,370 Exploration 20,828 5,907 18,961 Development 31,005 37,953 9,781 - ------------------------------------------------------------------ Total costs incurred $166,238 $69,839 $68,134 - ------------------------------------------------------------------
RESULTS OF OPERATIONS FROM GAS AND OIL PRODUCING ACTIVITIES - ------------------------------------------------------------------ 1996 1995 1994 - ------------------------------------------------------------------ (Thousands of Dollars) Revenues from gas and oil producing activities- Sales to unaffiliated parties $50,431 $40,810 $41,185 Sales to affiliates - - 2,023 - ------------------------------------------------------------------ Revenues 50,431 40,810 43,208 - ------------------------------------------------------------------ Production and lifting costs 8,860 5,762 5,360 Depletion 27,368 22,906 24,978 - ------------------------------------------------------------------ Total expenses 36,228 28,668 30,338 - ------------------------------------------------------------------ Income before taxes 14,203 12,142 12,870 Income taxes 3,037 1,957 3,306 - ------------------------------------------------------------------ Results of gas and oil producing activities (excluding corporate overhead and interest costs) $11,166 $10,185 $9,564 ==================================================================
10. 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 for each 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 was prepared by applying year-end prices of gas and oil to the Company's proved reserves, except for those reserves devoted to future production that is hedged. These reserves are priced at their respective hedged amount. The standardized measure 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) - --------------------------------------------------------------- 1996 1995 1994 - --------------------------------------------------------------- Proved Reserves- Beginning of Year 195,055 142,858 108,847 Revisions of previous estimates (354) 13,539 (2,297) Extensions and discoveries 13,139 38,985 25,890 Production (26,435) (21,822) (22,814) Purchases of reserves in place 134,325 21,495 34,931 Sales of reserves in place (1,189) - (1,699) - --------------------------------------------------------------- Proved Reserves- End of Year 314,541 195,055 142,858 - --------------------------------------------------------------- Proved Developed Reserves- Beginning of Year 151,594 110,225 100,454 - --------------------------------------------------------------- End of Year 222,522 151,594 110,225 ===============================================================
Crude Oil, Condensate and Natural Gas Liquids (MBbls) - --------------------------------------------------------------- 1996 1995 1994 - --------------------------------------------------------------- Proved Reserves- Beginning of Year 1,162 807 443 Revisions of previous estimates (148) 245 (140) Extensions and discoveries 182 155 155 Production (136) (148) (96) Purchases of reserves in place 294 103 495 Sales of reserves in place (106) - (50) - --------------------------------------------------------------- Proved Reserves- End of Year 1,248 1,162 807 - --------------------------------------------------------------- Proved Developed Reserves- Beginning of Year 974 543 407 - --------------------------------------------------------------- End of Year 1,040 974 543 - ---------------------------------------------------------------
10. SUPPLEMENTAL GAS AND OIL DISCLOSURES (CONTINUED) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED GAS AND OIL RESERVES
- --------------------------------------------------------------- 1996 1995 - --------------------------------------------------------------- (Thousands of Dollars) Future cash flows $554,798 $314,627 Future costs- Production (89,303) (57,941) Development (60,926) (29,948) - --------------------------------------------------------------- Future net inflows before income tax 404,569 226,738 Future income taxes (59,623) (43,705) - --------------------------------------------------------------- Future net cash flows 344,946 183,033 10% discount factor (85,688) (49,512) - --------------------------------------------------------------- Standardized measure of discounted future net cash flows $259,258 $133,521 - ---------------------------------------------------------------
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVE QUANTITIES
- ---------------------------------------------------------------- 1996 1995 1994 - ---------------------------------------------------------------- (Thousands of Dollars) Standardized measure- beginning of year $133,521 $108,134 $110,406 Sales and transfers, net of production costs (41,571) (35,048) (37,848) Net change in sales and transfer prices, net of production costs 44,719 (2,786) (25,005) Extensions and discoveries and improved recovery, net of related costs 18,894 28,868 15,536 Changes in estimated future development costs (4,798) (2,351) (1,016) Development costs incurred during the period that reduced future development costs 15,056 10,360 6,381 Revisions of quantity estimates (2,338) 13,858 (2,917) Accretion of discount 16,880 11,763 12,397 Net change in income taxes 21,026 (7,856) 4,001 Purchases of reserves in place 94,945 15,176 27,561 Sales of reserves in place - - (2,110) Changes in production rates (timing) and other (37,076) (6,597) 748 - ------------------------------------------------------------------ Standardized measure-end of year $259,258 $133,521 $108,134 - ------------------------------------------------------------------
10. SUPPLEMENTAL GAS AND OIL DISCLOSURES (CONTINUED)
Average Sales Prices and Production Costs - Per Unit - ------------------------------------------------------------------ For the year ended September 30, 1996 1995 1994 - ------------------------------------------------------------------ Average Sales Price* Natural Gas ($/MCF) 2.11 1.47 1.97 Oil, Condensate and Natural Gas Liquid ($/Bbl) 19.21 16.92 15.63 Production Cost Per Equivalent MCF ($) .32 .25 .23 - ------------------------------------------------------------------
Acreage - ------------------------------------------------------------------ As of September 30, 1996 Gross Net - ------------------------------------------------------------------ Producing 258,798 160,154 Undeveloped 111,087 88,554 - ------------------------------------------------------------------
Number of Producing Wells - ------------------------------------------------------------------ As of September 30, 1996 Gross Net - ------------------------------------------------------------------ Gas Wells 1,114 678 Oil Wells 11 3 - ------------------------------------------------------------------
Drilling Activity (Net) - ------------------------------------------------------------------ For the year ended September 30, 1996 1995 1994 Pro- Pro- Pro- ducing Dry Total ducing Dry Total ducing Dry Total Net Develop- mental Wells 10.1 0.8 10.9 10.0 3.4 13.4 6.6 - 6.6 Net Explora- tory Wells 2.1 3.4 5.5 1.4 0.4 1.8 2.5 1.2 3.7 - -------------------------------------------------------------------
Wells in Process As of September 30, 1996 Gross Net Exploratory 4.0 1.1 Developmental 2.0 1.1 - -------------------------------------------------------------------
* Represents the cash price received which excludes the effect of any hedging transactions. SUPPLEMENTARY INFORMATION (UNAUDITED) QUARTERLY INFORMATION SUMMARY OF QUARTERLY INFORMATION The following is a table of financial data for each quarter of fiscal 1996 and 1995. 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) 1996 Operating revenues 398,083 595,438 254,311 184,170 Operating income(loss) 57,400 88,505 5,495 (20,842)(a) Gains on sale of subsidiary stock and Canadian plant (after taxes) - - - 33,539 Income (loss) applicable to common stock 44,624 74,413 (4,561) 8,109 Per common share: Earnings (loss) (b) 0.91 1.51 (0.09) 0.16 Dividends declared 0.3550 0.3550 0.3550 0.3550 - -------------------------------------------------------------------------- 1995 Operating revenues 358,348 481,615 217,696 158,625 Operating income(loss) 54,580 85,364 5,650 (10,250) Income (loss) applicable to common stock 42,753 73,555 (6,188) (18,622) Per common share: Earnings (loss) (b) 0.90 1.53 (0.13) (0.38) Dividends declared 0.3475 0.3475 0.3475 0.3475 =========================================================================
(a) Includes a subsidiary reorganization charge of $7.8 million after taxes. (b) 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 ============================================================================ 1996 High 29 5/8 29 7/8 27 1/2 28 1/8 Low 24 5/8 25 3/4 24 7/8 24 7/8 Close 29 1/4 26 3/4 27 1/4 27 7/8 Shares Traded (000) 3,710 3,884 5,121 3,592 - ---------------------------------------------------------------------------- 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 ============================================================================
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 33 through 39 of the Company's Prospectus/Proxy Statement, dated December 20, 1996, for its Annual Meeting of Shareholders to be held on February 6, 1997. Information regarding the Company's executive officers, who are elected annually by the directors, is found on page 52 hereof. Item 11. Executive Compensation Information regarding compensation of the Company's executive officers is incorporated herein by reference to pages 39 through 47 of the Company's Prospectus/Proxy Statement, dated December 20, 1996, for its Annual Meeting of Shareholders to be held on February 6, 1997. Item 12. Security Ownership of Certain Beneficial Owners and Management Information regarding beneficial ownership and management ownership is incorporated herein by reference to "Proposal (2) - Election of Directors of Brooklyn Union" in the Company's Prospectus/Proxy Statement, on pages 37 and 38, dated December 20, 1996, for its Annual Meeting of Shareholders to be held on February 6, 1997. 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 26 Summary of Significant Accounting Policies and Basis of Financial Statement Presentation 27 Consolidated Statement of Income for the Years Ended September 30, 1996, 1995 and 1994 30 Consolidated Statement of Retained Earnings for the Years Ended September 30, 1996, 1995 and 1994 30 Consolidated Balance Sheet at September 30, 1996 and 1995 31 Consolidated Statement of Capitalization at September 30, 1996 and 1995 32 Consolidated Statement of Cash Flows for the Years Ended September 30, 1996, 1995 and 1994 33 Notes to Consolidated Financial Statements 34 (a) 2. Financial Statement Schedules 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 1996 In Such Capacity Business Experience in Past 5 Years Robert B. Catell, Chairman 59 1996 to Present Chairman and Chief Executive Officer and Chief Executive Officer 1991 to 1996 President and Chief Executive Officer 1990 to 1991 President and Chief Operating Officer Craig G. Matthews, President 53 1996 to Present President and Chief Operating Officer and Chief Operating Officer 1994 to 1996 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 64 1996 to Present Vice Chairman Vice Chairman 1992 to 1996 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 55 1992 to Present Senior Vice President Senior Vice President 1989 to 1992 Vice President Vincent D. Enright, Senior Vice 52 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 46 1994 to Present Senior Vice President Senior Vice President 1989 to 1994 Vice President Wallace P. Parker, Jr. 47 1994 to Present Senior Vice President Senior Vice President 1990 to 1994 Vice President Lenore F. Puleo 43 1994 to Present Senior Vice President Senior Vice President 1990 to 1994 Vice President Maurice K. Shaw, Senior Vice 57 1993 to Present Senior Vice President and Corporate President and Corporate Affairs Officer Affairs Officer 1987 to 1993 Senior Vice President and Chief Marketing Officer Edward J. Sondey 58 1992 to Present Senior Vice President Senior Vice President 1981 to 1992 Vice President Tina G. Barber, Vice President 47 1994 to Present Vice President and Chief and Chief Information Officer Information Officer 1992 to 1994 Vice President Richard M. Desmond, Vice 62 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 59 1992 to Present Vice President and Chief Engineer and Chief Engineer 1987 to 1992 Vice President Roger J. Walz, Vice President 51 1990 to Present Vice President and General Auditor and General Auditor Robert R. Wieczorek, Vice President, 54 1994 to Present Vice President, Secretary Secretary and Treasurer and Treasurer 1989 to 1994 Vice President, Treasurer, and Assistant Secretary
(a) 3. Exhibits (3) Articles of incorporation and by-laws By-laws of the Company, dated February 1, 1996, duly filed in December 1996 as Exhibit 3(b) on KeySpan Energy Corporation's Form S-4. 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 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. Official Statement, dated January 15, 1996, respective of $153,500,000 of the New York State Energy Research and Development Authority, 5 1/2% Gas Facilities Revenue Bonds Series 1996, replacing $98,500,000 Series 1985A and $55,000,000 Series 1985. Participation Agreement, dated January 1, 1996, between the New York Energy Research and Development Authority and The Brooklyn Union Gas Company relating to the Gas Facilities Revenue Bonds Series 1996. Indenture of Trust, dated January 1, 1996, between The New York State Energy Research and Development Authority and Chemical Bank, as Trustee, relating to the Gas Facilities Revenue Bonds Series 1996. (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. Long-Term Performance Incentive Compensation Plan, dated November 15, 1995. (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 were no reports filed on Form 8-K during the quarter ended September 30, 1996. 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 11, 1996. THE BROOKLYN UNION GAS COMPANY Signature Title s/Robert B. Catell Chairman and Chief Executive (Robert B. Catell) Officer s/Craig G. Matthews President and Chief Operating (Craig G. Matthews) Officer 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/James Q. Riordan Director (James Q. Riordan) s/Charles Uribe Director (Charles Uribe) 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, 1996 1995 1994 1993 1992 _________ _________ _________ _________ _________ (Thousands of Dollars) Earnings Net Income $ 122,908 $ 91,835 $ 87,384 $ 76,563 $ 59,873 Federal Income Tax 59,369 42,040 40,698 41,483 29,219 Interest on Long-Term Debt 46,803 47,939 48,084 46,353 40,990 Other Interest Charges 4,918 5,128 2,787 2,617 2,046 Portion of Rentals Representing Interest 4,626 4,883 5,196 4,256 5,310 Adjustment Related to Equity Investments (1,005) 174 (601) 729 3,239 Earnings Available to Cover --------- --------- --------- --------- --------- Fixed Charges $ 237,619 $ 191,999 $ 183,548 $ 172,001 $ 140,677 ========= ========= ========= ========= ========= Fixed Charges Interest on Long-Term Debt* $ 50,067 $ 50,521 $ 49,280 $ 47,017 $ 41,766 Other Interest Charges 4,918 5,128 2,787 2,617 2,046 Portion of Rentals Representing Interest 4,626 4,883 5,196 4,256 5,310 --------- --------- --------- --------- --------- Total Fixed Charges $ 59,611 $ 60,532 $ 57,263 $ 53,890 $ 49,122 ========= ========= ========= ========= ========= Ratio of Earnings to Fixed Charges 3.99 3.17 3.21 3.19 2.86 ========= ========= ========= ========= ========= * Includes capitalized interest of $3,264,000 in 1996, $2,582,000 in 1995, $1,196,000 in 1994 $664,000 in 1993 and $776,000 in 1992.
EX-21 3 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 Nos. 33-66182, 333-04863, 333-03441, 333-06257 and 333-18025. ARTHUR ANDERSEN LLP December 18, 1996 New York, New York EX-27 5
UT 0000014525 BROOKLYN UNION GAS CO. 1 U.S. DOLLARS 12-MOS SEP-30-1996 OCT-01-1995 SEP-30-1996 1 PER-BOOK 1,352,964,000 460,683,000 353,883,000 122,073,000 0 2,289,603,000 16,619,000 533,216,000 355,973,000 905,808,000 0 6,600,000 712,013,000 0 0 0 0 300,000 0 0 664,882,000 2,289,603,000 1,432,002,000 39,508,000 1,261,936,000 1,301,444,000 130,558,000 44,071,000 174,629,000 51,721,000 122,908,000 323,000 122,585,000 70,291,000 44,038,000 202,367,000 2.48 2.48
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