-----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, ThPN1E6wO/qBw/CWIyt86nYKowfw1wDG0oNrpO5ReFJ6PKaS/AVyCuBFKcEfjxn+ SL2HdqNMfuec1KFpBA4oDw== 0000950156-00-000168.txt : 20000313 0000950156-00-000168.hdr.sgml : 20000313 ACCESSION NUMBER: 0000950156-00-000168 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 12 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000310 FILER: COMPANY DATA: COMPANY CONFORMED NAME: EASTERN ENTERPRISES CENTRAL INDEX KEY: 0000311259 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS DISTRIBUTION [4924] IRS NUMBER: 041270730 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-02297 FILM NUMBER: 565139 BUSINESS ADDRESS: STREET 1: 9 RIVERSIDE RD CITY: WESTON STATE: MA ZIP: 02493 BUSINESS PHONE: 7816472300 FORMER COMPANY: FORMER CONFORMED NAME: EASTERN GAS & FUEL ASSOCIATES DATE OF NAME CHANGE: 19890511 10-K 1 EASTERN ENTERPRISES FORM 10-K ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15}D{ OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999 ---------------- COMMISSION FILE NUMBER 1-2297 EASTERN ENTERPRISES 9 Riverside Road, Weston, Massachusetts 02493 (781) 647-2300 MASSACHUSETTS 04-1270730 (State of organization) (I.R.S. Employer Identification No.) ---------------- Securities registered pursuant to Section 12(b) of the Act: NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED Common Stock, par value $1.00 per share New York Stock Exchange Common Stock Purchase Rights, no par value Boston Stock Exchange Pacific Stock Exchange Securities registered pursuant to Section 12(g) of the Act: None 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. Disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, but will be contained in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K. The aggregate market value of the voting stock held by non-affiliates of the registrant was approximately $1,571 million as of February 29, 2000. There were 27,146,679 shares of Common Stock, par value $1.00 per share, outstanding as of February 29, 2000. ---------------- DOCUMENTS INCORPORATED BY REFERENCE Portions of the annual report to shareholders for the year ended December 31, 1999 are incorporated by reference into Part II of this Report. Portions of the Registrant's 2000 definitive Proxy Statement for the Annual Meeting of Shareholders to be held April 26, 2000 are incorporated by reference into Part III of this Report. ---------------- Exhibits to Form 10-K and Financial Statement Schedules have been included only in copies of the Form 10-K filed with the Securities and Exchange Commission. ================================================================================ EASTERN ENTERPRISES ANNUAL REPORT ON FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999 TABLE OF CONTENTS PAGE NO. PART I Item 1. Business 10-K/1 Natural Gas Distribution 10-K/1 Marine Transportation 10-K/6 General 10-K/9 Item 2. Properties 10-K/9 Item 3. Legal Proceedings 10-K/9 Item 4. Submission of Matters to a Vote of Security Holders 10-K/9 PART II Item 5. Market For Registrant's Common Equity and Related Stockholder Matters 10-K/10 Item 6. Selected Financial Data 10-K/10 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 10-K/10 Item 8. Financial Statements and Supplementary Data 10-K/17 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 10-K/40 PART III Item 10. Directors and Executive Officers of the Registrant 10-K/40 Item 11. Executive Compensation 10-K/40 Item 12. Security Ownership of Certain Beneficial Owners and Management 10-K/40 Item 13. Certain Relationships and Related Transactions 10-K/40 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 10-K/40 PART I ITEM 1. BUSINESS 1(a) GENERAL Eastern Enterprises ("Eastern") is an unincorporated voluntary association (commonly referred to as a "Massachusetts business trust") established and existing under a Declaration of Trust dated July 18, 1929, as from time to time amended. Eastern's principal subsidiaries are Boston Gas Company ("Boston Gas"), Colonial Gas Company ("Colonial Gas"), Essex Gas Company ("Essex Gas") and Midland Enterprises Inc. ("Midland"). Boston Gas, Colonial Gas and Essex Gas are regulated utilities that distribute natural gas in eastern and central Massachusetts. Midland is engaged in barge transportation, principally on the Ohio and Mississippi river systems. Other subsidiaries include ServicEdge Partners, Inc. ("ServicEdge"), Transgas, Inc. ("Transgas") and AMR Data Corporation ("AMR Data"). ServicEdge offers heating, ventilation and air conditioning ("HVAC") equipment installation and services to customers in eastern Massachusetts. Transgas is the nation's largest over-the-road transporter of liquefied natural gas ("LNG"). AMR Data provides customized automated metering equipment and services primarily to municipal utilities in the Northeast. On November 4, 1999, Eastern signed a definitive agreement to be acquired by KeySpan Corporation ("KeySpan Energy") for $64.00 in cash per share of Eastern common stock, as described in Note 2 of Notes to Financial Statements. Such information is incorporated herein by reference. The transaction, which is subject to receipt of regulatory approvals and the approval of Eastern shareholders, is expected to close in mid to late 2000, although it is possible that the transaction will not close until 2001. In July 1999 Eastern signed a definitive agreement to acquire EnergyNorth, Inc. ("EnergyNorth") for a combination of stock and cash, as described in Note 3. This agreement was amended in November 1999 in connection with the pending acquisition of Eastern by KeySpan Energy, as discussed in Note 3. EnergyNorth is an energy services holding company headquartered in Manchester, New Hampshire. Its subsidiaries distribute natural gas and propane to approximately 85,000 customers in New Hampshire and provide mechanical contracting and HVAC services for commercial, industrial and institutional customers in northern New England. On August 31, 1999, Eastern completed the acquisition of Colonial Gas and its subsidiary Transgas by the issuance of 4.2 million shares of Eastern common stock valued at $186 million, cash payments, net of cash acquired, of $150 million, and the assumption of $138 million in long term debt. The transaction was accounted for using the purchase method of accounting, as described in Note 4. Eastern provides management services to its operating subsidiaries. Boston Gas, Colonial Gas, Essex Gas and Midland are financed primarily through their own internally generated funds and the issuance of their own funded debt, which is not guaranteed by Eastern. The debt instruments relating to Boston Gas, Colonial Gas, Essex Gas and Midland borrowings generally contain restrictive covenants, including restrictions on the payment of dividends to Eastern. In the opinion of management, none of these restrictions has any material impact upon Eastern and the operations of its subsidiaries. The information in this Form 10-K should be read in conjunction with the "Forward-Looking Information" in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. 1(b) FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS Information with respect to this item may be found in Note 5. 1(c) DESCRIPTION OF BUSINESS NATURAL GAS DISTRIBUTION Eastern's natural gas distribution operations ("LDC group") are comprised of Boston Gas, Colonial Gas and Essex Gas, which together are engaged in the transportation and sale of natural gas to approximately 740,000 residential, commercial, and industrial customers in Boston and 114 other communities in eastern and central Massachusetts. The LDC group also sells natural gas for resale in Massachusetts and other states. Boston Gas serves over 540,000 customers and is the largest natural gas distribution company in New England. Boston Gas has been in business for 177 years and is the second oldest gas company in the United States. Since 1929, all of the common stock of Boston Gas has been owned by Eastern. As described above, Colonial Gas was acquired by Eastern in August 1999 and serves approximately 158,000 10-K/1 customers. Essex Gas was acquired by Eastern in September 1998 and serves approximately 44,000 customers. For definitions of unfamiliar terms, see the Glossary on page Form 10-K/6. The LDC group provides local transportation services and gas supply to all customer classes. The LDC group's services are available on a firm and non- firm basis. Firm transportation services and sales are provided under rate tariffs and/or contracts filed with the Massachusetts Department of Telecommunications and Energy ("Department"), that typically obligate the LDC group to provide service without interruption throughout the year. Non-firm transportation services and sales are generally provided to large commercial/ industrial customers who can use gas or another energy source interchangeably. Non-firm services are provided through individually negotiated contracts and, in most cases, the price charged takes into account the price of the customer's alternative fuel. The LDC group offers unbundled services to all commercial/industrial users, who are allowed to purchase local transportation from the LDC group separately from the purchase of gas supply, which the customer may buy from third party suppliers. The LDC group views these third party suppliers as partners in marketing gas and increasing throughput and expects to work closely with them to facilitate the unbundling process and ensure a smooth transition, especially in the tracking and processing of transactions. The LDC group has also implemented a program to educate commercial/industrial customers about the opportunity to purchase gas from third party suppliers, while still relying on the utility for delivery. As of December 31, 1999, the LDC group had approximately 4,900 firm transportation customers. The chart below reflects the change in composition of firm throughput as customers migrate from bundled sales to transportation-only service. Service is currently provided to all residential customers on a bundled basis. Unbundled service to residential customers is expected to be offered beginning in April 2000. While the migration of customers to transportation-only service will lower the LDC group's revenues, it has no impact on its operating earnings as the LDC group earns all of its margins on the local distribution of gas and none on the resale of the commodity itself. With gross margins unaffected by migration to transportation-only service, the improvement in gross margin per employee, as shown below, reflects the benefit of productivity programs and acquisition synergies. (Bar Chart) FIRM THROUGHPUT (IN BCF) BUNDLED TRANSPORTATION- SALES ONLY Total ----- ---- ----- 1995 101.7 19.4 121.1 1996 101.9 46.0 147.9 1997 98.7 50.3 149.0 1998 85.8 49.4 135.2 1999 87.5 49.1 136.6 (Bar Chart) GROSS MARGIN PER EMPLOYEE ($ IN THOUSANDS) 1995 1996 1997 1998 1999 ---- ---- ---- ---- ---- $171 $187 $198 $201 $229 (Bar Chart) BOSTON AREA WEATHER % COLDER (WARMER) THAN NORMAL 1995 1996 1997 1998 1999 ---- ---- ---- ---- ---- 1.00% 5.00% 3.00% -9.00% -5.00% MARKETS AND COMPETITION The LDC group competes with other fuel distributors, particularly oil dealers, throughout its service territory. GAS THROUGHPUT The following table provides information about the LDC group's throughput during the three years 1997-1999, as measured in billions of cubic feet of natural gas at 1,000 Btu per cubic foot ("Bcf"). For comparability, the table below reflects the annual throughput of all three LDCs for all periods. The reduction in throughput from 1997 to 1998 primarily reflects the warmer weather in 1998, as shown in the chart above. 10-K/2 Years Ended December 31, 1999 1998 1997 ---- ---- ---- Residential 54.9 52.9 57.9 Commercial/Industrial 35.9 36.4 46.1 Off-system sales 5.5 12.7 7.4 ----- ----- ----- Total sales 96.3 102.0 111.4 Transportation of customer-owned gas 63.3 73.0 87.9 Less: Off-system sales (5.6) (12.7) (7.4) ----- ----- ----- Total throughput 154.0 162.3 191.9 ===== ===== ===== Firm throughput 136.6 135.2 149.0 ===== ===== ===== The table above excludes the cumulative effect of adopting the accrual method of revenue recognition, as discussed in Note 15. The one-time effect of this change increased residential, commercial/industrial and transportation throughput in 1998 by 3.3 Bcf, 1.4 Bcf and 0.4 Bcf, respectively. In 1999 residential customers comprised 91% of the LDC group's customer base, while commercial/industrial customers accounted for the remaining 9%. Volumetrically, residential customers accounted for 36% of total throughput and 40% of firm throughput, while commercial/industrial customers accounted for 64% of total throughput and 60% of firm throughput. Approximately 62% of the commercial/industrial customers' total throughput was local transportation of customer-owned gas. No customer, or group of customers under common control, accounted for more than 2% of total firm revenues in 1999. Firm throughput for Sithe Energies, an independent power generator, accounted for 28% of the total transportation of customer-owned gas. GAS SUPPLY The following table provides information about the LDC group's sources of supply during 1997-1999 in Bcf. For comparability, the table provides sources of supply for all three LDCs for all periods. Years Ended December 31, 1999 1998 1997 ---- ---- ---- Natural gas purchases 86.3 91.3 95.4 Underground storage 13.2 14.0 19.1 LNG purchases 4.0 1.6 4.1 ----- ----- ----- Total purchases 103.5 106.9 118.6 ----- ----- ----- Company use, unbilled and other (7.2) (4.9) (7.2) ----- ----- ----- Total sales 96.3 102.0 111.4 ===== ===== ===== Year to year variations in storage gas and unbilled gas reflect variations in end-of-year customer requirements, due principally to weather. Given the ready availability of supply, the LDC group purchased approximately 80% of its peak pipeline supplies in 1999 under short-term and spot contracts. The balance of peak day pipeline requirements was purchased directly from various producers and marketers pursuant to long-term contracts which have been reviewed and approved by the Department or by the Federal Energy Regulatory Commission ("FERC"). Pipeline supplies are transported on interstate pipeline systems to the LDC group's service territory pursuant to long-term contracts. FERC-approved tariffs provide for fixed demand charges for the firm capacity rights under these contracts. The daily and annual capacity and the expiration dates of the interstate pipeline contracts that provide firm transportation service to the LDC group's service territory are as follows: Capacity (in Bcf) ---------------------- Expiration Pipeline Daily Annual Dates - -------- ----- ------ ----- Algonquin Gas Transmission Company ("Algonquin") 0.32 95.1 2000-2012 Tennessee Gas Pipeline Company ("Tennessee") 0.28 103.5 2003-2013 ---- ----- 0.60 198.6 ==== ===== 10-K/3 In addition, the LDC group has firm capacity contracts on interstate pipelines upstream of the Algonquin and Tennessee pipelines to transport natural gas purchased by the LDC group from producing regions to the Algonquin and Tennessee pipelines. The expiration dates for these contracts are similar to those included in the above table. The LDC group has contracted with pipeline companies and others for the storage of natural gas in underground storage fields located in Pennsylvania, New York, Maryland and West Virginia. These contracts provide for storage capacity of 23.2 Bcf and peak day withdrawal capacity of 0.213 Bcf. The LDC group utilizes its existing pipeline contracts to transport gas from the storage fields to its service territory. Supplemental supplies of LNG and propane are purchased from foreign and domestic sources. The LDC group has entered into a portfolio management contract with El Paso Energy Marketing, Inc. ("El Paso"). For a three-year period beginning November 1, 1999, El Paso will provide all of the city gate supply requirements to the LDC group at market prices and will manage certain of the LDCs' upstream capacity, underground storage and firm supply contracts. The Department approved the contract in October 1999. Peak day throughput was 0.864 Bcf and 0.766 Bcf in 1999 and 1998, respectively. The LDC group provides for peak period demand through a least- cost portfolio of pipeline, storage and supplemental supplies. The LDC group considers its annual and peak day sendout capacity, based on its total supply resources, to be adequate to meet the requirements of its firm customers. REGULATION The LDC group's operations are subject to Massachusetts statutes applicable to regulated gas utilities. Rates, gas purchases, pipeline safety regulations, issuances of securities and affiliated party transactions are regulated by the Department. Rates for firm transportation and sales provided by the LDC group are subject to approval by, and are on file with, the Department. In addition, the LDC group has a cost of gas adjustment clause ("CGAC") which allows for the adjustment of billing rates for firm gas sales to enable it to recover the actual cost of gas delivered to firm customers, including the demand charges for capacity on the interstate pipeline system and certain other charges. Boston Gas' rates for local transportation service are governed by a five- year performance-based rate plan approved by the Department in its last rate proceeding in 1996. Boston Gas' local transportation rates are recalculated annually to reflect inflation for the previous 12 months, minus a productivity factor. The plan also provides for penalties if Boston Gas fails to meet specified service quality measures. Rates are capped such that 25% of earnings in excess of a 15% return on ending equity are to be passed back to ratepayers. Similarly, ratepayers are to absorb 25% of any shortfall below a 7% return on ending equity. The final year of the plan ends on October 31, 2002. Boston Gas appealed portions of the Department's performance-based rate plan order to the Massachusetts Supreme Judicial Court ("SJC") in 1997. In an August 1999 decision the SJC vacated the Department order as it relates to the accumulated inefficiencies factor in the productivity factor and the level of service quality penalties. These matters were remanded to the Department for further proceedings. The Department has stated that it would consider in the remand proceedings whether there should be retroactive collection of those charges vacated by the court. The performance-based rate calculation for 1999 resulted in a rate increase of approximately $1.4 million, with no service quality penalties. Boston Gas continues to recover its gas costs under its CGAC. Colonial Gas' and Essex Gas' rates for local transportation service are governed by ten-year rate plans approved by the Department in conjunction with its approval of Eastern's acquisition of these companies. These plans immediately reduced rates for Colonial Gas and Essex Gas customers by 2.2% and 5.0%, respectively, reflecting expected gas supply cost savings passed back through the CGAC. The plans freeze base rates through 2009 in the case of Colonial Gas and 2008 in the case of Essex Gas. The freeze on base rates is subject to adjustment only to take into account certain exogenous factors, such as changes in tax laws, accounting changes, or regulatory, judicial or legislative changes. All of Colonial Gas' and Essex Gas' administrative, operations and maintenance functions have been integrated with those of Boston Gas. In July 1997 the Department directed all ten Massachusetts investor-owned gas distribution companies ("gas utilities") to undertake a collaborative process with other stakeholders, including third party suppliers, customers and others, to develop common principles under which comprehensive gas service unbundling for all gas consumers might proceed. A settlement on model terms and conditions for unbundled transportation service jointly agreed upon by the collaborative participants was approved by the Department on November 30, 1998. Further, on February 1, 1999, the Department ordered the assignment, for a five-year transition period, of Massachusetts gas utility contractual commitments for 10-K/4 upstream capacity on a mandatory, pro rata basis to marketers selling gas to each gas utility's customers. The mandatory assignment method assures that the costs of upstream capacity purchased by a gas utility to serve firm customers will not be absorbed as stranded costs by the gas utility or its remaining bundled service customers during the five-year transition period. Under the Department's order, during the transition period the gas utilities will retain primary responsibility for upstream capacity planning and procurement to support customer requirements and growth. In year three of the transition period, the Department intends to evaluate the extent to which the upstream capacity market for Massachusetts is workably competitive and shorten or lengthen the transition period accordingly. While the Department's order assures the recoverability of stranded costs, if any, for capacity throughout the transition period, there can be no assurance about the recoverability of subsequent potential stranded costs until the Department has addressed the assignment of capacity after the transition period. Eastern was granted an exemption under the Public Utility Holding Company Act of 1935 under Section 3(a)(1) thereof, pursuant to orders of the Securities and Exchange Commission ("SEC") dated February 28, 1955, as amended by orders dated November 3, 1967 and August 28, 1975. Eastern's exemption was confirmed pursuant to orders of the SEC dated September 30, 1998, in conjunction with the Essex Gas acquisition, and August 12, 1999, in conjunction with the Colonial Gas acquisition. SEASONALITY AND WORKING CAPITAL The LDC group's revenues, earnings and cash flows are highly seasonal as the demand for most of its distribution sales and services is for space heating and, therefore, is directly related to variations in temperature conditions. The majority of the LDC group's earnings are generated in the first quarter, with a seasonal loss occurring in the third quarter. Since the bulk of its revenues is billed in the November through April heating season, significant cash flows are generated from late winter to early summer. In addition, while the LDC group pays pipeline demand charges over the entire year, the majority of these charges are billed to customers over the heating season. The lag between payment and billing of demand charges, along with other costs of gas distributed but unbilled, is reflected as deferred gas costs and is financed through short-term borrowings. Short-term borrowings are also required from time to time to finance normal business operations. As a result of these factors, short-term borrowings are generally highest during the late fall and early winter. ENVIRONMENTAL MATTERS The LDC group may have or share responsibility under applicable environmental laws for the remediation of certain former manufactured gas plant sites. Information with respect to environmental matters may be found in Note 14. Such information is incorporated herein by reference. EMPLOYEES As of December 31, 1999, the LDC group had approximately 1,700 employees, approximately 65% of whom were organized in local unions. Collective bargaining agreements for Colonial Gas expire in 2000 and 2001. Collective bargaining agreements with Boston Gas and Essex Gas expire in 2002. PROPERTIES The LDC group operates six LNG facilities in eastern Massachusetts. These facilities enable the LDC group to purchase and store LNG and, at one facility, to liquefy pipeline gas and store the resultant LNG for use in periods of high demand. The LDC group owns and operates four such facilities. In 1999 the LDC group resolved litigation concerning the other two facilities by entering into a new 15-year lease of the facilities. Substantially all the plant assets of Colonial Gas and Essex Gas are encumbered by indentures under First Mortgage Medium-Term Notes and First Mortgage Bonds. On December 31, 1999, the LDC group's distribution system included approximately 10,000 miles of gas mains, 598,000 services and 749,000 active customer meters. A majority of the gas mains consist of cast iron and bare steel pipe, which requires ongoing maintenance and replacement. The LDC group's mains and services generally are located on public ways or private property not owned by it. The LDC group's occupation of such property generally is pursuant to easements, licenses, permits or grants of location. Except as stated above, the principal items of property of the LDC group are owned in fee. In 1999, the LDC group's capital expenditures were $69.3 million. Capital expenditures were principally made for system replacement, system expansion to meet customer demand, and productivity 10-K/5 enhancement initiatives. The LDC group plans to spend approximately $95 million for similar purposes in 2000. The increase in large part reflects the acquisition of Colonial Gas. GLOSSARY -- NATURAL GAS DISTRIBUTION BUNDLED SERVICE -- Two or more services tied together as a single product. Services include gas sales, interstate transportation, local transportation, balancing variations in customer usage, storage and peak shaving. CAPACITY -- The capability of pipelines and supplemental facilities to deliver and/or store gas. COST OF GAS ADJUSTMENT CLAUSE ("CGAC") -- a rate mechanism that allows for the adjustment of billing rates for firm sales that enable LDCs to recover the actual cost of gas delivered to firm customers, including the demand charges for capacity on the interstate pipeline system. FIRM SERVICE -- Sales and/or transportation service provided without interruption throughout the year. Uninterrupted seasonal services are also available for less than 365 days. Firm services are provided either under filed rate tariffs or through individually negotiated contracts. INTERSTATE TRANSPORTATION -- Transportation of gas by an interstate pipeline to the service territory. LDC GROUP -- Boston Gas, Colonial Gas and Essex Gas, together. LIQUEFIED NATURAL GAS ("LNG") -- Natural gas is in liquid form at a temperature near absolute zero. Liquefying natural gas reduces its volume by a factor of 600, which facilitates the storage by LDCs of supplemental supplies needed for peak shaving. LOCAL DISTRIBUTION COMPANY ("LDC") -- A utility that owns and operates a gas distribution system for the delivery of gas supplies from the service territory to end-user facilities. LOCAL TRANSPORTATION SERVICE -- Transportation of gas by an LDC from the connection to the pipeline to the end user. NON-FIRM SERVICE -- Sales and transportation service offered at a lower level of reliability and cost. Under this service, an LDC can interrupt sales or service to a customer on short notice, typically during the winter season. Non-firm services are provided through individually negotiated contracts. In most cases, the price charged takes into account the price of the customer's energy alternative. PEAK SHAVING -- In times of heavy consumption, supplementing available pipeline gas with supplies from underground storage or LNG facilities or with injections of propane. PERFORMANCE-BASED REGULATORY PLAN -- An incentive ratemaking mechanism, typically a price cap plan, where rates are adjusted annually pursuant to a pre-determined formula tied to a measure of inflation, offset by an assumed increase in productivity, subject to the achievement of service quality measures. Rates may also reflect certain exogenous costs that may be incurred. THROUGHPUT -- Gas volume delivered to customers through an LDC's gas distribution system. UNBUNDLED SERVICE -- Service that is offered and priced separately, e.g., segregating the cost of the gas commodity delivered to an LDC's service territory from the cost of local transportation service. Other unbundled services may involve daily or monthly balancing, back-up or stand-by services and pooling. With unbundled services, customers can pick and choose among the offered services. MARINE TRANSPORTATION The marine transportation segment is comprised of Midland Enterprises Inc. and its wholly-owned operating subsidiaries (together "Midland"), which are engaged in the operation of a fleet of towboats and barges, principally on the Ohio and Mississippi rivers and their tributaries, the Gulf Intracoastal Waterway and the Gulf of Mexico. Midland transports dry bulk commodities, a major portion of which is coal. Midland also operates a boat and barge repair facility, a coal dumping terminal, a phosphate rock and phosphate chemical fertilizer terminal, cargo transfer facilities and provides refueling and barge fleeting services. 10-K/6 SALES Midland transported 60.0 million, 59.9 million and 57.0 million tons in 1999, 1998 and 1997, respectively. Tonnage in 1999 was essentially unchanged from 1998 as increased non-coal shipments were offset by a 4% decrease in coal shipments. Tonnage in 1998 grew 5% from 1997 as a result of increased shipments to contract coal customers and new aggregate business acquired in 1998, partly offset by lower grain and export coal demand. Ton miles are the product of tons and distance transported. The chart below, at left depicts ton miles by commodity for the period 1995-1999. The downward trend in coal ton miles reflects the continuing weakness in demand for long-haul export coal transportation markets. Conversely, the increase in grain ton miles in 1999 reflects increased demand for long-haul export grain transportation. (Bar Chart) TON MILES BY COMMODITY (IN BILLIONS) Coal Grain Other ---- ----- ----- 1995 15.20 5.20 16.40 1996 15.70 4.80 15.60 1997 13.60 4.50 15.00 1998 13.30 3.70 15.10 1999 12.60 5.00 15.40 "Other" includes iron, scrap steel, sand, stone, gravel, coke, phosphate, alumina, towing for others and miscellaneous other dry cargo. (Bar Chart) REVENUE & COST PER TON MILE (IN MILLS) 1995 1996 1997 1998 1999 ---- ---- ---- ---- ---- Revenue $7.1 $7.4 $7.1 $7.1 $7.1 Cost $5.7 $6.0 $6.2 $6.5 $6.6 (Bar Chart) BARGE FLEET ADDITIONS 1995 1996 1997 1998 1999 ---- ---- ---- ---- ---- Gross 50 175 58 152 130 Net (24) 76 (128) 112 22 In 1999 ton miles increased 3% reflecting increased exports of grain and imports of steel-related products, both of which increased the average trip length. In 1998 ton miles declined 3% primarily due to an 8% decline in the average length of haul, resulting from lower long-haul coal and grain export tonnage. In addition to changes in ton miles transported, Midland's revenues and net earnings are affected by other factors such as competition, operating conditions and the segment of the river system traveled. For the first half of 1999, operations generally experienced normal seasonal weather patterns; however, drought conditions negatively affected operations in the latter half of the year. In 1998, multiple tropical storms, flooding and lock delays adversely affected operations. The following table summarizes Midland's backlog of transportation and terminaling business under multi-year contracts: December 31, 1999 1998 ----- ----- Tons (in millions) 155.6 128.4 Revenues (in millions) $537.9 $496.6 Portions of revenue backlog not expected to be filled within the current year 80% 74% The 1999 revenue backlog (which is based on contracts that extend beyond December 31, 2000) is shown at prices in effect on December 31, 1999, which are generally subject to escalation/de-escalation adjustments. Since services under many of the multi-year contracts are based on customer requirements, Midland has estimated its backlog based on its forecast of the anticipated requirements of these contract customers. The 21% increase in tonnage backlog from 1998 mainly reflects new multi-year agreements, in addition to extended terms on current multi-year contracts. Partially offsetting these increases are expiring terms of current multi-year contracts as they draw closer to maturity, including those excluded from the calculation as they enter their final year. The revenue backlog increased 8%, as the increase in backlog tonnage was partly offset by a shift in the forecast tonnage to shorter-haul shipments which are priced lower on a per ton basis. Electric utilities, which traditionally have entered into multi-year transportation and coal supply agreements, have generally shortened the term of agreements for a variety of reasons, such as uncertainty caused by the Clean Air Act requirements and increasing competitive pressures resulting from the ongoing deregulation of the electric power industry. These factors have also led to changes in the sourcing of coal by utilities, leading to changes in traffic patterns. 10-K/7 The only significant raw material required by Midland is the diesel fuel to operate its towboats. Diesel fuel is purchased from a variety of sources and Midland regards the availability of diesel fuel as adequate for its operations. SEASONALITY Revenues during winter months tend to be lower than revenues for the remainder of the year due to the freezing of some northern waterways, increased coal consumption by electric utilities during the summer months and the fall harvest of grain. COMPETITION Midland's marine transportation business competes on the basis of price, service and equipment quality and availability. Midland's primary competitors include other barge lines and railroads. There are a number of companies offering transportation services on the waterways served by Midland. Price competition between barge lines intensifies in periods when barge supply exceeds demand. During the past few years, barge supply has increased as the industry has built more barges than it has retired. The level of long-haul export tonnage delivered to the Gulf of Mexico from the Ohio and upper Mississippi rivers is a key component of barge demand. Grain and coal exports are affected by the strength of the U.S. dollar, volatility of foreign economies and changes in the level of foreign competition. In recent years, export coal shipments have declined significantly due to these factors. While grain exports increased in 1999, they have been below historic levels. Increased imports of ores, cement and other raw materials through the Gulf offset some of the export market weakness. These issues have continued to create strong competition for domestic business and have contributed to the erosion of margins reflected in the chart depicting revenue and cost per ton mile. In 1999 and 1998 the revenues from an operating subsidiary of Cinergy Corp. and the combined revenues from two operating subsidiaries of The Southern Company each accounted for more than 10% of Midland's consolidated revenues under multi-year coal transportation agreements. In 1997 a subsidiary of Cinergy Corp. accounted for approximately 10% of Midland's consolidated revenues. No other customer, or group of customers under common control, accounted for more than 10% of revenues in 1999, 1998 or 1997. On the basis of past experience and its competitive position, Midland considers that the simultaneous loss of several of its largest customers, while possible, is unlikely to happen. Midland's multi-year transportation and terminaling contracts expire at various dates from March 2001 through June 2010. During 1999, approximately 52% of Midland's revenues resulted from multi-year contracts. A substantial portion of the contracts provide for rate adjustments based on changes in various costs, including diesel fuel costs, but the effect of these adjustments is not immediate and Midland remains at risk for fuel price volatility on other contracts and spot business. In addition, contracts contain "force majeure" clauses that excuse performance by the parties to the contracts when performance is prevented by circumstances beyond their reasonable control. Many of these contracts also have provisions for termination for specified causes, such as material breach of contract, environmental restrictions on the burning of coal, or loss by the customer of an underlying commodity supply contract. Penalties for termination for such causes are not generally specified. However, some contracts provide that in the event of an uncured material breach by Midland that results in termination of the contract, Midland would be responsible for reimbursing the customer for the differential between the contract price and the cost of substituted performance. Improvements in operating efficiencies have permitted barge operators to maintain comparatively low rate structures. Consequently, the barge industry has generally been able to retain its competitive position with alternate methods, primarily railroads, for the transportation of bulk commodities, particularly when the origin and destination of such movements are contiguous to navigable waterways. Towboats, such as those operated by Midland, are capable of moving in one tow (barge configuration) approximately 22,500 tons of cargo (equivalent to 225 one hundred-ton capacity railroad cars) on the Ohio River and upper Mississippi River, which are locking rivers, and approximately 60,000 tons (equivalent to 600 one hundred-ton capacity railroad cars) on the lower Mississippi River, where there are no locks to transit. Barge transportation costs per ton mile are generally well below those of railroads. ENVIRONMENTAL MATTERS Midland is subject to the provisions of the Federal Water Pollution Control Act, the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, the Superfund Amendment and Reauthorization Act, the Resource Conservation and Recovery Act of 1976 and the Oil Pollution Act of 1990 which permit the Coast Guard and the Environmental Protection Agency to assess penalties and 10-K/8 clean-up costs for oil, hazardous substances, and hazardous waste discharges. Midland is further subject to comparable state environmental statutes in the states where it operates. Some of these acts also allow third parties to seek damages for losses caused by such discharges. Compliance with these acts has had no material effect on Midland's capital expenditures, earnings, or competitive position, and no such effect is currently anticipated. PROPERTIES As of December 31, 1999, Midland operated 2,436 dry cargo barges and 86 towboats. Approximately half of this equipment is either mortgaged to secure Midland's equipment financing obligations or chartered under long-term leases from third parties. In 1999, Midland's capital expenditures were $18.4 million. These expenditures were made principally for the purchase of new dry cargo barges, terminal facilities and information system improvements. In addition, in 1999 Midland acquired 97 new dry cargo barges under long-term operating leases. About 23% of Midland's barge fleet is less than five years old, as reflected in the chart of barge fleet additions. In 2000 Midland expects to spend approximately $10 million for capital equipment, primarily for information systems and equipment renovations and Midland expects to enter into additional long-term operating leases for 50 to 100 new dry cargo barges. EMPLOYEES As of December 31, 1999, Midland employed approximately 1,400 persons, of whom approximately 31% are represented by labor unions. Collective bargaining agreements expire in 2000 through 2002. GENERAL ENVIRONMENTAL MATTERS Certain information with respect to Eastern's compliance with federal and state environmental statutes may be found in Item 1(c) under "Natural Gas Distribution" and "Marine Transportation" and Note 14. EMPLOYEES Eastern and its wholly-owned subsidiaries employed approximately 3,300 employees at December 31, 1999. ITEM 2. PROPERTIES Information with respect to this item may be found in Item 1(c) under "Natural Gas Distribution" and "Marine Transportation." Such information is incorporated herein by reference. ITEM 3. LEGAL PROCEEDINGS Information with respect to certain legal proceedings may be found in Note 14 and in Item 1(c) hereof under "Natural Gas Distribution" and "Marine Transportation." Such information is incorporated herein by reference. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matter was submitted to a vote of security holders in the fourth quarter of 1999. EXECUTIVE OFFICERS OF THE REGISTRANT GENERAL The table below identifies the executive officers of Eastern, who are appointed annually and serve at the pleasure of Eastern's Trustees.
Office Held Name Title Age Since ---- ----- --- ----------- J. Atwood Ives Chairman and Chief Executive Officer 63 1991 Fred C. Raskin President and Chief Operating Officer 51 1998 Walter J. Flaherty Executive Vice President and Chief Financial Officer 51 1999 J. Mark Cook Senior Vice President, President of Midland 56 1998 L. William Law, Jr. Senior Vice President, General Counsel and Secretary 55 1995 Chester R. Messer Senior Vice President, President of Boston Gas, Colonial Gas and Essex Gas 58 1988
10-K/9 BUSINESS EXPERIENCE J. Atwood Ives joined Eastern in 1991 as Chairman and Chief Executive Officer. He has served as a Trustee of Eastern since 1989. Fred C. Raskin was Senior Vice President and President of Midland from 1991 until returning to Eastern in 1998 as President and Chief Operating Officer. He has been an employee of Eastern or its subsidiaries since 1978. Walter J. Flaherty was elected Executive Vice President and Chief Financial Officer in August 1999. He was Senior Vice President - Administration of Boston Gas from 1988 until joining Eastern in 1991 as its Senior Vice President, Chief Administrative Officer and Chief Financial Officer. He has been an employee of Eastern or its subsidiaries since 1971. J. Mark Cook was elected Senior Vice President and President of Midland in 1998. He was President of Cyprus Foote Mineral Company from 1996 to 1998. He was Chairman and President of Cyprus Australia Coal Company from 1995 to 1996. He was Senior Vice President, Western Operations for Cyprus Amax Coal Company from 1993 to 1994. L. William Law, Jr. has been General Counsel and Secretary of Eastern since 1987. He has been an employee of Eastern or its subsidiaries since 1975. Chester R. Messer has been President of Boston Gas since 1988 and an employee since 1963. He became President of Colonial Gas and Essex Gas when each was acquired. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Eastern's common stock is traded on the New York, Boston and Pacific Stock Exchanges (ticker symbol EFU). The approximate number of shareholders at December 31, 1999 was 7,000. Information with respect to this item may be found in the sections captioned "Dividends Declared Per Share" and "Stock Price Range" appearing on the inside back cover of the annual report to shareholders for the year ended December 31, 1999. Such information is incorporated herein by reference. ITEM 6. SELECTED FINANCIAL DATA Information with respect to this item may be found in the section captioned "Six-Year Financial Review" appearing on page 20 of the annual report to shareholders for the year ended December 31, 1999. Such information is incorporated herein by reference. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following commentary should be read in conjunction with the Consolidated Financial Statements and accompanying Notes to Financial Statements. On November 4, 1999, Eastern signed a definitive agreement to be acquired by KeySpan Corporation ("KeySpan") for $64.00 per share in cash, as described in Note 2 of Notes to Financial Statements. Such information is incorporated herein by reference. The transaction, which is subject to receipt of regulatory approvals and the approval of Eastern shareholders, is expected to close in mid to late 2000, although it is possible the merger will not close until 2001. In July 1999 Eastern signed a definitive agreement to acquire EnergyNorth, Inc. ("EnergyNorth"), an energy services holding company whose subsidiaries distribute natural gas and propane to approximately 85,000 customers in New Hampshire and provide mechanical contracting and HVAC services for commercial, industrial and institutional customers in northern New England. The July agreement provided for a combination of stock and cash as the merger consideration, but the agreement was amended in November 1999 in connection with the pending acquisition of Eastern by KeySpan, as discussed in Note 3. If the KeySpan agreement is not terminated, Eastern will acquire EnergyNorth for approximately $203 million in cash simultaneously with Eastern's merger with KeySpan. If the KeySpan agreement is terminated, Eastern will acquire EnergyNorth for approximately $78 million in cash and 1.7 million Eastern shares, subject to adjustment under a collar arrangement. The merger, which is subject to satisfactory regulatory approvals and the approval of EnergyNorth shareholders, is expected to close in mid to late 2000, although it is possible the merger will not close until 2001. The merger is expected to be tax free to Eastern whether or not the KeySpan agreement is terminated. Eastern's acquisition of Colonial Gas Company ("Colonial Gas") on August 31, 1999 has been accounted for under the purchase method of accounting as discussed in Note 4. Accordingly, Eastern's financial statements include Colonial Gas' financial information from the date of acquisition. The operations 10-K/10 of Colonial Gas, a regulated utility, are combined with those of Boston Gas and Essex Gas and are presented herein as natural gas distribution (LDC group). Midland Enterprises is reported as marine transportation. Other services include the results of ServicEdge Partners, Inc. ("ServicEdge"), Transgas Inc. ("Transgas"), which was acquired as part of Colonial Gas, and AMR Data Corp. ("AMR Data"). 1999 COMPARED TO 1998 The Company reported net earnings of $55.1 million, or $2.27 per share, in 1999, compared to net earnings of $106.0 million, or $4.67 per share, in 1998. (Per share figures are presented on a diluted basis, as described in Note 1.) Excluding extraordinary items described in Notes 6 and 16 and the cumulative effect of an accounting change described in Note 15 from 1998 results, Eastern's earnings and earnings per share increased 8% and 1%, respectively, from $50.8 million and $2.24 per share in 1998. (In millions) 1999 1998 Change ----- ----- ------ REVENUES Natural gas distribution $690.8 $667.1 3.6% Marine transportation 267.3 261.1 2.4% Other services 20.6 7.1 nm ------ ------ Total $978.7 $935.3 4.6% ====== ====== The increase in consolidated revenues from 1998 to 1999 primarily reflects the acquisition of Colonial Gas and colder weather, partially offset by lower gas costs, lower non-firm sales and customer migration from firm gas sales to transportation-only service. (In millions) 1999 1998 Change ----- ----- ------ OPERATING EARNINGS Natural gas distribution $101.4 $ 88.9 14.1% Marine transportation 21.1 26.6 (20.7)% Other services (2.9) (9.0) 67.8% Headquarters (6.2) (6.1) (1.6)% ------ ------ Total $113.4 $100.4 12.9% ====== ====== The increase in consolidated operating earnings from 1998 to 1999 primarily reflects the acquisition of Colonial Gas, colder weather and the absence of startup costs associated with ServicEdge, partially offset by higher operating costs for marine transportation. NATURAL GAS DISTRIBUTION ("LDC GROUP") The LDC group includes the operations of Boston Gas, Colonial Gas and Essex Gas, as discussed in Note 5. Revenues in 1999 increased $23.7 million, compared to 1998, primarily reflecting the acquisition of Colonial Gas ($54 million), colder weather ($26 million) and throughput growth ($10 million), partially offset by lower gas costs ($28 million), lower interruptible sales ($20 million) and the migration of customers from firm sales to transportation-only service ($12 million). The impact of Essex Gas' revenue recognition and the conforming of its historical periods with those of Eastern increased 1998 revenues and operating earnings by $9 million and $4 million, respectively, reflecting the 1998 inclusion of Essex Gas' operations for December 1997 and the exclusion of its operations for September 1998, as described in Note 4. Weather for 1999 was 5% colder than 1998 but 5% warmer than normal. The revenue decrease associated with customer migration and lower gas costs has no impact on operating earnings as the LDC group earns all of its margins on the local distribution of gas and none on the sale of the commodity or the passthrough of gas costs. LDC group operating earnings in 1999 increased $12.5 million, as the acquisition of Colonial Gas ($11 million), the impact of colder weather ($7 million), and throughput growth ($4 million) were partially offset by higher controllable costs ($6 million) and the aforementioned Essex Gas accounting treatment and fiscal periods ($4 million). A $2 million charge for an early retirement program at Boston Gas related to the integration of Colonial Gas operations was partially offset by lower expenses, principally bad debt expense, reflecting improved collection experience. MARINE TRANSPORTATION Revenues in 1999 increased $6.2 million, reflecting higher ton mile production due to increased demand for shipments of grain exports and backhaul imports of steel-related products to the Ohio River 10-K/11 Valley. Partially offsetting was a continued decline in export coal shipments due to the non- competitiveness of U.S. coal prices in world markets. Domestic spot and utility contract coal shipments also trended lower, as mild weather and high stockpiles reduced electric utility demand. Tonnage transported in 1999 was unchanged from 1998, while ton miles increased 3% as a result of an increase in average trip length due to the additional long-haul grain and import tonnage discussed above. Total coal tonnage and ton miles both declined 4%, reflecting weaker export and spot shipments. Non-coal tonnage and ton miles both increased 8% due to the increased grain and import tonnage. Operating conditions were improved as compared to 1998, however, drought conditions significantly hampered operations during the last half of 1999. Operating expenses increased 6% over the prior year, reflecting rising costs associated with crew labor, port expenses, vessel maintenance and insurance. The purchase of new barges and other capital improvements increased depreciation and property taxes. As a result of these items, operating earnings declined $5.5 million from 1998. OTHER SERVICES Other services consist of the operations of ServicEdge, which accounts for the majority of the revenues, Transgas, which was acquired as part of Colonial Gas on August 31, 1999, and AMR Data. The decrease in the operating loss from $9.0 million in 1998 to $2.9 million in 1999 primarily reflects the absence of startup costs for ServicEdge, which commenced operations in 1998, and profitable operations at Transgas and AMR Data. HEADQUARTERS The increase in Headquarters' unallocated expenses in 1999 reflects KeySpan transaction costs of $2.4 million, partially offset by the absence of $1.2 million in Essex Gas transaction costs and lower consulting costs incurred in 1998. OTHER The $5.2 million increase in net interest expense primarily reflects the assumption of debt and cash paid in the Colonial Gas acquisition and the issuance of debt by Midland in September 1998, partially offset by interest income on a tax settlement and lower working capital requirements for natural gas distribution during the first part of 1999. Other, net in 1999 includes a $3.2 million reduction in the environmental reserve reflecting regulatory clearance of one site, $2.5 million in environmental-related insurance recoveries and a $1.8 million gain on the sale of a towboat. Other, net in 1998 primarily reflects realized gains on investments. The increase in Eastern's effective tax rate from 36% in 1998 to 40% in 1999 reflects the capital loss utilization available in 1998 and the non- deductibility of KeySpan merger expenses and Colonial goodwill amortization. In the first quarter of 1998, Eastern recognized an extraordinary loss of $2.3 million pretax, $1.5 million net, or $.06 per share, on redeeming Midland debt, as described in Note 6. In June 1998 the U.S. Supreme Court held the Coal Industry Retiree Health Benefit Act of 1992 ("Coal Act") to be unconstitutional as applied to Eastern. The reversal of the Coal Act reserve resulted in an extraordinary gain of $74.5 million pretax, $48.4 million net, or $2.13 per share, in the second quarter of 1998, as described in Note 16. Net earnings for the first quarter of 1998 include $8.2 million, or $.36 per share, for the cumulative effect of changing Boston Gas' method of accounting for unbilled revenues to an accrual method, as described in Note 15. 10-K/12 1998 COMPARED TO 1997 (In millions) 1998 1997 Change ---- ---- ------ REVENUES Natural gas distribution $667.1 $ 754.5 (11.6)% Marine transportation 261.1 269.2 (3.0)% Other services 7.1 - nm ------ -------- Total $935.3 $1,023.7 (8.6)% ====== ======== The decrease in consolidated revenues from 1997 to 1998 primarily reflects decreases for natural gas distribution, including the impact of warmer weather, the migration from firm gas sales to transportation-only service and lower gas costs, partially offset by sales to new customers. (In millions) 1998 1997 Change ---- ---- ------ OPERATING EARNINGS Natural gas distribution $ 88.9 $ 87.8 1.3% Marine transportation 26.6 34.6 (23.1)% Other services (9.0) (1.5) nm Headquarters (6.1) (5.6) (8.9)% ------ ------ Total $100.4 $115.3 (12.9)% ====== ====== The decrease in consolidated operating earnings from 1997 to 1998 primarily reflects reduced volumes, lower rates and higher costs for marine transportation and startup costs associated with ServicEdge. NATURAL GAS DISTRIBUTION Revenues in 1998 decreased $87.4 million, compared to 1997, primarily reflecting warmer weather ($50 million), the migration of customers from firm sales to transportation-only service ($22 million), lower gas costs ($17 million), and the absence of a 1997 nonrecurring increase in revenues ($9 million) related to a change in the recovery mechanism for the portion of bad debts associated with gas costs. Growth in throughput was partially offsetting. Weather for calendar 1998 was 9% warmer than normal and 13% warmer than 1997. Operating earnings in 1998 increased $1.1 million, as lower operating costs ($9 million), throughput growth ($4 million), and modestly higher average rates were mostly offset by the negative impact of warmer weather ($16 million) and higher depreciation expense. The decrease in operating costs primarily reflects weather-related reductions and continued cost control measures, as well as the absence of a $9 million charge related to Boston Gas' decision to exit the gas appliance service business in 1997. The operating earnings impact of this latter charge was essentially offset by the absence of the nonrecurring revenue increase related to the bad debt recovery mechanism, as described above. MARINE TRANSPORTATION Revenues in 1998 decreased $8.1 million, reflecting lower ton mile production and lower rates resulting from weaker market conditions. A strong U.S. dollar and economic problems in Asia combined to significantly reduce long-haul export coal and grain demand, which in turn created excess barge capacity and placed downward pressure on rates. Tonnage transported in 1998 increased 5% over 1997, while ton miles declined 3% due to shorter average trip lengths, primarily reflecting the reduced long-haul export tonnage. Total coal tonnage increased 8% with coal tonnage shipped under multi-year contracts to utility customers increasing 12%. Coal ton miles declined 3%, however, due to the decline in long-haul export coal shipments. Extreme adverse weather conditions significantly increased operating costs and reduced productivity. Operating difficulties disrupted traffic patterns, lowered fleet productivity and materially increased operating expenses. Lower fuel prices, which dropped 23% per gallon in 1998, were partly offsetting. Reflecting these operating and market issues, operating earnings declined $8.0 million from 1997. OTHER SERVICES Revenues of $7.1 million primarily reflect the results of ServicEdge, which commenced operations in 1998. The operating loss of $9.0 million primarily reflects costs associated with the startup of ServicEdge. 10-K/13 OTHER The $2.4 million reduction in net interest expense reflects the use of short-term investments for the redemption and issuance of Midland debt in 1998. The $9.6 million increase in other, net reflects increased realized gains on investments in 1998 and the absence of a charge recorded in 1997 to reflect Eastern's share of a former joint venture's operating losses, as reflected in Note 12. Eastern's effective tax rate in 1998 was 36%. In 1997 the rate was 33%, primarily because of adjustments relating to prior year returns, as described in Note 13. Net earnings for 1998 include an extraordinary gain on the reversal of the Coal Act reserve, an extraordinary loss on the redemption of Midland debt and the cumulative effect of an accounting change for Boston Gas, as described above. YEAR 2000 ISSUES TRANSITION TO YEAR 2000 Eastern experienced no significant issues as a result of the transition from December 31, 1999 to January 1, 2000. Natural gas distribution transitioned into year 2000 without incident or disruption to the gas distribution network, customer services or production systems. Marine transportation experienced no significant year 2000 related problems or operational disruptions. A few minor program errors to non- critical systems were identified and corrected. Eastern and its operating subsidiaries will continue to monitor in-house information systems through the end of the first quarter of 2000. COST OF YEAR 2000 REMEDIATION Eastern's cost incurred to achieve year 2000 compliance was approximately $17.3 million as detailed in the following chart: (In millions) ----------------------------------------------------------- Natural gas distribution: capitalized $10.5 expensed 4.4 Marine transportation: capitalized 1.4 expensed 1.0 ----- Total $17.3 ===== Included above are the costs of purchased software and hardware, consulting and the value of internal staff time. Capitalized projects have resulted in added functionality while addressing year 2000 issues. The company does not expect to incur any further significant year 2000 related costs. FORWARD-LOOKING INFORMATION This report and other company statements and statements issued or made from time to time contain certain "forward-looking statements" concerning projected future financial performance, expected plans or future operations. Eastern cautions that actual results and developments may differ materially from such projections or expectations. Investors should be aware of important factors that could cause actual results to differ materially from forward-looking projections or expectations. These factors include, but are not limited to: the effect of the pending mergers with KeySpan and EnergyNorth, Eastern's ability to successfully integrate its new gas distribution operations, temperatures above or below normal in eastern Massachusetts, changes in market conditions for barge transportation, adverse weather and operating conditions on the inland waterways, uncertainties regarding the profitability of ServicEdge, changes in economic conditions, including interest rates and the value of the dollar versus other currencies, regulatory and court decisions and developments with respect to Eastern's previously-disclosed environmental liabilities. Most of these factors are difficult to predict accurately and are generally beyond Eastern's control. LIQUIDITY AND CAPITAL RESOURCES Management believes that projected cash flow from operations, in combination with currently available resources, will be more than sufficient to meet Eastern's 2000 capital expenditure and working capital requirements, potential funding of its environmental liabilities, normal debt repayments and 10-K/14 anticipated dividends to shareholders. Management expects KeySpan to provide the funds needed for the acquisition of EnergyNorth. If the KeySpan agreement is terminated, management expects the EnergyNorth acquisition to be funded through a combination of internal sources and additional borrowings. In addition to cash and marketable investments of $44.3 million at December 31, 1999, Eastern and its subsidiaries maintain $145 million of borrowing capacity under revolving credit agreements, plus uncommitted lines, all of which are available for general corporate purposes. At December 31, 1999, there were borrowings of $80.2 million outstanding under these facilities. To meet working capital requirements which reflect the seasonal nature of its business, natural gas distribution had outstanding $80.2 million of short- term borrowings at December 31, 1999, an increase of $42.4 million from the prior year, primarily reflecting the acquisition of Colonial Gas. In addition, natural gas distribution maintains bank credit agreements of up to $110 million to finance its inventory of gas supplies. At December 31, 1999, natural gas distribution had outstanding $70.3 million of gas inventory financing for this purpose, of which $16.3 million is reflected in current debt. Eastern's capital structure is depicted in the chart below. The Company expects to continue its policy of capitalizing its LDC group and Midland with approximately equal amounts of equity and long-term debt. Boston Gas, Colonial Gas and Midland currently maintain "A" ratings with the major rating agencies. (Bar Chart) CAPITAL STRUCTURE ($ IN MILLIONS) 1995 1996 1997 1998 1999 ---- ---- ---- ---- ---- Debt $379.02 $367.68 $371.49 $385.52 $ 515.23 Equity 426.47 461.01 484.47 546.07 754.63 ------- ------- ------- ------- --------- Total Capital $805.49 $828.69 $855.96 $931.59 $1,269.86 (Bar Chart) OPERATING CASH FLOW ($ IN MILLIONS) 1995 1996 1997 1998 1999 ---- ---- ---- ---- ---- $127.6 $131.7 $127.2 $126.3 $136.5 (Bar Chart) CAPITAL EXPENDITURES AND DEPRECIATION AND AMORTIZATION ($ IN MILLIONS) CAPITAL EXPENDITURES: 1995 1996 1997 1998 1999 ----- ------ ----- ------ ----- Natural Gas $64.3 $ 66.5 $62.3 $ 66.2 $69.3 Marine Transportation 20.9 47.9 25.7 46.6 18.4 ----- ------ ----- ------ ----- Total $85.2 $114.4 $88.0 $112.8 $87.7 DEPRECIATION AND AMORTIZATION 1995 1996 1997 1998 1999 ----- ------ ----- ------ ----- Natural Gas $40.8 $ 44.3 $47.8 $ 50.9 $55.8 Marine Transportation 22.9 22.6 22.7 23.8 24.3 ----- ------ ----- ------ ----- Total $63.7 $ 66.9 $70.5 $ 74.7 $80.1 Operating cash flow was $136.5 million in 1999, reflecting a steady increase in depreciation and amortization which has grown 27% from 1995 to 1999. Over this period, Eastern's capital expenditures were nearly $500 million and exceeded depreciation and amortization by approximately $130 million. Consolidated capital expenditures for 2000 are budgeted at approximately $107 million, with about 90% at Eastern's LDC group and the balance at Midland. 10-K/15 OTHER MATTERS Eastern is aware of certain non-utility sites, associated with former operations, for which it may have or share responsibility for environmental remediation or ongoing maintenance. Eastern has a reserve with a balance of approximately $20 million at December 31, 1999, to cover the remediation and maintenance costs of these sites, the principal of which is a former coal tar processing facility in Everett, Massachusetts, as described in Note 14. While Eastern has provided reserves to cover the estimated probable costs of remediation and maintenance for environmental sites based on the information available at the present time, the extent of Eastern's potential liability at such sites is not yet determined. Eastern's natural gas distribution operations, like many other companies in the natural gas industry, are parties to government proceedings requiring investigation and possible remediation of former manufactured gas plant ("MGP") sites. Boston Gas, Colonial Gas and Essex Gas may have or share responsibility under applicable environmental law for remediation of 28 such sites, as described in Note 14. Boston Gas, Colonial Gas and Essex Gas are aware of 30 other MGP sites within their service territories. A subsidiary of New England Electric System has provided full indemnification to Boston Gas with respect to eight of these sites. At this time, there is substantial uncertainty as to whether Boston Gas, Colonial Gas or Essex Gas has or shares responsibility for remediating any of these other sites. No notice of responsibility has been issued to Boston Gas, Colonial Gas or Essex Gas for any of these sites from any governmental authority. 10-K/16 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO FINANCIAL STATEMENTS PAGE NO. Consolidated Statements of Operations 10-K/18 Consolidated Balance Sheets 10-K/19 Consolidated Statements of Cash Flows 10-K/20 Consolidated Statements of Shareholders' Equity 10-K/21 Notes to Financial Statements 10-K/22 Unaudited Quarterly Financial Information 10-K/38 Report of Independent Public Accountants 10-K/39 Management's Report on Responsibility 10-K/39 10-K/17 CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended December 31, (In thousands, except per share amounts) 1999 1998 1997 - ----------------------------------------------------------------------------------------------------------------- REVENUES $978,702 $935,264 $1,023,740 OPERATING COSTS AND EXPENSES: Operating costs 665,422 640,792 715,066 Selling, general and administrative expenses 118,468 118,546 122,035 Depreciation and amortization 81,373 75,521 71,322 -------- -------- ---------- OPERATING EARNINGS 113,439 100,405 115,317 OTHER INCOME (EXPENSE): Interest income 7,964 7,582 8,997 Interest expense (39,136) (33,584) (37,411) Other, net 8,980 5,591 (4,033) -------- -------- ---------- EARNINGS BEFORE INCOME TAXES 91,247 79,994 82,870 Provision for income taxes 36,154 29,166 26,954 -------- -------- ---------- EARNINGS BEFORE EXTRAORDINARY ITEMS AND ACCOUNTING CHANGE 55,093 50,828 55,916 Extraordinary items, net of tax: Reversal of Coal Act reserve - 48,425 - Loss on early extinguishment of debt - (1,465) - Cumulative effect of accounting change, net of tax - 8,193 - -------- -------- ---------- NET EARNINGS $ 55,093 $105,981 $ 55,916 ======== ======== ========== BASIC EARNINGS PER SHARE BEFORE EXTRAORDINARY ITEMS AND ACCOUNTING CHANGE $2.28 $2.26 $2.50 Extraordinary items, net of tax: Reversal of Coal Act reserve - 2.16 - Loss on early extinguishment of debt - (.07) - Cumulative effect of accounting change, net of tax - .37 - ----- ----- ----- BASIC EARNINGS PER SHARE $2.28 $4.72 $2.50 ===== ===== ===== DILUTED EARNINGS PER SHARE BEFORE EXTRAORDINARY ITEMS AND ACCOUNTING CHANGE $2.27 $2.24 $2.49 Extraordinary items, net of tax: Reversal of Coal Act reserve - 2.13 - Loss on early extinguishment of debt - (.06) - Cumulative effect of accounting change, net of tax - .36 - ----- ----- ----- DILUTED EARNINGS PER SHARE $2.27 $4.67 $2.49 ===== ===== ===== The accompanying notes are an integral part of these financial statements. 10-K/18
CONSOLIDATED BALANCE SHEETS
December 31, (In thousands) 1999 1998 - ----------------------------------------------------------------------------------------------------- ASSETS CURRENT ASSETS: Cash and short-term investments $ 44,332 $ 159,836 Receivables, less reserves of $18,860 in 1999 and $17,070 in 1998 135,409 105,133 Inventories 74,555 55,867 Deferred gas costs 64,503 54,065 Other current assets 5,008 5,689 ---------- ---------- TOTAL CURRENT ASSETS 323,807 380,590 PROPERTY AND EQUIPMENT, AT COST 2,197,156 1,722,603 Less--accumulated depreciation 906,953 746,992 ---------- ---------- NET PROPERTY AND EQUIPMENT 1,290,203 975,611 OTHER ASSETS: Goodwill, less amortization of $2,146 in 1999 247,137 - Deferred postretirement health care costs 72,760 78,567 Investments 14,671 15,395 Deferred charges and other costs, less amortization 71,179 68,449 ---------- ---------- TOTAL OTHER ASSETS 405,747 162,411 ---------- ---------- TOTAL ASSETS $2,019,757 $1,518,612 ========== ========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Current debt $ 123,251 $ 43,237 Accounts payable 75,770 56,339 Accrued expenses 37,516 39,164 Other current liabilities 50,234 43,013 ---------- ---------- TOTAL CURRENT LIABILITIES 286,771 181,753 GAS INVENTORY FINANCING 54,020 52,644 LONG-TERM DEBT 515,232 385,519 RESERVES AND OTHER LIABILITIES: Deferred income taxes 179,426 134,911 Postretirement health care 100,016 97,196 Preferred stock of subsidiary 26,454 29,360 Other reserves 103,208 91,160 ---------- ---------- TOTAL RESERVES AND OTHER LIABILITIES 409,104 352,627 COMMITMENTS AND CONTINGENCIES SHAREHOLDERS' EQUITY: Common stock $1.00 par value; Authorized shares-- 50,000,000; Issued shares--27,131,090 in 1999 and 22,535,734 in 1998 27,131 22,536 Capital in excess of par value 244,449 53,421 Retained earnings 483,710 470,576 Accumulated other comprehensive (loss) (77) (105) Treasury stock at cost--16,892 shares in 1999 and 10,461 shares in 1998 (583) (359) ---------- ---------- TOTAL SHAREHOLDERS' EQUITY 754,630 546,069 ---------- ---------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $2,019,757 $1,518,612 ========== ========== The accompanying notes are an integral part of these financial statements. 10-K/19
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31, (In thousands) 1999 1998 1997 - ---------------------------------------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES: NET EARNINGS $ 55,093 $ 105,981 $ 55,916 Adjustments to reconcile net earnings to net cash provided by operating activities: Extraordinary credit for reversal of Coal Act reserve - (48,425) - Extraordinary loss on early extinguishment of debt - 1,465 - Cumulative effect of accounting change - (8,193) - Depreciation and amortization 81,373 75,521 71,322 Income taxes and tax credits 5,588 (1,876) 19,578 Net gain on sale of assets (2,125) (4,948) (778) Other changes in assets and liabilities: Receivables (15,541) 19,864 (12,502) Inventories (3,692) 5,827 4,495 Deferred gas costs (10,523) 15,160 8,892 Accounts payable 3,599 (16,929) (7,345) Other 159 (9,191) 7,062 --------- --------- -------- NET CASH PROVIDED BY OPERATING ACTIVITIES 113,931 134,256 146,640 --------- --------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (88,117) (113,712) (89,216) Acquisition of Colonial Gas, net of cash acquired (150,446) - - Investments (8,208) (7,624) 3,018 Proceeds on sale of assets 9,998 15,956 7,290 Other (2,897) (6,035) (1,966) --------- --------- -------- NET CASH USED BY INVESTING ACTIVITIES (239,670) (111,415) (80,874) --------- --------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: Dividends paid (39,801) (35,653) (35,255) Changes in notes payable 48,738 (10,800) (25,927) Changes in gas inventory financing 1,376 (7,300) 358 Proceeds from issuance of long-term debt - 68,519 9,827 Repayment of long-term debt and preferred stock (9,449) (56,348) (5,801) Other 9,371 7,920 1,581 --------- --------- -------- NET CASH PROVIDED (USED) BY FINANCING ACTIVITIES 10,235 (33,662) (55,217) --------- --------- -------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (115,504) (10,821) 10,549 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 159,836 170,657 160,108 --------- --------- -------- CASH AND CASH EQUIVALENTS AT END OF YEAR 44,332 159,836 170,657 SHORT-TERM INVESTMENTS - - 5,052 --------- --------- -------- CASH AND SHORT-TERM INVESTMENTS $ 44,332 $ 159,836 $175,709 ========= ========= ======== The accompanying notes are an integral part of these financial statements. 10-K/20
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
Accumulated Other Common Capital In Comprehensive Stock Excess of Retained Earnings Treasury (In thousands) $1 Par Value Par Value Earnings (Loss) Stock Total - ---------------------------------------------------------------------------------------------------------------- BALANCE AT DECEMBER 31, 1996 $22,387 $ 50,604 $390,333 $ 1,244 $(3,555) $461,013 Comprehensive income: Net earnings - - 55,916 - - - Unrealized holding gains on investments, net - - - 884 - - Pension liability adjustment, net - - - (261) - - Total comprehensive income - - - - - 56,539 Dividends declared--$1.61 per share - - (35,493) - - (35,493) Executive stock purchase loans - (1,156) - - - (1,156) Issuance of stock, net 51 1,541 - - 1,975 3,567 ------- -------- -------- ------- ------- -------- BALANCE AT DECEMBER 31, 1997 22,438 50,989 410,756 1,867 (1,580) 484,470 Comprehensive income: Net earnings - - 105,981 - - - Essex Gas excluded period - - (7,994) - - - Unrealized holding losses on investments, net - - - (2,448) - - Pension liability adjustment, net - - - 476 - - Total comprehensive income - - - - - 96,015 Dividends declared--$1.65 per share - - (38,167) - - (38,167) Executive stock purchase loans - (169) - - - (169) Issuance of stock, net 98 2,601 - - 1,221 3,920 ------- -------- -------- ------- ------- -------- BALANCE AT DECEMBER 31, 1998 22,536 53,421 470,576 (105) (359) 546,069 Comprehensive income: Net earnings - - 55,093 - - - Unrealized holding losses on investments, net - - - (383) - - Pension liability adjustment, net - - - 411 - - Total comprehensiveincome - - - - - 55,121 Dividends declared--$1.69 per share - - (41,959) - - (41,959) Acquisition of Colonial Gas 4,219 181,378 - - - 185,597 Executive stock purchase loans - (2,381) - - - (2,381) Issuance of stock, net 376 12,031 - - (224) 12,183 ------- -------- -------- ------- ------- -------- BALANCE AT DECEMBER 31, 1999 $27,131 $244,449 $483,710 $ (77) $ (583) $754,630 ======= ======== ======== ======= ======= ======== The accompanying notes are an integral part of these financial statements. 10-K/21
NOTES TO FINANCIAL STATEMENTS 1. ACCOUNTING POLICIES The consolidated financial statements include the accounts of Eastern Enterprises ("Eastern") and its natural gas distribution subsidiaries, Boston Gas Company ("Boston Gas"), Colonial Gas Company ("Colonial Gas") and Essex Gas Company ("Essex Gas"), its marine transportation subsidiary, Midland Enterprises Inc. ("Midland"), and its other subsidiaries, ServicEdge Partners, Inc. ("ServicEdge"), Transgas Inc. ("Transgas") and AMR Data Corp. ("AMR Data"). As discussed in Note 4, Colonial Gas and its subsidiary Transgas, were acquired on August 31, 1999 in a transaction accounted for using the purchase method of accounting for business combinations. 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 revenues and expenses during the reporting period, the reported amounts of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates. As discussed in Note 4, amounts have been restated under the pooling-of- interests method of accounting to include the operations of Essex Gas, acquired on September 30, 1998. Certain prior year financial statement information has been reclassified to be consistent with the current presentation. All material intercompany balances and transactions have been eliminated in consolidation. Certain accounting policies followed by Eastern and its subsidiaries are described below: Cash and short-term investments: Highly liquid instruments with original maturities of three months or less are considered cash equivalents. Inventories consist of the following: December 31, (In thousands) 1999 1998 --------------------------------------------------------------------- Supplemental gas supplies $57,935 $45,266 Other materials, supplies and marine fuel 16,620 10,601 ------- ------- $74,555 $55,867 ======= ======= Inventories are valued at the lower of cost or market using the first-in, first-out (FIFO) or average cost method. Regulatory assets and liabilities: Boston Gas is subject to the provisions of Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation" during the periods presented. Colonial Gas and Essex Gas discontinued the application of SFAS No. 71 as of August 31, 1999 and September 30, 1998, respectively, as discussed in Note 4. Regulatory assets represent probable future revenue associated with certain costs which will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Regulatory assets include the following: December 31, (In thousands) 1999 1998 ------------------------------------------------------------------- Postretirement benefit costs $72,760 $ 78,567 Environmental costs 21,299 20,990 Other 733 1,365 ------- -------- $94,792 $100,922 ======= ======== Regulatory liabilities total $8,586,000 and $9,479,000 at December 31, 1999 and 1998, respectively, and relate primarily to income taxes. As of December 31, 1999 regulatory assets and regulatory liabilities are being reflected in rates charged to customers over periods from one to 20 years. 10-K/22 NOTES TO FINANCIAL STATEMENTS--(CONTINUED) Other current liabilities consist of the following: December 31, (In thousands) 1999 1998 --------------------------------------------------------------------- Dividend payable $11,613 $ 9,455 Reserves for insurance claims 10,326 10,739 Pipeline refunds due utility customers 5,897 192 Other 22,398 22,627 ------- ------- $50,234 $43,013 ======= ======= Revenue recognition: Eastern's natural gas subsidiaries record revenues utilizing the unbilled revenue method by estimating revenues that remain unbilled at the end of the accounting periods. As described in Note 15, in 1998 Boston Gas changed its revenue accounting method to record unbilled revenue. As described in Note 4, Essex Gas adopted the unbilled revenue method upon acquisition. Deferred gas costs represent amounts billable to customers through the operation of regulatory approved cost of gas adjustment clauses. Midland recognizes revenue on tows in progress on the percentage-of-completion method based on miles traveled. ServicEdge recognizes contract revenues over the life of the contract, matching revenues with anticipated expenses and other revenues when billed. Depreciation and amortization: Depreciation and amortization are provided using the straight-line method at rates designed to allocate the cost of property and equipment over their estimated useful lives: Years ---------------------------------------------------------------------- Gas utility plant 14-82 Boats and barges 23-30 Buildings 20-30 Furniture, fixtures and other equipment 3-25 Computer software and related equipment 3-10 Leaseholds shorter of useful life or term of lease Earnings per share: SFAS No. 128, "Earnings per Share," requires the presentation of basic and diluted earnings per share. Basic earnings per share is computed by dividing net income by the weighted average number of shares of common stock outstanding during the year. Diluted earnings per share is determined by giving effect to the exercise of stock options using the treasury stock method. The following includes a reconciliation of shares outstanding used to compute basic and diluted earnings per share: Years Ended December 31, (In thousands, except per share amounts) 1999 1998 1997 - -------------------------------------------------------------------------------- Earnings before extraordinary items and accounting change $55,093 $50,828 $55,916 ======= ======= ======= Weighted-average shares 24,112 22,474 22,329 Dilutive effect of options 142 206 169 ------- ------- ------- Adjusted weighted-average shares 24,254 22,680 22,498 ======= ======= ======= Basic earnings per share before extraordinary items and accounting change $2.28 $2.26 $2.50 ===== ===== ===== Diluted earnings per share before extraordinary items and accounting change $2.27 $2.24 $2.49 ===== ===== ===== Comprehensive income: Effective January 1, 1998, Eastern adopted SFAS No. 130, "Reporting Comprehensive Income." This statement requires presentation of the components of comprehensive earnings, including the changes in equity from non-owner sources such as unrealized gains on securities and minimum pension liability adjustments, which are reflected on Eastern's consolidated statements of shareholders' equity. 10-K/23 NOTES TO FINANCIAL STATEMENTS--(CONTINUED) The following is a summary of the reclassification adjustments and the income tax effects for the components of other comprehensive income:
Unrealized Holding Gains (Losses) on Reclassification Investments Adjustments for Pension Arising During Gains Included Net Unrealized Liability (In thousands) the Period in Net Income Gains (Losses) Adjustment Total - ------------------------------------------------------------------------------------------------------------- 1997 Pretax $2,210 $(1,313) $ 897 $(401) $ 496 Income tax benefit (expense) 12 (25) (13) 140 127 ----- ------ ------ ---- ------ Net change $2,222 $(1,338) $ 884 $(261) $ 623 ====== ======= ======= ===== ======= 1998 Pretax $ 105 $(1,873) $(1,768) $ 732 $(1,036) Income tax (expense) (680) - (680) (256) (936) ----- ------ ------ ---- ------ Net change $ (575) $(1,873) $(2,448) $ 476 $(1,972) ====== ======= ======= ===== ======= 1999 PRETAX $ 502 $(1,091) $ (589) $ 632 $ 43 INCOME TAX BENEFIT (EXPENSE) (176) 382 206 (221) (15) ----- ------ ------ ---- ------ NET CHANGE $ 326 $ (709) $ (383) $ 411 $ 28 ====== ======= ======= ===== =======
The income tax benefit in 1997 reflects the availability of capital loss carryforwards to offset unrealized gains. Pending Accounting Changes: SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 137, is effective for fiscal quarters of all fiscal years beginning after June 15, 2000. SFAS No. 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or a liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. The Company has not yet quantified the impact of adopting SFAS No. 133 on the consolidated financial statements. However, SFAS No. 133 could increase volatility in earnings and other comprehensive income. 2. PLANNED MERGER WITH KEYSPAN On November 4, 1999, Eastern signed a definitive agreement that provides for the merger of Eastern with a wholly-owned subsidiary of KeySpan Corporation ("KeySpan"), with Eastern surviving the merger and becoming a wholly-owned subsidiary of KeySpan. In the merger, holders of Eastern common stock will receive $64.00 in cash per share of Eastern common stock, without interest, plus an additional $0.006 per share per day for each day the merger has not closed beginning on the later of (a) August 4, 2000 or (b) ninety days after the state of New Hampshire gives final regulatory approval. The transaction, which is subject to receipt of regulatory approvals and the approval of Eastern shareholders, is expected to close in mid to late 2000, although it is possible the merger will not close until 2001. 10-K/24 NOTES TO FINANCIAL STATEMENTS--(CONTINUED) 3. PLANNED MERGER WITH ENERGYNORTH, INC. On July 14, 1999, Eastern signed a definitive agreement that provides for the merger of EnergyNorth, Inc. ("EnergyNorth") into a wholly-owned subsidiary of Eastern. This agreement was amended on November 4, 1999, in connection with the execution of the merger agreement between Eastern and KeySpan discussed above in Note 2. In the proposed merger, a wholly-owned subsidiary of Eastern will merge into EnergyNorth and, as a result, EnergyNorth will become a wholly-owned subsidiary of Eastern. If the KeySpan-Eastern merger agreement has not been terminated prior to the effective time of the Eastern-EnergyNorth merger, holders of EnergyNorth common stock will receive $61.13 cash, without interest, per share of EnergyNorth. The per share amount of $61.13 may be increased if the cash amount to be paid for each share of Eastern common stock in the merger discussed in Note 2 above is increased above $64.00. If the KeySpan-Eastern merger agreement has been terminated, holders of EnergyNorth common stock will receive cash or Eastern common stock worth $47.00 per share of EnergyNorth, with 50.1% of the common stock of EnergyNorth being converted into Eastern stock and the balance being converted into cash. The exchange ratio for the stock portion of the consideration will be based upon Eastern's weighted average trading stock price for a ten-day period prior to closing, subject to a collar mechanism. The transaction, which is subject to receipt of regulatory approvals and the approval of EnergyNorth shareholders, is expected to close simultaneously with the KeySpan merger. The merger is expected to be tax-free to Eastern whether or not the KeySpan-Eastern merger agreement is terminated. The Eastern-EnergyNorth merger will be accounted for using the purchase method of accounting. 4. MERGERS COLONIAL GAS MERGER On August 31, 1999, Eastern completed a merger with Colonial Gas in a transaction with an enterprise value of approximately $474 million. In effecting the transaction, Eastern paid $150 million in cash, net of cash acquired and including transaction costs, issued approximately 4.2 million shares of common stock valued at $186 million and assumed $138 million of debt. The cash portion of the transaction was financed through available cash and borrowings under Eastern's lines of credit. The Colonial merger has been accounted for using the purchase method of accounting for business combinations. Accordingly, the accompanying Consolidated Statements of Operations include Colonial Gas results commencing September 1, 1999. The purchase price was allocated to the net assets acquired based on their fair value. The historical cost basis of Colonial Gas' assets and liabilities, with the exception of its retiree benefit obligations and the adjustments described below, was determined to represent the fair value due to the existence of a regulatory-approved rate plan based upon the recovery of historical costs and a fair return thereon. As a result of the merger and related rate plan approved by the Massachusetts Department of Telecommunications and Energy ("Department"), value was not allocated to systems that will no longer be used due to the integration of Colonial into Eastern's natural gas distribution business and value was not allocated to Colonial's net regulatory assets. No value was allocated to the net regulatory assets because the rate plan does not meet the criteria for the continued application of SFAS 71, "Accounting for the Effects of Certain Types of Regulation." The allocation of the purchase price remains subject to adjustment upon final valuation of certain acquired balances. The excess of cost over the fair value of the net assets acquired, or goodwill, of approximately $250 million has been recorded as an asset and is being amortized on a straight-line basis, principally over a period of 40 years. 10-K/25 NOTES TO FINANCIAL STATEMENTS--(CONTINUED) The following table sets forth Eastern's unaudited pro forma results as if the transaction had occurred on January 1, 1998. Years Ended December 31, (In thousands) 1999 1998 ----------------------------------------------------------------------- Revenues $1,108,977 $1,118,357 Operating earnings 133,049 128,082 Earnings before extraordinary items and accounting change 56,921 54,729 Earnings per common share before extraordinary items and accounting change: Basic $2.11 $2.05 Diluted $2.10 $2.03 Weighted average number of common shares outstanding: Basic 26,920 26,693 Diluted 27,063 26,899 ESSEX GAS MERGER On September 30, 1998, Eastern completed a merger with Essex Gas by exchanging approximately 2.0 million shares of its common stock for all of the common stock of Essex Gas. Each share of Essex Gas was exchanged for 1.183985 shares of Eastern common stock. The merger was accounted for as a pooling-of- interests and the accompanying consolidated financial statements include the accounts of Essex Gas for all periods. Prior to the merger, Essex Gas' fiscal year ended on August 31. Accordingly, the accompanying Consolidated Statement of Operations includes the year ended December 31, 1998 of Eastern combined with the period from December 1, 1997 through December 31, 1998 for Essex Gas excluding the month of September 1998. The financial statements for 1997 include the year ended December 31 for Eastern combined with the year ended August 31 for Essex Gas. Pre-merger financial results for the separate companies and the combined amounts in the Consolidated Statements of Operations include the nine months ended September 30, 1998 of Eastern combined with the nine months ended August 31, 1998 of Essex Gas and the year ended December 31, 1997 of Eastern combined with the year ended August 31, 1997 of Essex Gas, as follows: Nine Months Ended Year Ended September 30, December 31, 1998 1997 -------------------------------------------------------------------- Revenues: Eastern $635,442 $ 970,204 Essex Gas 41,786 53,536 -------- ---------- Combined $677,228 $1,023,740 ======== ========== Earnings before extraordinary item: Eastern $ 28,717 $ 51,950 Essex Gas 2,478 3,966 -------- ---------- Combined $ 31,195 $ 55,916 ======== ========== The combined financial statements for 1998 and 1997 include adjustments to conform the accounting policies of Essex Gas with those of Eastern. The primary adjustment conformed Essex Gas' method of adoption of SFAS No. 106, "Employers" Accounting for Postretirement Benefits Other Than Pensions" with Eastern's adoption by immediately recognizing the transition obligation of approximately $4.1 million at the date of adoption, September 1, 1994. Since Essex Gas had received regulatory approval to fully recover the SFAS No. 106 costs in rates, a regulatory asset was recorded for the transition obligation and there was no adjustment to income during the pre-merger period. Transaction fees totaled $9,776,000 pre-tax, of which $2,788,000 was incurred and expensed during the nine month period ending September 30, 1998. An additional $750,000 of transaction fees were incurred and expensed in 1997. The remaining $6,238,000 was expensed by Essex Gas in September 1998. Transaction fees primarily include investment banking fees and other professional fees. 10-K/26 NOTES TO FINANCIAL STATEMENTS--(CONTINUED) As a result of the merger and related rate plan approved by the Department, Essex Gas was unable to continue its application of SFAS No. 71, and, effective September 30, 1998, wrote off net regulatory assets approximating $4,500,000 pre-tax or $2,873,000 after-tax, which primarily consisted of deferred postretirement health care costs. In addition, Essex Gas was required to adopt a revenue method which reflects full accrual accounting and which resulted in a minor nonrecurring gain. In conforming Essex Gas' historical periods based on a fiscal year ending August 31 with Eastern's operations and changing Essex Gas' fiscal year-end, consolidated results for the year ended December 31, 1998 include Essex Gas' results for December 1997 and December 1998 and exclude its results for September 1998. Essex Gas' revenues and net earnings for December 1997 were $7,262,000 and $995,000, respectively. Essex Gas' revenues and net loss for September 1998 were $1,374,000 and $8,121,000, respectively. The September 1998 net loss reflected transaction and integration expenses of $5,088,000 and the aforementioned write off of regulatory assets. Essex Gas' revenues and net earnings for the three months ended November 30, 1997 were $9,035,000 and $127,000, respectively. The Consolidated Statement of Cash Flows for 1998 includes the effect of Essex Gas' excluded periods of ($2,103,000) for net operating activity, ($2,178,000) for net investing activity and $4,574,000 for net financing activity. These amounts are reflected in the other captions in the Consolidated Statement of Cash Flows. 5. BUSINESS SEGMENT INFORMATION Effective January 1, 1998, Eastern adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." Pursuant to SFAS No. 131, Eastern's two reportable segments are natural gas distribution and marine transportation. Natural gas distribution, which includes Boston Gas, Colonial Gas and Essex Gas, provides services to customers in eastern and central Massachusetts, and marine transportation, which includes Midland, operates boats and barges on the inland waterways. Other services include ServicEdge, Transgas and AMR Data. Segment information, including operating results and other financial data, is presented below: (In thousands) 1999 1998 1997 ------------------------------------------------------------------------ Revenues: Natural gas distribution $ 690,809 $ 667,106 $ 754,481 Marine transportation 267,269 261,061 269,259 Other services 20,624 7,097 - ---------- ---------- ---------- $ 978,702 $ 935,264 $1,023,740 ========== ========== ========== Operating earnings: Natural gas distribution $ 101,359 $ 88,913 $ 87,773 Marine transportation 21,114 26,634 34,614 Other services (2,932) (9,043) (1,481) Headquarters(1) (6,102) (6,099) (5,589) ---------- ---------- ---------- $ 113,439 $ 100,405 $ 115,317 ========== ========== ========== Identifiable assets, net of depreciation and reserves: Natural gas distribution $1,555,561 $ 952,818 $ 974,021 Marine transportation 377,918 379,676 356,350 Other(2) 86,278 186,118 199,994 ---------- ---------- ---------- $2,019,757 $1,518,612 $1,530,365 ========== ========== ========== Capital expenditures: Natural gas distribution $ 69,265 $ 66,248 $ 62,283 Marine transportation 18,447 46,621 25,700 Other 405 843 1,233 ---------- ---------- ---------- $ 88,117 $ 113,712 $ 89,216 ========== ========== ========== (1) Reflects unallocated corporate general and administrative expenses. (2) Primarily includes cash and short-term investments. 10-K/27 NOTES TO FINANCIAL STATEMENTS--(CONTINUED) (In thousands) 1999 1998 1997 ---------------------------------------------------------------------- Depreciation and amortization: Natural gas distribution $ 55,754 $ 50,870 $ 47,786 Marine transportation 24,345 23,838 22,675 Other 1,274 813 861 --------- --------- --------- $ 81,373 $ 75,521 $ 71,322 ========= ========= ========= Interest expense: Natural gas distribution $ 24,866 $ 22,565 $ 23,067 Marine transportation 13,031 10,830 13,713 Other 1,239 189 631 --------- --------- --------- $ 39,136 $ 33,584 $ 37,411 ========= ========= ========= Income tax provision: Natural gas distribution $ 30,914 $ 27,121 $ 24,792 Marine transportation 4,917 6,534 8,464 Other 323 (4,489) (6,302) --------- --------- --------- $ 36,154 $ 29,166 $ 26,954 ========= ========= ========= Natural gas distribution operations are subject to Massachusetts statutes applicable to gas utilities. Their revenues, earnings and cash flows are highly seasonal as most of their firm sales and transportation are directly related to temperature levels. These operations purchase gas supplies from a variety of producers and marketers, under a combination of long-term commitments, firm winter service agreements and spot purchases. These operations have diversified their gas supplies across major North American producing regions. A significant portion of marine transportation operations relate to multi- year transportation contracts. Based on past experience and its competitive position, management considers that the simultaneous loss of several of its largest customers, while possible, is unlikely to happen. 6. LONG-TERM OBLIGATIONS AND CURRENT DEBT Credit agreements and lines of credit: Eastern maintains credit agreements with groups of banks, which provide for the borrowings by Eastern and its subsidiaries of up to $145,000,000 at various times through December 31, 2001. The interest rate for borrowings is the agent bank's prime rate or, at the borrower's option, various pricing alternatives. The agreements require facility fees ranging from 9.5 to 37.5 basis points on the commitments. In addition, Eastern, Boston Gas, Colonial Gas and Essex Gas have various uncommitted lines of credit which are utilized for working capital needs and provide for interest at the bank's prime rate or, at the borrower's option, various pricing alternatives. At December 31, 1999 and 1998, $80,200,000 and $8,935,000 were outstanding, with a weighted average interest rate of 6.28% and 5.95%, respectively. Boston Gas utilizes a portion of the credit agreement to back its commercial paper borrowings. Included in current debt were $20,000,000 and $37,835,000 of commercial paper with a weighted average interest rate of 6.26% and 5.30% at December 31, 1999 and 1998, respectively. Covenants related to these credit agreements and lines 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. Gas inventory financing: Boston Gas, Colonial Gas and Essex Gas maintain credit agreements with groups of banks, which provide for the borrowing of up to $110,000,000 for the exclusive purpose of funding their inventory of gas supplies or for backing commercial paper issued for the same purpose. All costs related to this funding are recoverable from customers. To fund their inventory of gas supplies, Boston Gas, Colonial Gas and Essex Gas had commercial paper of $70,262,000 ($16,242,000 is reflected in current debt), and $52,644,000 at December 31, 1999 and 1998, respectively. Since $54,020,000 and $52,644,000 of the fuel inventory financing is supported by long-term credit agreements, these borrowings have been classified as non-current in the accompanying consolidated balance sheets in 1999 and 1998, respectively. The Boston Gas credit agreement includes a one-year revolving credit facility which may be converted to a two-year term loan at the option of Boston Gas if the one-year revolving credit facility is not renewed by the banks. Boston Gas may select the agent bank's prime rate or, at Boston Gas' option, various pricing alternatives. The Boston Gas agreement requires a facility fee of 8.5 basis points on the commitment. No borrowings were outstanding under this agreement during 1999 and 1998. 10-K/28 NOTES TO FINANCIAL STATEMENTS--(CONTINUED) Description of long-term debt: December 31, (In thousands) 1999 1998 ------------------------------------------------------------------------ NATURAL GAS DISTRIBUTION: 6.80%-9.75% Unsecured Medium-Term Notes, due 2005-2025 $210,000 $210,000 5.50%-7.38% First Mortgage Medium-Term Notes, due 2003-2028 95,000 - 7.28%-10.25% First Mortgage Bonds due 1999-2022 45,400 21,000 8.15%-8.625% Debenture due 2006-2017 7,157 7,199 Capital leases 16,816 532 Less--current portion (1,641) (660) -------- -------- NATURAL GAS DISTRIBUTION 372,732 238,071 -------- -------- MARINE TRANSPORTATION: First Preferred Ship Mortgages 6.25% Bonds, due 2008, effective 7.50% 69,088 68,619 8.1%-9.85% Medium-Term Notes, Series A, due 2002-2012 67,263 67,423 Capital leases 11,316 16,148 Less--current portion (5,167) (4,742) -------- -------- MARINE TRANSPORTATION 142,500 147,448 -------- -------- TOTAL LONG-TERM DEBT $515,232 $385,519 ======== ======== Natural gas distribution Medium-Term Notes are not callable prior to maturity. The First Mortgage Medium-Term Notes and the First Mortgage Bonds are secured by substantially all the plant assets of Colonial Gas and Essex Gas. The marine transportation First Preferred Ship Mortgage Bonds and Medium- Term Notes are secured by certain transportation equipment. The Medium-Term Notes are not callable prior to maturity. In March 1998 marine transportation utilized available cash to call $50,000,000 of 9.9% First Preferred Ship Mortgage Bonds, due 2008. In extinguishing this debt, marine transportation recognized an extraordinary charge of $2,254,000 pre-tax, $1,465,000 net, or $.06 per share. In September 1998 marine transportation issued $75,000,000 of 6.25% First Preferred Ship Mortgage Bonds maturing October 1, 2008 at a discount. The debt has an effective annual interest rate of 7.50%. Capital leases consist of equipment lease obligations with a weighted average interest rate of 7.68%. Minimum lease payments under these agreements are due in installments through 2014. Debt payment requirements, including capitalized leases and maturities, net of amounts acquired in advance, are $6,808,000, $5,650,000, $6,268,000, $12,034,000 and $1,014,000 for 2000 through 2004, respectively, and cumulatively $490,266,000 thereafter. Five-year operating lease commitments: In addition to the equipment financed under capital leases, Eastern and its subsidiaries lease certain facilities, vessels and equipment under long-term operating leases which expire on various dates through the year 2079. Total rents charged to expense were $12,360,000 in 1999, $10,294,000 in 1998 and $10,887,000 in 1997. Future minimum lease commitments under operating leases are $10,526,000, $9,215,000, $7,628,000, $4,015,000, $3,498,000 for 2000 through 2004, respectively, and cumulatively $24,788,000 thereafter. 7. PREFERRED STOCK OF SUBSIDIARY Boston Gas has 1,080,000 shares outstanding of 6.421% Cumulative Preferred Stock, which is non-voting and has a liquidation value of $25 per share. The preferred stock requires 5% annual sinking fund payments beginning on September 1, 1999 with a final redemption on September 1, 2018. At the option of Boston Gas, the annual sinking fund payment may be increased to 10%. In 1999 Boston Gas redeemed 120,000 shares, or 10% of the original issue, at the liquidation price of $25 per share. The preferred stock is callable beginning in 2003. 10-K/29 NOTES TO FINANCIAL STATEMENTS--(CONTINUED) 8. STOCK PLANS Eastern has three stock option plans which provide for the issuance of non-qualified stock options, incentive stock options and stock appreciation rights ("SARs") to its officers, non-employee trustees and key employees. On September 30, 1998, two stock option plans of Essex Gas were terminated. Options and SARs may be granted at prices not less than fair market value on the date of grant for periods not extending beyond ten years from the date of grant. No SARs have been granted since 1991. In 1995, the right to exercise outstanding SARs was effectively eliminated. Eastern applies Accounting Principles Board Opinion 25 in accounting for its plans. Accordingly, no compensation cost has been recognized for its stock option plans and its employee stock purchase plan. Had compensation cost for Eastern's plans been determined applying SFAS No. 123, "Accounting for Stock- Based Compensation," Eastern's net earnings would have been reduced by $729,000 or $.03 per share in 1999, $542,000 or $.02 per share in 1998, and by $418,000 or $.02 per share in 1997. The weighted average fair value of options granted during 1999, 1998, and 1997 was $39.01, $42.86 and $33.63, respectively. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted- average assumptions used for grants in 1999, 1998 and 1997, respectively: dividend yields of 4.0% in each year; expected volatilities of 17.0%, 16.5% and 17.8%; risk-free interest rates of 5.0%, 5.0% and 6.1%; and an expected life of 5.0 years for each year. Shares available for future grants under these stock option plans were 409,130 at December 31, 1999, 666,927 at December 31, 1998 and 934,760 at December 31, 1997. Option activity during the past three years was as follows: Average Option Stock Price Options SARs -------------------------------- OUTSTANDING AT DECEMBER 31, 1996 $27.96 776,006 87,700 Granted 33.63 161,700 - Exercised 24.57 (52,140) - Surrendered - - (22,500) Canceled 35.52 (3,350) - ------- ------ OUTSTANDING AT DECEMBER 31, 1997 $29.21 882,216 65,200 Granted 42.86 220,850 - Exercised 23.38 (65,843) - Surrendered - - (20,720) Canceled 36.22 (43,000) - ------- ------ OUTSTANDING AT DECEMBER 31, 1998 $32.19 994,223 44,480 Granted 39.01 234,000 - Exercised 27.21 (294,012) - Surrendered - - (28,980) Canceled 36.11 (52,761) (2,050) ------- ------ OUTSTANDING AT DECEMBER 31, 1999 $35.36 881,450 13,450 ======= ====== Stock options exercisable at December 31, 1999 and 1998 were for 378,433 shares and 561,342 shares, respectively. At December 31, 1999, the range of exercise prices of outstanding and exercisable options was $23.44 to $49.97 and $23.44 to $43.59, respectively, with a weighted-average remaining contractual life of options outstanding of 6.8 years. Pursuant to the merger agreement with KeySpan, holders of vested options and holders of unvested options who have employment agreements, pursuant to which their options will vest at a change of control, can elect to receive cash for the excess of $64.00 over the option exercise price at the time of the merger. Options not cashed out in this way will be converted to options to purchase KeySpan stock. Under restricted stock plans for key employees and non-employee trustees, Eastern awarded 5,500 shares in 1998 and 4,400 shares in 1997. Eastern recognized compensation expense of $70,000 in 1999 and 1998 and $109,000 in 1997 in accordance with the vesting terms of these and prior awards. Shares available for future awards under these plans were 27,800 at December 31, 1999 and December 31, 1998. 10-K/30 NOTES TO FINANCIAL STATEMENTS--(CONTINUED) 9. COMMON STOCK PURCHASE RIGHTS On February 22, 1990, Eastern declared a distribution to shareholders of record on March 5, 1990, pursuant to the terms of a Common Stock Rights Agreement (as amended, the "1990 Rights Agreement") between Eastern and BankBoston, N.A., the current Rights Agent, of one common stock purchase right for each outstanding share of common stock. Each right would initially entitle the holder to purchase one share of common stock at an exercise price of $100, subject to adjustment to prevent dilution. The rights become exercisable on the 10th business day after a person acquires 10% or more of Eastern's stock or commences a tender offer for 10% or more of Eastern's stock or such later date as the board determines. The rights may be redeemed by Eastern at any time prior to the 10th day after a 10% position has been acquired at a price of $.01 per right. Eastern may exchange any outstanding rights at any time after a person acquires 10% or more of Eastern stock, but before such person beneficially owns 50% or more of Eastern's stock, for shares of common stock of Eastern at an initial exchange ratio of one share for each right, subject to adjustment and subject to other limitations contained in the 1990 Rights Agreement. The rights will expire on March 5, 2000. If Eastern is acquired in a merger or other business combination, each right will entitle its holder to purchase common shares of the acquiring company having a market value of twice the exercise price of each right (i.e., at a 50% discount). If an acquiror purchases 10% of Eastern's common stock, each right will entitle its holder to purchase a number of Eastern's common shares having a market value of twice the right's exercise price. On July 22, 1998 Eastern declared a dividend of one purchase right (a "New Right") for every outstanding share of Eastern common stock. The New Rights were distributed at the close of business on February 18, 2000 to shareholders of record as of the close of business on such date. The terms of the New Rights are set forth in a Rights Agreement dated as of July 22, 1998 (the "New Rights Agreement") between Eastern and BankBoston, N.A., as Rights Agent. Each New Right would initially entitle the holder to purchase from Eastern one share of Eastern common stock at a price of $160 per share, subject to adjustment. The New Rights will expire on July 22, 2008, or upon the earlier redemption of the New Rights. The material terms of the New Rights Agreement are substantially similar to the terms of the 1990 Rights Agreement discussed above. In connection with the KeySpan-Eastern merger, Eastern has agreed to amend the New Rights Agreement to exempt the anticipated merger. 10. COMMITMENTS AND CONTINGENCIES Eastern maintains employment agreements with 32 employees. The pending KeySpan merger is expected to trigger the change of control provisions under these agreements which, in the event of a termination, provide for one to three times salary and bonus as severance and, in certain circumstances, a tax gross-up and enhanced retirement benefits. Excluding payment for stock options described in Note 8, the maximum contingent liability under these agreements is approximately $33.3 million. In addition, the acquisition of Colonial Gas triggered change of control provisions under agreements with eight Colonial Gas employees. In the event of a termination, these agreements provide for severance and, under certain circumstances, enhanced retirement benefits. The maximum contingent liability under these agreements is approximately $8.5 million. 11. INTEREST EXPENSE Years Ended December 31, (In thousands) 1999 1998 1997 ---------------------------------------------------------------------- Interest on long-term debt $34,863 $29,866 $32,636 Other, including amortization of debt expense 3,334 2,282 3,485 Less--capitalized interest (923) (490) (636) Subsidiary preferred stock dividends 1,862 1,926 1,926 ------- ------- ------- INTEREST EXPENSE $39,136 $33,584 $37,411 ======= ======= ======= INTEREST PAYMENTS $35,782 $32,362 $36,660 ======= ======= ======= 10-K/31 NOTES TO FINANCIAL STATEMENTS--(CONTINUED) 12. OTHER INCOME (EXPENSE) Years Ended December 31, (In thousands) 1999 1998 1997 --------------------------------------------------------------------- Net gain on sale of assets $ 2,125 $ 4,948 $ 778 Environmental reversal and recoveries 5,718 - - Equity in loss of AllEnergy - - (5,472) Other 1,137 643 661 ------- ------- -------- $ 8,980 $ 5,591 $ (4,033) ======= ======= ======== In December 1997, Eastern sold its 50% interest in AllEnergy Marketing Company, L.L.C. for $5,375,000, which approximated the net book value of its investment at September 30, 1997. Eastern accounted for its investment in AllEnergy using the equity method. 13. INCOME TAXES The table below reconciles the statutory U.S. Federal income tax provision from continuing operations to the recorded income tax provision: Years Ended December 31, 1999 1998 1997 -------------------------------------------------------------------- Statutory rate 35% 35% 35% State taxes, net of Federal benefit 4 4 3 Goodwill and merger-related costs 2 - - Capital loss utilization - (2) - Adjustment - - (4) Other (1) (1) (1) -- -- -- Effective rate 40% 36% 33% == == == The adjustment in 1997 reflects the resolution of Federal tax audit issues on the sale of a subsidiary in 1993 and inventory capitalization in 1994. Following is a summary of the provision for income taxes: Years Ended December 31, (In thousands) 1999 1998 1997 ------------------------------------------------------------------ Federal $19,554 $22,747 $13,152 State 4,513 5,429 4,498 ------- ------- ------- TOTAL CURRENT PROVISION 24,067 28,176 17,650 Federal 10,134 1,470 9,706 State 1,953 (480) (402) ------- ------- ------- TOTAL DEFERRED PROVISION 12,087 990 9,304 ------- ------- ------- PROVISION FOR INCOME TAXES $36,154 $29,166 $26,954 ======= ======= ======= TAX PAYMENTS $26,809 $32,567 $ 8,758 ======= ======= ======= Significant items making up deferred tax assets and deferred tax liabilities are as follows: December 31, (In thousands) 1999 1998 ------------------------------------------------------------------ Environmental reserves $ 7,275 $ 7,495 Other 41,756 35,339 --------- --------- TOTAL DEFERRED TAX ASSETS 49,031 42,834 Accelerated depreciation (203,593) (161,209) Deferred gas costs (15,981) (12,332) Other (19,710) (20,818) --------- --------- TOTAL DEFERRED TAX LIABILITIES (239,284) (194,359) --------- --------- TOTAL DEFERRED TAXES $(190,253) $(151,525) ========= ========= 10-K/32 NOTES TO FINANCIAL STATEMENTS--(CONTINUED) 14. ENVIRONMENTAL MATTERS Eastern is aware of certain non-utility sites, associated with former operations, for which it may have or share environmental remediation responsibility or ongoing maintenance. Eastern has a reserve of approximately $20 million in total at December 31, 1999 to cover the remediation and maintenance of these sites, the principal of which is a former coal tar processing facility (the "Facility") in Everett, Massachusetts. In 1999 Eastern reduced the reserve by $3.2 million related to the regulatory clearance of one site. While Eastern has provided reserves to cover the estimated probable costs of remediation and maintenance for environmental sites based on the information available at the present time, the extent of Eastern's potential liability at such sites is not yet determined. The Facility, which was located on a 10-acre parcel of land formerly owned by Eastern, was operated by Allied-Signal, Inc., predecessor of Honeywell International, Inc., from the early 1900s until 1937 and by Koppers Company, predecessor of Beazer East, Inc. (and Eastern's controlling stockholder until 1951) from 1937 until 1960, when it was shut down. The Facility processed coal tar purchased from Eastern's adjacent by-product coke plant, also shut down in 1960. Eastern, Beazer and Honeywell ("the Companies") entered into an Administrative Consent Order with the Massachusetts Department of Environmental Protection ("DEP") in 1989 which requires that they jointly investigate and develop a remedial response plan for the Facility site, including any area where a release from that site may have come to be located. The Companies have entered into a cost-sharing agreement under which each company has agreed to pay one-third of the costs of compliance with the consent order, while preserving any claims it may have against the other companies. In 1993, the Companies completed preliminary remedial measures, including abatement of seepage of materials into the adjacent Island End River, a 29-acre tidal river which is part of Boston Harbor. Studies have identified compounds that may be associated with coal tar and/or oil in soil and ground water at the site and adjacent areas, including the riverbed. In addition to the DEP, the National Oceanic and Atmospheric Administration and the Coast Guard have been involved in river sediment investigation and remediation discussions. During 1995 and 1996, the Companies conducted and received the results of certain sediment sampling which confirmed findings of contamination in the riverbed. The Coast Guard has been working with the DEP since July 1998 to bring about a remedial solution that would abate the continuing sheening problem in the Island End River. Eastern, Beazer and Honeywell have proposed a remedial solution, a major element of which is the utilization of a containment structure with limited dredging. As yet, however, no agreement has been reached with the regulators as to the appropriate remedial solution. In light of uncertainties as to the full extent and sources of releases of compounds, the nature of the required remediation, the area and volume of soil, ground water and/or sediments that may be included, the possibility of participation by additional potentially responsible parties and the apportionment of liability, Eastern does not possess at this time sufficient information to reasonably determine or estimate the ultimate cost to it of such remedial measures. Eastern is recovering certain costs of its legal defense and may be entitled to recover remediation costs from its insurers. In 1999 Eastern recovered $2.5 million of prior defense costs from insurance carriers. Eastern's natural gas distribution operations, like many other companies in the natural gas industry, are parties to governmental proceedings requiring investigation and possible remediation of former manufactured gas plant ("MGP") sites. Boston Gas, Colonial Gas and Essex Gas may have or share responsibility under applicable environmental laws for the remediation of 28 such sites. A subsidiary of New England Electric System ("NEES") has assumed responsibility for remediating 11 of these sites, subject to a limited contribution from Boston Gas. Boston Gas, Colonial Gas and Essex Gas have estimated their potential share of the costs of investigating and remediating former MGP sites in accordance with SFAS No. 5, "Accounting for Contingencies," and the American Institute of Certified Public Accountants Statement of Position 96-1, "Environmental Remediation Liabilities." These operations have recorded liabilities of $19.2 million, which represents their best estimate at this time of remediation costs, which may reasonably be estimated to range from $18 million to $34 million. However, there can be no assurance that such costs will not vary considerably from these estimates. Factors that may bear on costs differing from estimates include, without limit, changes in regulatory standards, changes in remediation technologies and practices and the type and extent of contaminants discovered at the sites. Boston Gas, Colonial Gas and Essex Gas are aware of 30 other former MGP sites within their service territories. The NEES subsidiary has provided full indemnification to Boston Gas with respect to eight of these sites. At this time, there is substantial uncertainty as to whether Boston Gas, Colonial Gas or Essex 10-K/33 NOTES TO FINANCIAL STATEMENTS--(CONTINUED) Gas have or share responsibility for remediating any of these other sites. No notice of responsibility has been issued to Boston Gas, Colonial Gas or Essex Gas for any of these sites from any governmental environmental authority. By a rate order issued on May 25, 1990, the Department approved the recovery of all prudently incurred environmental response costs associated with former MGP sites over separate, seven-year amortization periods, without a return on the unamortized balance. Eastern's natural gas operations have recognized an insurance receivable of $3.3 million, reflecting a negotiated settlement with an insurance carrier for environmental expense indemnity, and a regulatory asset of $14.7 million, representing the expected rate recovery of environmental remediation costs, net of the insurance settlement. Eastern currently believes, in light of the indemnity agreement with the NEES subsidiary and the Department rate order on environmental cost recovery, that it is not probable that such costs will materially affect its financial condition or results of operations. 15. UNBILLED REVENUE ACCOUNTING CHANGE During the fourth quarter of 1998, Boston Gas changed its method of accounting for unbilled revenues, retroactively applied as of January 1, 1998. Previously, substantially all revenues were recorded when billed. Boston Gas defers the cost of any firm gas that has been distributed, but is unbilled at the end of a period in which gas is billed to customers. Under the new method, the estimated margin on unbilled revenues is recorded at the end of each accounting period. This accrual method of accounting for revenues is the prevalent method in the utility industry. The cumulative effect of this accounting change at January 1, 1998 was to increase net earnings by $8,193,000, or $.36 per share. The effect of this accounting change was to increase earnings before extraordinary items and accounting change by $405,000, or $.02 per share, for the year ended December 31, 1998. The pro forma effect of retroactively applying this method to 1997 was not material. 16. COAL MINERS RETIREE HEALTH CARE On June 25, 1998 the U.S. Supreme Court ruled that the Coal Industry Retiree Health Benefit Act of 1992 ("Coal Act") is unconstitutional as applied to Eastern. Accordingly, previously recorded reserves not used, less associated expenses, resulted in an extraordinary gain of $74,500,000 pre-tax, $48,425,000 net, or $2.13 per share, in the second quarter of 1998. In 1993, Eastern recorded a reserve of $70,000,000 ($45,500,000 net of tax, or $1.88 per share) to provide for its estimated undiscounted obligations under the Coal Act with respect to notices of responsibility received from the Social Security Administration in that year. The notices claimed that Eastern was responsible for health care and death benefit premiums for certain retired coal miners and their beneficiaries who were said to have worked for Eastern's Coal Division prior to the transfer of those operations to a subsidiary in 1965. Principally due to receipt of additional notices, in 1995 Eastern recorded an additional reserve of $10,000,000 ($6,500,000 net of tax or $.30 per share). Provisions to establish these reserves were accounted for as extraordinary items. Eastern never paid any premiums under the Coal Act. 17. RETIREE BENEFITS Eastern and its subsidiaries, through various company-administered plans and other union retirement and welfare plans, provide retirement benefits for the majority of their employees, including pension and certain health care and life insurance benefits. Normal retirement age ranges from 60 to 65, but provision is made for earlier retirement. Pension benefits for salaried plans are based on salary and years of service, while union retirement and welfare plans are based on negotiated benefits and years of service. Employees, excluding Essex Gas employees, hired before 1993 who are participants in the pension plans become eligible for postretirement health care benefits if they reach retirement age while working for Eastern. The funding of retirement and employee benefit plans is in accordance with the requirements of the plans and, where applicable, in sufficient amounts to satisfy the "Minimum Funding Standards" of the Employee Retirement Income Security Act ("ERISA"). 10-K/34 NOTES TO FINANCIAL STATEMENTS--(CONTINUED) Effective January 1, 1998, Eastern adopted SFAS No. 132, "Employers" Disclosures about Pensions and Other Postretirement Benefits," which revises prior disclosure requirements. The information for 1997 has been restated to conform to this presentation. The net cost for these plans and agreements charged to expense was as follows: Pensions Years Ended December 31, (In thousands) 1999 1998 1997 -------------------------------------------------------------------------- Service cost $ 5,687 $ 5,250 $ 5,145 Interest cost on projected benefit obligation 15,449 13,300 12,808 Expected return on plan assets (19,415) (17,049) (15,820) Amortization of prior service cost 1,744 1,552 1,501 Amortization of transitional obligation 397 424 424 Recognized actuarial gain (664) (599) (263) Settlement and curtailment gain (1,268) (490) (2,314) -------- -------- -------- Total net pension cost of company- administered plans 1,930 2,388 1,481 Multi-employer union retirement and welfare plans 445 475 270 -------- -------- -------- Total net pension cost $ 2,375 $ 2,863 $ 1,751 ======== ======== ======== Health Care Years Ended December 31, (In thousands) 1999 1998 1997 ---------------------------------------------------------------------------- Service cost $ 984 $ 1,066 $ 1,007 Interest cost on accumulated benefits obligation 7,649 7,425 7,147 Expected return on plan assets (2,319) (2,131) (1,585) Amortization of prior service cost (1,317) (1,374) (1,170) Recognized actuarial gain (280) (399) (229) Regulatory deferral 5,359 5,359 4,841 -------- -------- -------- Total net retiree health care cost $ 10,076 $ 9,946 $ 10,011 ======== ======== ======== The tables above do not reflect pension enhancements at natural gas distribution operations of $2,593,000 and $3,847,000 for 1999 and 1998, respectively, and retirement health care enhancements of $353,000 and $698,000 for 1999 and 1998, respectively. 10-K/35 NOTES TO FINANCIAL STATEMENTS--(CONTINUED) The following tables set forth the change in benefit obligation and plan assets, reconciliation of funded status and amounts recognized in other comprehensive income of company-administered plans and amounts recorded in Eastern's consolidated balance sheets as of December 31, 1999 and 1998 using actuarial measurement dates as of October 1, 1999 and 1998:
Pensions Health Care (In thousands) 1999 1998 1999 1998 - ------------------------------------------------------------------------------------------------------- CHANGE IN BENEFIT OBLIGATION Balance at beginning of year $254,429 $181,330 $ 115,048 $102,239 Service cost 5,687 5,250 984 1,066 Interest cost 15,449 13,300 7,649 7,425 Plan amendments 639 1,264 1,406 - Curtailment (gain) 98 (635) (106) (85) Settlement (gain) 333 (294) - - Special termination benefits 2,593 3,868 353 698 Benefits paid (11,071) (10,159) (7,354) (6,642) Settlement payments (3,665) - - - Actuarial (gain) or loss 858 4,143 (1,591) (474) -------- -------- --------- -------- Balance at end of year $265,350 $198,067 $ 116,389 $104,227 ======== ======== ========= ======== CHANGE IN PLAN ASSETS Fair value at beginning of year $277,772 $241,734 $ 31,653 $ 25,263 Actual return on plan assets 17,957 (6,789) 926 439 Employer contributions 901 1,121 7,034 6,936 Benefits paid (11,071) (10,220) (7,354) (6,642) Special termination benefits (3,665) - - - -------- -------- --------- -------- Fair value at end of year $281,894 $225,846 $ 32,259 $ 25,996 ======== ======== ========= ======== RECONCILIATION OF FUNDED STATUS Funded status $ 16,544 $ 27,779 $ (84,130) $(78,231) Contributions for fourth quarter 387 208 1,757 1,591 Unrecognized actuarial (gain) (34,592) (35,646) (10,465) (10,292) Unrecognized transition obligation 336 734 - - Unrecognized prior service 17,575 15,075 (7,543) (10,265) -------- -------- --------- -------- Net amount recognized at end of year $ 250 $ 8,150 $(100,381) $(97,197) ======== ======== ========= ======== AMOUNTS RECOGNIZED IN BALANCE SHEET Prepaid benefit cost $ 24,409 $ 23,416 $ - $ - Accrued benefit liability (28,441) (20,383) (100,381) (97,197) Intangible asset 2,759 3,032 - - Accumulated other comprehensive income 1,523 2,085 - - -------- -------- --------- -------- Net amount $ 250 $ 8,150 $(100,381) $(97,197) ======== ======== ========= ======== Other comprehensive income pre-tax $ 632 $ 732 $ - $ - ======== ======== ========= ========
To fund health care benefits under its collective bargaining agreements, Boston Gas and Essex Gas maintain voluntary employee beneficiary associations, to which they make contributions from time to time. Essex Gas made contributions during 1997 of $560,241. Plan assets are invested in debt and equity marketable securities. Following are the weighted-average assumptions used in developing the projected benefit obligation for 1999, 1998 and 1997: 1999 1998 1997 ---- ---- ---- Discount rate 7.5% 7.25% 7.5% Return on plan assets 8.5% 8.5% 8.5% Increase in future compensation 4.0%-4.5% 4.5%-5.0% 4.75%-5.0% Health care inflation trend 8.0%-10.0% 8.0% 7.0-8.75% 10-K/36 NOTES TO FINANCIAL STATEMENTS--(CONTINUED) The health care inflation trend for individuals not yet 65 years of age is assumed to be 8.0% in 2000 and decreasing gradually to 5.0% in 2008. The health care inflation rate for individuals 65 years of age or older is 10.0% in 2000 and decreasing gradually to 5.0% in 2008. A one-percentage point increase (decrease) in the assumed health care trend rate for 1999 would have the following effects: One-Percentage One-Percentage (In thousands) Point Increase Point Decrease ----------------------------------------------------------------------- Total of service and interest cost components $ 633 $ (559) Postretirement benefit obligation $8,658 $(7,591) See Note 4 for discussion of the adjustment conforming Essex Gas' method of adoption of SFAS No. 106. 18. FAIR VALUES OF FINANCIAL INSTRUMENTS Pursuant to SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities," which requires investments in debt and equity securities other than those accounted for under the equity method to be carried at fair value or amortized cost for debt securities expected to be held to maturity, Eastern has classified its investments in debt and equity securities as available for sale. Accordingly, the net unrealized gains and losses computed in marking these securities to market have been reported as a component of other comprehensive income. The difference between the fair value and the original cost of these securities is a net unrealized gain of $867,000 and $1,250,000, at December 31, 1999 and 1998, respectively. The following methods and assumptions were used to estimate the fair value disclosures for financial instruments: Cash and short-term investments and short-term debt: The carrying amounts approximate fair value because of the short maturity of those instruments. Short-term debt includes notes payable and gas inventory financing. Marketable securities and investments: Marketable securities and investments include marketable securities classified as available for sale. Pursuant to SFAS No. 115 the carrying value is the fair value based on currently quoted market prices. Long-term debt and preferred stock of subsidiary: The fair values are based on currently-quoted market prices. The carrying amounts and estimated fair values of Eastern's financial instruments are as follows:
December 31, (In thousands) 1999 1998 - ------------------------------------------------------------------------------------------------------- Carrying Fair Carrying Fair Amount Value Amount Value -------- -------- -------- -------- Cash and short-term investments $ 44,332 $ 44,332 $159,836 $159,836 Marketable securities and investments 14,975 14,975 15,801 15,801 Short-term debt 170,463 170,463 90,479 90,479 Long-term debt 522,040 515,187 390,921 443,927 Preferred stock of subsidiary 26,454 26,730 29,360 30,076
10-K/37 NOTES TO FINANCIAL STATEMENTS--(CONTINUED) 19. UNAUDITED QUARTERLY FINANCIAL INFORMATION Unaudited quarterly financial information for 1998 has been restated to reflect the retroactive change of accounting described in Note 15.
For the three months ended (In thousands, except per share amounts) Mar. 31, June 30, Sept. 30, Dec. 31, - ---------------------------------------------------------------------------------------------------------- 1999: Revenues $344,829 $170,520 $144,978 $318,375 Operating earnings 57,946 1,697 (4,830) 58,626 EARNINGS BEFORE INCOME TAXES 52,309 (4,107) (3,848) 46,893 NET EARNINGS $ 32,296 $ (2,568) $ (2,823) $ 28,188 ======== ======== ======== ======== BASIC EARNINGS PER SHARE $1.43 $(.11) $(.12) $1.04 ===== ===== ===== ===== DILUTED EARNINGS PER SHARE $1.42 $(.11) $(.12) $1.03 ===== ===== ===== ===== 1998: Revenues $352,922 $188,425 $135,881 $258,036 Operating earnings 55,624 11,804 (4,526) 37,503 Earnings before income taxes 50,344 6,393 (7,398) 30,655 EARNINGS BEFORE EXTRAORDINARY ITEMS AND ACCOUNTING CHANGE $ 31,067 $ 3,882 $ (3,754) $ 19,633 Extraordinary items, net of tax (1,465) 48,425 - - Accounting change, net of tax 8,193 - - - -------- -------- -------- -------- NET EARNINGS $ 37,795 $ 52,307 $ (3,754) $ 19,633 ======== ======== ======== ======== BASIC EARNINGS PER SHARE BEFORE EXTRAORDINARY ITEMS AND ACCOUNTING CHANGE $1.39 $ .16 $(.17) $ .88 Extraordinary items, net of tax (.07) 2.16 - - Accounting change, net of tax .37 - - - ----- ----- ----- ----- Net earnings $1.69 $2.32 $(.17) $ .88 ===== ===== ===== ===== DILUTED EARNINGS PER SHARE BEFORE EXTRAORDINARY ITEMS AND ACCOUNTING CHANGE $1.37 $ .17 $(.17) $ .87 Extraordinary items, net of tax (.06) 2.13 - - Accounting change, net of tax .36 - - - ----- ----- ----- ----- Net earnings $1.67 $2.30 $(.17) $ .87 ===== ===== ===== =====
10-K/38 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS TO THE TRUSTEES AND SHAREHOLDERS OF EASTERN ENTERPRISES: We have audited the accompanying consolidated balance sheets of Eastern Enterprises (a Massachusetts voluntary association) and subsidiaries as of December 31, 1999 and 1998, and the related consolidated statements of operations, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1999. 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 auditing standards generally accepted in the United States. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Eastern Enterprises and subsidiaries as of December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. As explained in Note 15 to the financial statements, effective January 1, 1998, the Company changed its method of accounting for unbilled revenues at Boston Gas Company. /s/ Arthur Andersen Arthur Andersen LLP Boston, Massachusetts January 21, 2000 MANAGEMENT'S REPORT ON RESPONSIBILITY The management of Eastern is responsible for the preparation, integrity and fair presentation of the Company's financial statements. These statements have been prepared in accordance with generally accepted accounting principles and, as such, include amounts based on management's informed judgments and estimates. The financial statements have been audited by the independent accounting firm of Arthur Andersen LLP which was given unrestricted access to all financial records and related data. Eastern maintains a system of internal control over financial reporting which is designed to provide reasonable assurance to the Company's management and Board of Trustees regarding the preparation of reliable financial statements and the safeguarding of assets. The system includes a documented organizational structure and division of responsibility, an internal audit staff, the careful selection and development of personnel and established policies and procedures, including policies to foster a strong ethical climate and control environment, which are communicated throughout Eastern. The Audit Committee of the Board of Trustees, consisting solely of outside trustees, meets periodically with management, internal auditors and the independent auditors to review internal accounting controls, and the accounting principles and practices used to report financial condition and the results of operations. The Audit Committee also annually recommends to the Board of Trustees the selection of independent auditors. /s/ J. Atwood Ives /s/ Walter J. Flaherty /s/ James J. Harper J. Atwood Ives Walter J. Flaherty James J. Harper Chairman and Executive Vice President and Vice President Chief Executive Officer Chief Financial Officer and Controller 10-K/39 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information with respect to this item may be found in the sections captioned "Information With Respect To Nominees and Trustees" appearing on pages 47 through 49 and "Section 16(a) Beneficial Ownership Reporting Compliance" appearing on page 56 and "Certain Transactions and Other Disclosures" appearing on page 61 of the 1999 definitive Proxy Statement. Such information is incorporated herein by reference. See also the item captioned "Executive Officers of the Registrant" at the end of Part I hereof. ITEM 11. EXECUTIVE COMPENSATION Information with respect to this item may be found in the sections captioned "Compensation of Executive Officers" appearing on pages 51 through 54, "Compensation of Trustees" appearing on page 55, "Termination of Employment and Change of Control Arrangements" appearing on page 56, "Compensation Committee Report" appearing on pages 57 through 59 and "Performance Graph" appearing on page 60 of the 2000 definitive Proxy Statement. Such information is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Information with respect to this item may be found in the sections captioned "Information With Respect To Certain Shareholders" appearing on page 62 and "Stock Ownership of Trustees and Executive Officers" appearing on page 50 of the 2000 definitive Proxy Statement. Such information is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Information with respect to this item may be found in the sections captioned "Compensation of Trustees" appearing on page 55 and "Certain Transactions and Other Disclosures" appearing on page 61 of the 2000 definitive Proxy Statement. Such information is incorporated herein by reference. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) (1) AND (2) LIST OF FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES Exhibits and Financial Statement Schedules to the Form 10-K have been included only with the copies of the Form 10-K filed with the SEC. A copy of this Form 10-K, including a list of exhibits and Financial Statement Schedules is available free of charge upon written request to: Corporate Relations Department, Eastern Enterprises, 9 Riverside Road, Weston, MA 02493. 10-K/40 (3) LIST OF EXHIBITS 2.1 -- Agreement and Plan of Reorganization dated as of July 14, 1999, by and between Eastern, EE Acquisition Company, Inc. and EnergyNorth, Inc., including Amendment No. 1 dated November 4, 1999 (incorporated by reference to Exhibit 2.1 to Registration Statement on Form S-4 of Eastern Enterprises, dated January 28, 2000 (File No. 333-95693)).* 2.2 -- Agreement and Plan of Merger, dated as of November 4, 1999, by an among Eastern Enterprises, KeySpan Energy Corporation and ACJ Acquisition LLC (incorporated by reference to Exhibit 2 of Current Report on Form 8-K of KeySpan Energy Corporation dated November 4, 1999 (Commission File No. 001-14161)).* 2.3 -- Amendment No. 1 to Agreement and Plan of Merger, dated as of January 26, 2000, by and among Eastern Enterprises, KeySpan Energy Corporation and ACJ Acquisition LLC. 3.1 -- Declaration of Trust of Eastern Enterprises, as amended through April 27, 1989 (filed as Exhibit 3.1 to Quarterly Report of Eastern Enterprises on Form 10-Q for the quarter ended June 30, 1989 (File No. 1-2297)).* 3.2 -- By-Laws of Eastern Enterprises, as amended through February 24, 1999 (incorporated by reference to Exhibit 3.2 to Annual Report on Form 10-K of Eastern for the year ended December 31, 1998 (File No. 1-2297)).* (NOTE: Eastern agrees to furnish to the Securities and Exchange Commission upon request a copy of any instrument with respect to long-term debt of Eastern or any of its subsidiaries. Such instruments are not filed herewith since no such instrument authorizes securities in an amount greater than 10% of the total assets of Eastern and its subsidiaries on a consolidated basis.) 4.1 -- Common Stock Rights Agreement between Eastern and The Bank of New York, dated as of February 22, 1990, and Exhibits attached thereto (incorporated by reference to Exhibit 1 to Form 8-K of Eastern dated March 1, 1990 (File No. 1-2297)).* 4.1.1 -- Agreement between Eastern and The First National Bank of Boston, dated January 30, 1995 (incorporated by reference to Exhibit 4.1.1 to Annual Report of Eastern on Form 10-K for year ended December 31, 1994 (File No. 1-2297)).* 4.1.2 -- Amendment No. 2 to Common Stock Rights Agreement, dated as of July 22, 1998, between Eastern and BankBoston, N.A. (incorporated by reference to Exhibit 99.1 to Form 8-K of Eastern filed July 28, 1998 (File No. 1-2297)).* 4.1.3 -- Rights Agreement, dated as of July 22, 1998, between Eastern and BankBoston, N.A. (incorporated by reference to Exhibit 99.2 to Form 8-K of Eastern filed July 28, 1998 (File No. 1-2297)).* 10.1 -- Agreement, dated as of September 14, 1999, by and between Boston Gas Company, Essex Gas Company, Colonial Gas Company and El Paso Energy Marketing Company (Redacted)+ 10.2 -- Eastern's amended and restated Deferred Compensation Plan for Trustees, dated April 22, 1998 (incorporated by reference to Exhibit 10.5.2 to Quarterly Report on Form 10-Q for the quarter ended March 31, 1998 (File No. 1-2297)).*(a) 10.2.1 -- Amendment to Eastern's Amended and Restated Deferred Compensation Plan for Trustees, dated as of October 27, 1999. (a) 10.2.2 -- Amendment to Eastern's Amended and Restated Deferred Compensation Plan for Trustees, dated as of December 20, 1999. (a) 10.3 -- Eastern's 1982 Stock Option Plan, as amended (incorporated by reference to Exhibit 10.2 to Quarterly Report of Eastern on Form 10-Q for the quarter ended March 31, 1992 (File No. 1-2297)).*(a) 10.4 -- Eastern's 1995 Stock Option Plan (incorporated by reference to Exhibit 10.9 to Annual Report of Eastern on Form 10-K for the year ended December 31, 1994 (File No. 1-2297)).*(a) 10.5 -- Eastern's Amended and Restated Supplemental Executive Retirement Plan. (a) 10.6 -- Trust Agreement between Eastern and Shawmut Bank of Boston, N.A., as amended (incorporated by reference to Exhibit 10.12 to the Annual Report of Eastern on Form 10-K for the year ended December 31, 1990 (File No. 1-2297)).*(a) 10.6.1 -- Amendment to Trust Agreement between Eastern and Shawmut Bank of Boston, N.A. (incorporated by reference to Exhibit 10.2 to Quarterly Report of Eastern on Form 10-Q for quarter June 30, 1995 (File No. 1-2297)).*(a) 10.6.2 -- Amendment to Trust Agreement between Eastern and the Key Trust Company of Ohio, N.A., as successor trustee, dated December 8, 1995 (incorporated by reference to Exhibit 10.9.2 to Annual Report of Eastern on Form 10-K for year ended December 31, 1995 (File No. 1-2297)).*(a) 10.6.3 -- Amendment to Trust Agreement between Eastern and Key Trust Company of Ohio, N.A., as successor trustee, dated February 25, 1998 (incorporated by reference to Exhibit 10.9.3 to Quarterly Report on Form 10-Q for the quarter ended March 31, 1998 (File No. 1-2297)).*(a) 10.6.4 -- Amendment, dated as of September 22, 1999, to Trust Agreement between Eastern and Key Trust Company of Ohio, N.A. (a) 10.7 -- Eastern's Executive Incentive Compensation Plan, as amended (incorporated by reference to Exhibit 10.3 to Quarterly Report of Eastern on Form 10-Q for the quarter ended March 31, 1992 (File No. 1-2297)).*(a) 10.8.1 -- Change of Control Agreement, dated as of September 22, 1999, by and between Eastern and J. Atwood Ives (incorporated by reference to Exhibit 10.11.1 to Quarterly Report of Eastern on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-2297)).*(a) 10.8.2 -- Change of Control Agreement, dated as of September 22, 1999, by and between Eastern and Fred C. Raskin (incorporated by reference to Exhibit 10.11.2 to Quarterly Report of Eastern on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-2297)).*(a) 10.8.3 -- Change of Control Agreement, dated as of September 22, 1999, by and between Eastern and Walter J. Flaherty (incorporated by reference to Exhibit 10.11.3 to Quarterly Report of Eastern on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-2297)).*(a) 10.8.4 -- Change of Control Agreement, dated as of September 22, 1999, by and between Eastern and L. William Law, Jr. (incorporated by reference to Exhibit 10.11.4 to Quarterly Report of Eastern on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-2297)).*(a) 10.8.5 -- Change of Control Agreement, dated as of September 22, 1999, by and between Eastern, Boston Gas Company and Chester R. Messer (incorporated by reference to Exhibit 10.11.5 to Quarterly Report of Eastern on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-2297)).*(a) 10.8.6 -- Change of Control Agreement, dated as of September 22, 1999, by and between Eastern, Midland Enterprises Inc. and J. Mark Cook (incorporated by reference to Exhibit 10.11.6. to Quarterly Report of Eastern on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-2297)).*(a) 10.9 -- Agreement dated November 27, 1991 between Eastern and J. Atwood Ives (incorporated by reference to Exhibit 10.14 to the Annual Report of Eastern on Form 10-K for the year ended December 31, 1991 (File No. 1-2297)).*(a) 10.10 -- Agreement dated October 25, 1991 between Eastern and Richard R. Clayton (incorporated by reference to Exhibit 10.15 to the Annual Report of Eastern on Form 10-K for the year ended December 31, 1991 (incorporated by reference to Exhibit 10.14 to Annual Report of Eastern on Form 10-K for the year ended December 31, 1998 (File No. 1-2297)).*(a) 10.11 -- Letter Agreement, dated May 22, 1998, by and between Eastern and Richard R. Clayton (incorporated by reference to Exhibit 10.14 to Annual Report of Eastern on Form 10- K for the year ended December 31, 1998 (File No. 1-2297)).*(a) 10.12 -- Employment Agreement, dated as of September 1, 1998, by and between Eastern and Fred C. Raskin (incorporated by reference to Exhibit 10.2 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1998 (File No. 1-2297)).*(a) 10.13 -- Eastern's Retirement Plan for Non-Employee Trustees, as amended (incorporated by reference to Exhibit 10.22 to Annual Report of Eastern on Form 10-K for the year ended December 31, 1992 (File No. 1-2297)).*(a) 10.13.1 -- Amendment to Eastern's Retirement Plan for Non-Employee Trustees, dated December 8, 1995 (incorporated by reference to Exhibit 10.20.1 to Annual Report of Eastern on Form 10-K for the year ended December 31, 1995 (File No. 1-2297)).*(a) 10.14 -- Eastern's 1996 Non-Employee Trustees' Stock Option Plan (incorporated by reference to Exhibit 10.21 to Annual Report of Eastern on Form 10-K for the year ended December 31, 1995 (File No. 1-2297)).*(a) 10.14.1 -- Amendment to Eastern's 1996 Non-Employee Trustees' Stock Option Plan (incorporated by reference to Exhibit 10.21.1 to Quarterly Report on Form 10-Q for the quarter ended March 31, 1998 (File No. 1-2297)).*(a) 10.15 -- Eastern's 1992 Restricted Stock Plan (incorporated by reference to Exhibit 10.1 to Quarterly Report of Eastern on Form 10-Q for the quarter ended March 31, 1992 (File No. 1-2297)).*(a) 10.16 -- Eastern's Restricted Stock Plan for Non-Employee Trustees (incorporated by reference to Exhibit 10.24 to Annual Report of Eastern on Form 10-K for the year ended December 31, 1992 (File No. 1-2297)).*(a) 10.16.1 -- Amendment dated as of September 22, 1999, to Eastern's Restricted Stock Plan for Non-Employee Trustees (incorporated by reference to Exhibit 10.23.1 to Quarterly Report of Eastern on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-2297)).* 10.17 -- Eastern's 1994 Deferred Compensation Plan (incorporated by reference to Exhibit 10.22 to Annual Report of Eastern on Form 10-K for year ended December 31, 1993 (File No. 1-2297)).*(a) 10.17.1 -- Amendment to Eastern's Deferred Compensation Plan, dated December 8, 1995 (incorporated by reference to Exhibit 10.24.1 to Annual Report of Eastern on Form 10-K for the year ended December 31, 1995 (File No. 1-2297)).*(a) 10.17.2 -- Amendment to Eastern's Deferred Compensation Plan, dated July 25, 1996 (incorporated by reference to Exhibit 10.24.2 to Annual Report of Eastern on Form 10-K for the year ended December 31, 1996 (File No. 1-2297)).*(a) 10.18 -- Eastern's Enterprises Executive Stock Purchase Loan Plan, as amended February 27, 1997 (incorporated by reference to Exhibit 10.25 to Annual Report of Eastern on Form 10-K for year ended December 31, 1996 (File No. 1-2297)).* 10.19 -- Credit Agreement, dated as of December 31, 1994, by and between Eastern, Boston Gas, Midland, the Banks named therein and The First National Bank of Boston, individually and as Agent (incorporated by reference to Exhibit 10.26 to Annual Report of Eastern on Form 10-K for year ended December 31, 1996 (File No. 1-2297)).* 10.19.1 -- Amendment No. 1 to Credit Agreement, dated as of December 31, 1995, by and among Eastern, Boston Gas, Midland, the Banks named therein and The First National Bank of Boston, individually and as Agent (incorporated by reference to Exhibit 10.26.1 to Annual Report of Eastern on Form 10-K for the year ended December 31, 1996 (File No. 1-2297)).* 10.19.2 -- Amendment No. 2 to Credit Agreement, dated as of December 31, 1996, by and among Eastern, Boston Gas, Midland, the Banks named therein and The First National Bank of Boston, individually and as Agent (incorporated by reference to Exhibit 10.26.2 to Annual Report of Eastern on Form 10-K for year ended December 31, 1996 (File No. 1-2297)).* 10.19.3 -- Amendment No. 3 to Credit Agreement, dated as of August 20, 1999, by and among, Eastern, Boston Gas Company and Midland enterprises Inc., the Banks named therein and BankBoston, N.A., individually and as Agent. 13.1 -- Portions incorporated herein of annual report to shareholders for the year ended December 31, 1999. With the exception of the sections captioned "Six-Year Financial Summary" appearing on page 20 and "Stock Price Range" and "Dividends Declared Per Share" appearing on the inside back cover of the said annual report, which are incorporated by reference in Items 5 and 6 of this Form 10-K. Said annual report is not deemed filed as part of this report. 21.1 -- Subsidiaries of the registrant. 23.1 -- Consent of Arthur Andersen LLP. 27.1 -- Financial Data Schedule for the twelve months ended December 31, 1999. Eastern will furnish a copy of any exhibit not included herewith to any holder of Eastern's common stock upon payment of the cost of reproduction and mailing. (B) REPORTS ON FORM 8-K Eastern filed a Current Report on Form 8-K on November 8, 1999. - ---------- *Not filed herewith. In accordance with Rule 12b-32 of the General Rules and Regulations under the Securities and Exchange Act of 1934, reference is made to the document previously filed with the Commission. + Confidential Treatment Requested. (a) Indicates a management contract or compensatory plan or arrangement. EASTERN ENTERPRISES AND SUBSIDIARIES INDEX TO FINANCIAL STATEMENTS AND SCHEDULES DECEMBER 31, 1999 (SUBMITTED IN ANSWER TO ITEMS 14(A)(1) AND (2) OF FORM 10-K, SECURITIES AND EXCHANGE COMMISSION) FINANCIAL STATEMENTS EASTERN ENTERPRISES AND SUBSIDIARIES: Report of independent public accountants on schedules ............... F-2 Consent of independent public accountants ........................... F-2 SCHEDULES (PAGES F-3 THROUGH F-5) II Valuation of Qualifying accounts and reserves Schedules not listed above are omitted as not applicable or not required under the rules of Regulation S-X. F-1 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULES TO EASTERN ENTERPRISES: We have audited, in accordance with generally accepted auditing standards, the consolidated financial statements included in Eastern Enterprises Annual Report to Shareholders incorporated by reference in this Form 10-K, and have issued our report thereon dated January 21, 2000. Our audit was made for the purpose of forming an opinion on those statements taken as a whole. The schedules listed in the index on page F-1 are the responsibility of Eastern's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subject to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. /s/ Arthur Andersen Arthur Andersen LLP Boston, Massachusetts January 21, 2000 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference of our reports, dated January 21, 2000, included in, and incorporated by reference into, Eastern Enterprises Annual Report on this Form 10-K for the year ended December 31, 1999, into Eastern's previously filed Post-Effective Amendment No. 1 to Form S-16 Registration Statement No. 2-71614 on Form S-3, Form S-4 Registration Statements No. 333-69039 and No. 333-95693, and Form S-8 Registration Statements No. 2-77146, No. 33-19990, No. 33-40862, No. 33-56424, No. 33-58873 and No. 333-88967. /s/ Arthur Andersen Arthur Andersen LLP Boston, Massachusetts March 9, 2000 F-2 SCHEDULE II EASTERN ENTERPRISES AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEAR ENDED DECEMBER 31, 1999 (IN THOUSANDS)
ADDITIONS DEDUCTIONS --------------------------- ---------- CHARGES CHARGED FOR WHICH BALANCE TO COSTS CHARGED RESERVES BALANCE DECEMBER 31, AND TO OTHER WERE DECEMBER 31, DESCRIPTION 1998 EXPENSES ACCOUNTS CREATED 1999 - ----------- ---- -------- -------- ------- ---- Reserves deducted from assets -- Reserves for doubtful accounts ................ $ 17,070 $12,005 $ 3,176 $(13,391) $ 18,860 ======== ======= ======= ======== ======== Reserves for loss on inventory ................ $ -- $ 234 $ -- $ -- $ 234 ======== ======= ======= ======== ======== Reserves for loss on investments .............. $ 19 $ -- $ -- $ -- $ 19 ======== ======= ======= ======== ======== Reserves included in liabilities -- Reserve for postretirement health care ........ $ 97,197 $ 5,781 $ 4,857 $ (8,211) $ 99,624 Reserves for employee benefits ................ 29,716 16,722 7,345 (13,290) 40,493 Reserves for environmental expenses ........... 25,115 249 850 (4,340) 21,874 Reserves for insurance claims ................. 12,269 5,497 3,268 (8,863) 12,171 Other ......................................... 11,157 286 -- (1,190) 10,253 ======== ======= ======= ======== ======== Total liability reserves .................... $175,454 $28,535 $16,320 $(35,894) $184,415 ======== ======= ======= ======== ========
F-3 SCHEDULE II EASTERN ENTERPRISES AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEAR ENDED DECEMBER 31, 1998 (IN THOUSANDS)
ADDITIONS DEDUCTIONS --------------------------- ---------- CHARGES CHARGED FOR WHICH BALANCE TO COSTS CHARGED RESERVES BALANCE DECEMBER 31, AND TO OTHER WERE DECEMBER 31, DESCRIPTION 1997 EXPENSES ACCOUNTS CREATED 1998 - ----------- ---- -------- -------- ------- ---- Reserves deducted from assets -- Reserves for doubtful accounts ................ $ 17,220 $ 5,062 $ 120 $ (5,332) $ 17,070 ======== ======= ======= ======== ======== Reserves for loss on investments .............. $ 19 $ -- $ -- $ -- $ 19 ======== ======= ======= ======== ======== Reserves included in liabilities -- Reserve for postretirement health care ........ $ 98,382 $ 5,540 $ -- $ (6,725) $ 97,197 Reserve for coal miner's retiree health care .. 76,500 (74,500) -- (2,000) -- Reserves for employee benefits ................ 25,236 14,092 1,486 (11,098) 29,716 Reserves for environmental expenses ........... 25,920 71 82 (958) 25,115 Reserves for insurance claims ................. 13,171 5,029 1,968 (7,899) 12,269 Other ......................................... 16,319 377 921 (6,460) 11,157 -------- ------- ------- -------- -------- Total liability reserves .................... $255,528 $(49,391) $ 4,457 $(35,140) $175,454 ======== ======= ======= ======== ========
F-4 SCHEDULE II EASTERN ENTERPRISES AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEAR ENDED DECEMBER 31, 1997 (IN THOUSANDS)
ADDITIONS DEDUCTIONS --------------------------- ---------- CHARGES CHARGED FOR WHICH BALANCE TO COSTS CHARGED RESERVES BALANCE DECEMBER 31, AND TO OTHER WERE DECEMBER 31, DESCRIPTION 1996 EXPENSES ACCOUNTS CREATED 1997 - ----------- ---- -------- -------- ------- ---- Reserves deducted from assets -- Reserves for doubtful accounts ................ $ 17,301 $ 5,818 $ 167 $ (6,066) $ 17,220 ======== ======= ======= ======== ======== Reserves for loss on investments .............. $ 19 $ -- $ -- $ -- $ 19 ======== ======= ======= ======== ======== Reserves included in liabilities -- Reserve for postretirement health care ........ $100,446 $ 4,578 $ -- $ (6,642) $ 98,382 Reserve for coal miner's retiree health care .. 77,308 -- -- (808) 76,500 Reserves for employee benefits ................ 24,624 9,690 907 (9,985) 25,236 Reserves for environmental expenses ........... 26,809 -- 122 (1,011) 25,920 Reserves for insurance claims ................. 12,838 7,348 (530) (6,485) 13,171 Other ......................................... 17,680 6,304 41 (7,706) 16,319 -------- ------- ------- -------- -------- Total liability reserves .................... $259,705 $27,920 $ 540 $(32,637) $255,528 ======== ======= ======= ======== ========
F-5 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. EASTERN ENTERPRISES Registrant By /s/ JAMES J. HARPER ------------------------------------ JAMES J. HARPER Vice President and Controller (Chief Accounting Officer) Date: March 10, 2000 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 10th day of March, 2000. SIGNATURE TITLE Chairman and Chief Executive Officer and /s/ J. ATWOOD IVES Trustee - -------------------------------- J. ATWOOD IVES /s/ FRED C. RASKIN President and Chief Operating Officer - -------------------------------- FRED C. RASKIN Executive Vice President and Chief /s/ WALTER J. FLAHERTY Financial Officer - -------------------------------- WALTER J. FLAHERTY /s/ JAMES R. BARKER Trustee - -------------------------------- JAMES R. BARKER /s/ RICHARD R. CLAYTON Trustee - -------------------------------- RICHARD R. CLAYTON /s/ JOHN D. CURTIN, JR. Trustee - -------------------------------- JOHN D. CURTIN, JR. /s/ SAMUEL FRANKENHEIM Trustee - -------------------------------- SAMUEL FRANKENHEIM /s/ LEONARD R. JASKOL Trustee - -------------------------------- LEONARD R. JASKOL /s/ WENDELL J. KNOX Trustee - -------------------------------- WENDELL J. KNOX /s/ F. L. PUTNAM, JR. Trustee - -------------------------------- F. L. PUTNAM, JR. /s/ RINA K. SPENCE Trustee - -------------------------------- RINA K. SPENCE /s/ DAVID B. STONE Trustee - -------------------------------- DAVID B. STONE F-6 EXHIBIT INDEX See Item 14(a)(3), "List of Exhibits," for statement of the location of exhibits incorporated by reference. EXHIBIT 2.1 -- Agreement and Plan of Reorganization, dated as of July 14, 1999 by and between Eastern, EE Acquisition Company, Inc. and EnergyNorth, Inc., including Amendment No. 1 dated November 4, 1999 (incorporated by reference). 2.2 -- Agreement and Plan of Merger, dated as of November 4, 1999, by and among Eastern Enterprises, KeySpan Energy Corporation and ACJ Acquisition LLC (incorporated by reference). 2.3 -- Amendment No. 1 to Agreement and Plan of Merger, dated as of January 26, 2000, by and among Eastern Enterprises, KeySpan Energy Corporation and ACJ Acquisition LLC. 3.1 -- Declaration of Trust of Eastern Enterprises, as amended through April 27, 1989 (incorporated by reference). 3.2 -- By-Laws of Eastern Enterprises, as amended through February 24, 1999 (incorporated by reference). 4.1 -- Common Stock Rights Agreement between Eastern and The Bank of New York, dated as of February 22, 1990, and Exhibits attached thereto (incorporated by reference). 4.1.1 -- Agreement between Eastern and The First National Bank of Boston, dated January 30, 1995 (incorporated by reference). 4.1.2 -- Amendment No. 2 to Common Stock Rights Agreement, dated as of July 22, 1998, between Eastern and BankBoston, N.A. (incorporated by reference). 4.1.3 -- Rights Agreement, dated as of July 22, 1998, between Eastern and BankBoston, N.A. (incorporated by reference). 10.1 -- Agreement, dated as of September 14, 1999, by and between Boston Gas Company, Essex Gas Company, Colonial Gas Company and El Paso Energy Marketing Company (Redacted)+ 10.2 -- Eastern's amended and restated Deferred Compensation Plan for Trustees, dated April 22, 1998 (incorporated by reference). 10.2.1 -- Amendment to Eastern's Amended and Restated Deferred Compensation Plan For Trustees, dated as of October 27, 1999. 10.2.2 -- Amendment to Eastern's Amended and Restated Deferred Compensation Plan For Trustees, dated as of December 20, 1999. 10.3 -- Eastern's 1982 Stock Option Plan, as amended (incorporated by reference). 10.4 -- Eastern's 1995 Stock Option Plan (incorporated by reference). 10.5 -- Eastern's Amended and Restated Supplemental Executive Retirement Plan. 10.6 -- Trust Agreement between Eastern and Shawmut Bank of Boston N.A., as amended (incorporated by reference). 10.6.1 -- Amendment to Trust Agreement between Eastern and Shawmut Bank of Boston, N.A. (incorporated by reference). 10.6.2 -- Amendment to Trust Agreement between Eastern and the Key Trust Company of Ohio, N.A., as successor trustee, dated December 8, 1995 (incorporated by reference). 10.6.3 -- Amendment to Trust Agreement between Eastern and Key Trust Company of Ohio, N.A., as successor trustee, dated February 25, 1998 (incorporated by reference). 10.6.4 -- Amendment, dated as of September 22, 1999, to Trust Agreement between Eastern and Key Trust Company of Ohio, N.A. 10.7 -- Eastern's Executive Incentive Compensation Plan, as amended (incorporated by reference). 10.8.1 -- Change of Control Agreement, dated as of September 22, 1999, by and between Eastern and J. Atwood Ives (incorporated by reference). 10.8.2 -- Change of Control Agreement, dated as of September 22, 1999, by and between Eastern and Fred C. Raskin (incorporated by reference). 10.8.3 -- Change of Control Agreement, dated as of September 22, 1999, by and between Eastern and Walter J. Flaherty (incorporated by reference). 10.8.4 -- Change of Control Agreement, dated as of September 22, 1999, by and between Eastern and L. William Law, Jr. (incorporated by reference). 10.8.5 -- Change of Control Agreement, dated as of September 22, 1999, by and between Eastern, Boston Gas Company and Chester R. Messer (incorporated by reference). 10.8.6 -- Change of Control Agreement, dated as of September 22, 1999, by and between Eastern, Midland Enterprises Inc. and J. Mark Cook (incorporated by reference). 10.9 -- Agreement dated November 27, 1991 between Eastern and J. Atwood Ives (incorporated by reference). 10.10 -- Agreement dated October 25, 1991 between Eastern and Richard R. Clayton (incorporated by reference). 10.11 -- Letter Agreement, dated May 22, 1998, by and between Eastern and Richard R. Clayton (incorporated by reference). 10.12 -- Employment Agreement, dated as of September 1, 1998, by and between Eastern and Fred C. Raskin (incorporated by reference). 10.13 -- Eastern's Retirement Plan for Non-Employee Trustees, as amended (incorporated by reference). 10.13.1 -- Amendment to Eastern's Retirement Plan for Non-Employee Trustees, dated December 8, 1995 (incorporated by reference). 10.14 -- Eastern's 1996 Non-Employee Trustees' Stock Option Plan (incorporated by reference). 10.14.1 -- Amendment to Eastern's 1996 Non-Employee Trustees' Stock Option Plan (incorporated by reference). 10.15 -- Eastern's 1992 Restricted Stock Plan (incorporated by reference). 10.16 -- Eastern's Restricted Stock Plan for Non-Employee Trustees (incorporated by reference). 10.16.1 -- Amendment, dated as of September 22, 1999, to Eastern's Restricted Stock Plan for Non-Employee Trustees (incorporated by reference). 10.17 -- Eastern's 1994 Deferred Compensation Plan (incorporated by reference). 10.17.1 -- Amendment to Eastern's Deferred Compensation Plan, dated December 8, 1995 (incorporated by reference). 10.17.2 -- Amendment to Eastern's Deferred Compensation Plan, dated July 25, 1996 (incorporated by reference). 10.18 -- Eastern Enterprises Executive Stock Purchase Loan Plan, as amended February 27, 1997 (incorporated by reference). 10.19 -- Credit Agreement, dated as of December 31, 1994, by and between Eastern, Boston Gas, Midland, the Banks named therein and The First National Bank of Boston, individually and as Agent (incorporated by reference). 10.19.1 -- Amendment No. 1 to Credit Agreement, dated as of December 31, 1995, by and among Eastern, Boston Gas, Midland, the Banks named therein and The First National Bank of Boston, individually and as Agent (incorporated by reference). 10.19.2 -- Amendment No. 2 to Credit Agreement, dated as of December 31, 1996, by and among Eastern, Boston Gas, Midland, the Banks named therein and The First National Bank of Boston, individually and as Agent (incorporated by reference). 10.19.3 -- Amendment No. 3 to Credit Agreement, dated as of August 20, 1999, by and among, Eastern, Boston Gas Company and Midland Enterprises Inc., the Banks named therein and BankBoston, N.A., individually and as Agent. 13.1 -- Portions incorporated herein of annual report to shareholders for the year ended December 31, 1999. 21.1 -- Subsidiaries of the registrant. 23.1 -- Consent of Arthur Andersen LLP. 27.1 -- Financial Data Schedule for the twelve months ended December 31, 1999. - ---------- + Confidential Treatment Requested. EX-2.3 2 AMEND. NO. 1 TO AGREEMENT & PLAN OF MERGER Exhibit 2.3 AMENDMENT NO. 1 TO AGREEMENT AND PLAN OF MERGER This is AMENDMENT NO. 1 dated as of January 26, 2000 (the "Amendment") to the AGREEMENT AND PLAN OF MERGER (the "Agreement") dated as of November 4, 1999 by and among Eastern Enterprises, a Massachusetts voluntary association (the "Company"), KeySpan Corporation, a New York corporation ("Parent"), and ACJ Acquisition LLC, a Massachusetts limited liability company which is directly and indirectly wholly owned by the Parent ("Merger Sub"). 1. The parties entered into the Agreement to provide for a business combination (the "Merger") pursuant to which the Merger Sub would merge with and into the Company, with the Company as the survivor of the Merger. The purpose of this Amendment is to set forth certain agreements by and among the Company, Parent and Merger Sub to amend the Agreement. Accordingly, the Company, Parent and Merger Sub agree as set forth below in this Agreement. Capitalized terms used in this Amendment that are not defined herein shall have the respective meanings ascribed to them in the Agreement. Capitalized terms used in this Amendment that are not defined in the Agreement shall be deemed included in the Agreement with the respective meanings ascribed to them in this Amendment. 2. Section 4.13 of the Agreement is hereby amended to read in its entirety as follows: Section 4.13 VOTE REQUIRED. The approval of the Merger AND THE AMENDMENT TO THE COMPANY DECLARATION OF TRUST TO PERMIT A MASSACHUSETTS LIMITED LIABILITY COMPANY OR ANY OTHER COMPANY TO MERGE INTO OR CONSOLIDATE WITH THE COMPANY by a majority of the votes entitled to be cast by all holders of Company Common Stock (the "Company Shareholders' Approval") are the only votes of the holders of any class or series of the capital stock of the Company or any of its subsidiaries required to approve this Agreement, the Merger and the other transactions contemplated hereby. IN WITNESS WHEREOF, Eastern Enterprises, KeySpan Corporation and ACJ Acquisition LLC have caused this Amendment to be signed as a sealed instrument by their duly authorized representative officers, all as of the date first written above. EASTERN ENTERPRISES By: /s/ J. Atwood Ives ----------------------------------- Title: Chief Executive Officer KEYSPAN CORPORATION By: /s/ Gerald Luterman ----------------------------------- Title: Senior Vice President ACJ ACQUISITION LLC By: /s/ Steven Zelkowitz ----------------------------------- Title: Manager EX-10.1 3 AGREEMENT DATED 9-14-99 Exhibit 10.1 *** INDICATES MATERIAL THAT HAS BEEN OMITTED AND FOR WHICH CONFIDENTIAL TREATMENT HAS BEEN REQUESTED, ALL SUCH MATERIAL HAS BEEN FILED WITH THE COMISSION PURSUANT TO RULE 24b OF THE SECURITIES EXCHANGE ACT OF 1934. AGREEMENT THIS AGREEMENT made and entered into this 14th day of Sep., 1999, by and between BOSTON GAS COMPANY, a Massachusetts corporation, ESSEX GAS COMPANY, a Massachusetts corporation and COLONIAL GAS COMPANY a Massachusetts corporation hereinafter jointly referred to as "Buyer", and El Paso Energy Marketing Company, a Delaware corporation, hereinafter referred to as "Seller" WITNESSETH THAT: WHEREAS, Buyer desires to retain a manager for certain of its natural Gas resource portfolio under the terms and conditions of this Agreement; and WHEREAS, Buyer desires to purchase natural Gas from Seller under the terms and conditions of this Agreement; and WHEREAS, Seller desires to provide portfolio management services under the terms and conditions of this Agreement; and WHEREAS, Seller desires to sell natural Gas to Buyer under the terms and conditions of this Agreement. NOW, THEREFORE, in consideration of the mutual covenants and benefits to be derived hereunder, Buyer and Seller agree as follows; ARTICLE I DEFINITIONS Unless expressly stated otherwise, the following terms as used in this Agreement shall mean: 1.1 The term "Algonquin" shall mean the Algonquin Gas Transmission Company. 1.2 The term "Btu" shall mean British Thermal Unit(s) which shall mean that amount of heat energy required to raise the temperature of one avoirdupois pound of water from fifty-nine-degrees Fahrenheit to sixty-degrees Fahrenheit at standard atmospheric pressure, as determined on a dry basis. All prices and charges paid hereunder shall be computed on a "dry" Btu basis. 1.3 The term "Buyer's Unbundling Program" shall mean the methodology by which Buyer, each Month, implements the mandatory assignment of a pro-rata share Of its pipeline and underground storage resources and certain Gas supplies to third party suppliers on behalf of existing transportation customers and customers converting from sales to transportation service. 1.4 The term "Canadian Index" shall mean a transfer price from Buyer to Seller of $0.00 per MMBtu with title transfer of the Gas occurring at the respective receipt points into Tennessee Gas Pipeline and Iroquois Gas Transmission for those volumes reflected in Appendix 1 and identified as Canadian Supply under the heading Gas Commodity Contract Volumes. Both Buyer and Seller understand that these volumes are subject to change each Month during the Term of this Agreement as a direct result of Buyer's Unbundling Program. 1.5 The term "Day" shall mean the period of time beginning at 9:00 a.m., Central Clock Time, on a calendar day and ending at 9.00 a.m., Central Clock Time, on the following calendar day. 1.6 The term "Delivery Points" shall mean those city gate meter stations connected to the Tennessee Gas Pipeline and Algonquin Gas Transmission system as listed in Appendix 1. 1.7 The term "DTE". shall mean the Massachusetts Department of Telecommunications and Energy. 1.8 The term "Ending Underground Storage Balance" means the quantity of Gas that is physically in Buyer's total underground storage accounts as of October 31, 2002. 1.9 The term "Enron Index" shall mean those volumes identified in Appendix 1 as Enron Supply. Both Buyer and Seller understand' that these volumes are subject to change each Month during the Term of this Agreement as a direct result of Buyer's Unbundling Program. From time to time, Seller shall be required to take title. to the Enron Supply at a $0.00 per MMBtu transfer price at the interconnection between Tennessee and Algonquin at Mendon, MA and redeliver like volumes, less applicable transport fuel, to Boston Gas' Delivery Point(s) off of Algonquin. Upon start up of the Sable Offshore Energy Project, ("SOEP") all or a portion of the volumes identified as Enron Supply may be replaced, at Buyer's option, with supplies delivered from Imperial Oil via Maritimes and Northeast Pipeline and Tennessee to the Delivery Points. All Imperial Oil volumes, not to exceed 43,200 MMBtu/Day, will be nominated, scheduled and paid for by Buyer. Subsequent to the start up of SOEP, the parties understand and agree that this index may include both the Enron Supply and Imperial Oil volumes of up to 43,200 MMBtu/Day for a period of up to ninety Days at Buyers discretion. 1.10 The term "FERC" shall mean the Federal Energy Regulatory Commission. 1.11 The term "Force Majeure" shall mean an event as defined in section 11.3 of this Agreement. 1.12 The term "Gas" shall mean quality Gas as defined in the FERC Gas Tariffs of Texas Eastern Transmission, Texas Gas Transmission, Tennessee Gas Pipeline, Transcontinental Pipeline, CNG Transmission, National Fuel Gas Supply, Iroquois Gas Transmission, Honeoye Storage Company, Algonquin Gas Transmission and Maritimes and Northeast Pipeline L,L.C. 1.13 The term "Gas Commodity Contract Volumes" means Buyer's Gas supply contract volumes as identified on Appendix 1. 1.14 The term "Initial Underground Storage Balance" shall mean that quantity of Gas that is physically in Buyer's total underground storage accounts as of November 1, 1999. 1.15 The term "MMBtu" shall mean one million (1,000,000) Btus. 1.16 The term "Month" shall mean the period of time beginning on the first Day of each calendar month and ending on the first Day of the following calendar month. 1.17 The term "NYMEX" shall mean the New York Mercantile Exchange for Natural Gas Futures Contracts. 1.18 The term "Off-Peak Period" shall mean the period of time beginning on the first Day of May and ending on the last Day of October. 1.19 The term "Off-Peak Period Baseload Index" shall mean the weighted average Gas price as reflected in Inside FERC First of the Month's Pricing Report for Tennessee zone 0 and zone 1 and for the Tetco STX, WLA ELA, and ETX supply areas, associated with Buyer's long haul transportation contracts listed in Appendix 1 and not allocated to the Canadian Index, Enron Index or Sonat Index. 1.20 The term "Off-Peak Period Swing Index" shall mean the weighted average Gas price as reflected in Pasha's Gas Daily Pricing Report for Tennessee zone 0 and zone 1 and for the Tetco STX, WLA, ELA, and ETX supply areas associated with Buyer's long haul transportation contracts listed in Appendix 1 and not allocated to the Canadian Index, Enron Index or Sonat Index. 1.21 The term "Peak Period" shall mean the period of time beginning on the first Day of November and ending on the last Day of April. 1.22 The term "Peak Period Baseload Index " shall mean the weighted average Gas price as reflected in Inside FERC First of the Month's Pricing Report for Gas Delivered to Pipelines for the applicable Month for the applicable supply area capacity associated with the transportation contracts listed in Appendix I not allocated to the Canadian Index, Enron Index or Sonat Index. 1.23 The term "Peak Period Swing Index" shall mean the weighted average Gas price as reflected in Pasha's Gas Daily Pricing Report for the applicable supply capacity associated with the transportation contracts listed in Appendix 1 not allocated to the Canadian Index, Enron Index, or Sonat Index. 1.24 The term "Sonat Index" shall mean those volumes identified in Appendix 1 as Sonat Supply and shall have a $0.00 per MMBtu transfer price plus applicable Variable Charges to the Delivery Points with title transfer occurring at the Sonat and Buyer's supply aggregation agreement on Tennessee's zone 0, 100 leg and zone 1, 500 leg, The Sonat Index will be eliminated for purposes of the pricing hierarchy set forth in Article III below effective April 1, 2000. 1.25 The term "Storage WACOG" shall mean the Buyer's weighted average cost of all underground storage Gas. 1.26 The term "Tennessee" shall mean the Tennessee Gas Pipeline Company. 1.27 The term "Term" shall mean the period commencing on November 1, 1999 and ending on October 31, 2002. 1.28 The term "Transporters" shall mean any of the following, Texas Eastern Transmission, Texas Gas Transmission, Tennessee Gas Pipeline, Transcontinental Gas Pipeline, CNG Transmission, National Fuel Gas Supply, Iroquois Gas Transmission, Honeoye Storage Company, Algonquin Gas Transmission Company and Maritimes and Northeast Pipeline L.L.C. 1.29 The term "Variable Charges" shall mean all applicable Transporter transportation commodity and fuel charges and all Transporter storage injection, withdrawal and fuel charges and any other surcharges associated with delivery of Buyer's Gas to the Delivery Points, based upon the pricing hierarchy as reflected in Section 3.1. ARTICLE-II QUANTITY AND NOMINATIONS 2.1 Nominated Quantity . Subject to the terms and conditions of this Agreement, Buyer will nominate, purchase and receive and Seller will sell and deliver on a firm basis on each Day of the Term hereof, a quantity of Gas up to the MDQ as defined in section 2.2 below. 2.2 Maximum Daily Quantity ("MDQ"). Notwithstanding anything to the contrary herein, the MDQ of Gas that Buyer is entitled to purchase and receive and that Seller is obligated to sell and deliver on each Day of the Term hereof, shall be as follows: for the period November 16 through April 15 the MDQ is 536,011 MMBtu, for the period April 16, through May 31, the MDQ is 517,038 MMBtu, for the period June 1 through September 30, the MDQ is 466,438 MMBtu, for the period October 1 through November 14 the MDQ is 517,038, and for the Day of November 15, the MDQ is 507,689. Both Buyer and Seller understand that the MDQ shall be adjusted Monthly and or Daily to reflect certain instances including, but not limited to, application of underground storage withdrawal ratchets, Buyer's Unbundling Program and Transporters' restrictions affecting secondary firm capacity. 2.2.1 Quantities in Excess of the MDQ. From time to time during the term of this Agreement, Seller may sell and Buyer may purchase quantities in excess of the MDQ. The price and terms of such excess sales will be mutually agreed upon by Seller and Buyer prior to delivery. Provided however, that nothing contained in this section 2.2.1 shall prevent Buyer from purchasing quantities of Gas in excess of the MDQ from a third party(s) other than Seller. 2.3 Nomination and Delivery Requirements. 2.3.1 Monthly Nomination. On or before 12:00 Noon Central Time and three business Days prior to the first Day of the following Month, Buyer will provide Seller with a nomination specifying the total daily quantity of Gas to be purchased and received under this Agreement for each Day during the following Month, ("Daily Nominated Quantity"). Such nomination by Buyer shall include the volumes indicated as Peak Period Index Baseload or Off-Peak Period Baseload Index volumes pursuant to section 3.1.1 below. 2.3.2 Daily Adjustments. On or before the applicable Transporters nominations deadlines for the next Day, Buyer may adjust its Daily Nominated Quantity prospectively for any Day during the remainder of that Month. 2.3.3 Intra-Day Adjustments. On or before the applicable intra-Day Transporters nomination deadline, Buyer may adjust its Daily Nominated Quantity for the remainder of that Day. In the event that Buyer requests an intra-Day adjustment, the Parties shall work together to utilize the intra-Day flexibility associated with the contracts listed in Appendix I in making such adjustments. 2.3.4 Manner of Submitting Nominations. Buyer may provide the nominations set forth above in this section either orally or by fax, but any oral nomination must be followed by written confirmation within twenty-four (24) hours. By 3:30 P.M. Eastern time each Day, Seller shall provide volume allocations by contract and delivery point consistent with Buyer's nominations for the following Day. 2.3.5 Points of Delivery. Seller will deliver volumes of Gas nominated by Buyer to points designated by Buyer as provided by the applicable contracts or such other points as the parties may mutually agree. 2.4 Remedies for Failure to Deliver. 2.4.1 Seller's Failure to Deliver. Except for an event of Force Majeure, if Seller fails to deliver to Buyer the Daily Nominated Quantity, and such failure to deliver is not excused under this Agreement, then Seller shall reimburse Buyer an amount, if positive, between the price Buyer pays for a delivered substitute supply of Gas and the Commodity Price, multiplied by the quantity of Gas Seller fails to deliver in accordance with this section, plus $ *** per MMBtu, multiplied by the quantity of Gas Seller fails to deliver. Buyer agrees to act in good faith in purchasing such substitute supplies of Gas so as to minimize Seller's reimbursement costs hereunder. In the event Seller fails to deliver for any continuous period in excess of one (1) Day, Buyer may terminate this Agreement in accordance with the provisions of section 5.2 below. 2.4.2 Liquidating Damages. Should Seller's failure to deliver occur on a Day Buyer is unable, utilizing reasonable efforts, to obtain a delivered substitute supply, then in addition to any amounts owed by Seller to Buyer pursuant to Section 2.4.1, Seller shall pay to Buyer $ *** per MMBtu multiplied by the quantity Seller fails to deliver. Such amount represents Buyer's damages difficult to quantify and constitute liquidated damages and not a penalty. 2.4.3 Sole and Exclusive Remedy. The remedies set forth in Sections 2.4.1 and 2.4.2 shall be Buyer's sole and exclusive remedy for Seller's failure to deliver Gas hereunder. 2.4.4 Corporate Guaranty. Seller shall cause its parent corporation, which shall have total stockholders' equity of at least $200,000,000, to execute and maintain in effect throughout the term of this Agreement a valid and binding guaranty of Seller's obligations under this Agreement to Buyer substantially in the form attached hereto as Appendix 2, or provide such other form of guaranty as may be acceptable to Buyer in its sole discretion. ARTICLE III PRICE 3.1 Commodity Price. 3.1.1 Quantities Within MDQ. The price for Gas delivered hereunder up to the MDQ will be referred to as the "Commodity Price" and shall be equal to the following pricing hierarchy: CANADIAN INDEX: 0 up to the sum total of Buyer's entitlements on the Canadian contracts identified in Appendix 1 stated in MMBtu's per Day shall be equal to the Canadian Index plus applicable Variable Charges. ENRON INDEX: The next quantities., as specified below, shall be equal to the Enron Index plus applicable Variable Charges, Provided however, the maximum volumes to be priced at the Enron Index shall be adjusted each Month in accordance with the Buyer's Unbundling Program. (a) prior to the start up of the Sable Offshore Energy Project, 35,000 MMBtu/Day; (b) for the first 90 Days after the start up of the Sable Offshore Energy Project, quantities selected by Buyer at its discretion but not less than 35,000 MMBtu/Day (except that Buyer may select a volume less than 35,000 MMBtu/Day consistent with adjustments made to the Enron Supply as a result of Buyer's Unbundling Program) nor more than 78,200 MMBtu/Day; (c) More than 90 Days after the start up of the Sable Offshore Energy Project, 43,200 MMBtu/Day. SONAT INDEX: The next 17,300 MMBtu's per Day shall be equal to the Sonat Index plus applicable Variable Charges. The Sonat Index will terminate effective April 1, 2000. PEAK PERIOD BASELOAD INDEX: In the Peak Period the next volumes, up to the amount indicated by Buyer in accordance with this section, but not to exceed Buyer's MDQ less the Storage WACOG tier, less the Canadian Index tier, less the Enron Index tier and less the Sonat Index tier, shall be equal to the Peak Period Baseload Index plus applicable Variable Charges. On or before the 25th Day of each Month, Buyer will indicate the volumes that will be subject to the Peak Period Baseload Index for the following Month. If Buyer fails to take delivery of volumes it indicates as Peak Period Baseload index volumes, and such failure to take is not excused under the Agreement, then, Buyer shall reimburse Seller the amount, if any, by which the price Seller is able to obtain by reselling volumes not taken is exceeded by the Peak Period Baseload Index. Seller shall act in good faith to resell such volumes in a commercially reasonable manner so as to minimize Buyer's reimbursement costs hereunder. PEAK PERIOD SWING INDEX: In the Peak Period the next volumes, up to Buyer's MDQ less the Storage WACOG tier, less the Canadian Index tier, less the Enron Index tier, less the Sonat Index tier and the less the Peak Period Baseload Index tier shall be equal to the Peak Period Swing Index plus applicable Variable Charges. OFF-PEAK PERIOD BASELOAD INDEX: In the Off-Peak Period the next volumes, up to the amount indicated by Buyer pursuant to this section, but not to exceed Buyer's MDQ less the Storage WACOG tier, less the Canadian Index tier, less the Enron Index tier and less the Sonat Index tier, shall be equal to the Off-Peak Period Baseload Index plus applicable Variable Charges. On or before the 25 th Day of each Month, Buyer will indicate the volumes that will be subject to the Off-Peak Period Baseload Index for the following Month. If Buyer fails to take delivery of volumes it indicates as Off-Peak Period Baseload Index volumes, and such failure to take is not excused under the Agreement, then, Buyer shall reimburse Seller the amount, if any, by which the price Seller is able to obtain by reselling volumes not taken is exceeded by the Off-Peak Period Baseload Index. Seller shall act in good faith to resell such volumes in a commercially reasonable manner so as to minimize Buyer's reimbursement costs hereunder. OFF-PEAK PERIOD SWING INDEX: In the Off-Peak Period the next volumes up to Buyer's MDQ less the Storage WACOG tier, less the Canadian Index tier, less the Enron Index tier, less the Sonat Index tier and less the Off-Peak Period Baseload Index tier shall be equal to the Off-Peak Period Swing Index plus applicable Variable Charges. STORAGE WACOG: All remaining volumes, up to Buyer's MDQ, shall be equal to the Storage WACOG plus applicable Variable Charges. 3.1.2 Buyer's Right to Fixed Pricing. Buyer shall retain the right to convert any Baseload Volume Index price to a fixed price for any portion of the MDQ for any Month(s) during the Term of this Agreement, provided any converted volumes are specifically within the following Commodity Price tiers: Sonat Index, Peak Period Baseload Index, Peak Period Swing Index, Off-Peak Period Baseload Index or Off-Peak Period Swing index. Such fixed pricing shall be defined as the applicable NYMEX based price plus a mutually agreed upon basis differential, Buyer must notify Seller of any change to fixed pricing for any Month on or before three (3) full business Days prior the last Day of trading for the applicable NYMEX future contract Month(s). In addition, if Buyer elects to convert to a fixed price for any of its MDQ, then Buyer will be required to purchase on each Day during the applicable converted period 100 percent of the volume that Buyer elected to convert to a fixed price. 3.2 Guaranteed Payment. Buyer agrees to invoice Seller on or before the 15th Day of each Month during the Term and Seller agrees to pay Buyer an amount of $ *** , payable in thirty six (36) equal installments of $ *** on or before the 25th Day of each Month during the Term of this Agreement to compensate Buyer for the use of Buyer's portfolio. Such payments shall be made by wire transfer at such location as Buyer may from time to time designate in writing. 3.3 Transportation and Underground Storage Cost Reimbursement. Buyer shall reimburse Seller for 100 percent of the transportation and underground storage reservation charges associated with capacities assigned from Buyer to Seller pursuant to Article IV during the Term of this Agreement. In addition, Buyer shall reimburse Seller for 100 percent of the applicable transportation and underground storage Variable Charges associated With the delivery of Gas by Seller to Buyer's Delivery Points up to the MDQ and based upon the pricing hierarchy as reflected in section 3.11. All Transporter refunds and credits applicable to the Term of this Agreement associated with capacities assigned from Buyer to Seller during the Term of this Agreement shall belong to Buyer. 3.4 Underground Storage Refill. *** 3.5 Suspension of Indices, If, during the Term of this Agreement, a specified index as defined in sections 1.19, 1.20, 1.22 and 1.23 ceases to be published or is not published for a given Month, or, if a more appropriate index becomes available then Buyer and Seller shall mutually agree upon a replacement index. ARTICLE IV TRANSPORTATION AND UNDERGROUND STORAGE ASSIGNMENTS 4.1 Assignment of Transportation and Under-ground Storage Contracts to Seller. Each Month, Buyer shall assign or otherwise provide agency rights to the specified transportation and underground storage contracts and related quantities as listed in Appendix 1, as attached hereto. Such quantities are subject to recall and will be adjusted each Month in accordance with Buyer's Unbundling Program requirements. Subject to Article 11 of this Agreement and the limitations set forth in section 4.2.4 below, Seller shall have full and complete control over the utilization of the contracts and related quantities listed in Appendix 1, including without limitation the manner and timing of any transportation, injections, and withdrawals of Gas under such contracts, provided that Seller shall maintain maximum withdrawal rights on each of the Tennessee FS-MA contract numbers 527, 524 and 2272 at all times throughout the term of this Agreement and further that Seller shall not release any Tennessee capacity on contracts 2062, 2025, and 435 upstream of Zone 4 at any time during the Months of December, January and February Any incremental charges incurred by either Buyer or Seller as a result of such utilization by Seller shall be the sole responsibility of Seller, and Seller shall either pay or credit Buyer for any such charges incurred by Buyer. All assignments or agency rights from Buyer to Seller shall be in accordance with all the applicable Transporters' tariff provisions and shall terminate upon the expiration of this Agreement. 4.1.1 Transfer of Gas in Underground Storage. The Initial Underground Storage Balance shall be under the control and discretion of Seller effective with the Term of this Agreement and title to such Initial Underground Storage Balance shall transfer to Seller as of the effective date of this Agreement at no cost to Seller. No resale agreement or other indicia of the transfer other than this Agreement shall be necessary to evidence such transfer of title. Buyer warrants title to the Initial Underground Storage Balance and that such Gas is free from liens and adverse claims of every kind. Buyer will indemnify and save Seller harmless against all loss, damage and expense of every character on account of adverse claims to the Initial Underground Storage Balance prior to transfer of title to Seller. Seller shall ensure that all tariff provisions and other compliance requirements of underground storage vendors applicable to Gas in underground storage are met and penalties are avoided. Any penalties incurred by Buyer or Seller as a result of Seller's utilization of Gas in underground storage shall be the sole responsibility of Seller. Prior to April 1st of each year, Seller and Buyer will agree on underground storage refill volumes to be' injected into underground storage over the following seven Month period, such volumes to be priced in accordance with section 3.4 above. Unless otherwise agreed to in writing prior to March 15, 2002, at the end of this Agreement, Seller shall cause Buyers underground storage to be 95 percent full and return control, discretion and title of such Gas in underground storage to Buyer. Buyer and Seller agree to work together in complying with all contract termination provisions, including but not limited to the two (2) underground storage contracts that Buyer is holder of on National Fuel Gas Supply. 4.1.2 Gas Commodity Contract Volumes. For those Gas Commodity Contract Volumes identified in Appendix 1, Buyer will transfer and Seller will accept title to such volumes at the delivery point(s) applicable to each such Gas Commodity Contract Volumes. All volumes delivered will be adjusted Monthly in accordance with Buyer's Unbundling Program requirements. 4.2 Responsibility for Transportation and Underground Storage Contracts. 4.2.1 Responsibility for Administration. Subject to the limitations in section 4.2.4 below, Seller shall assume all obligations and rights under the transportation and underground storage contracts listed in Appendix 1, including without limitation, the obligation to submit nominations to all applicable Transporters and to pay all Transporter invoices. 4.2.2 Operational Balancing Agreements. Buyer shall retain all responsibilities for confirming all of Sellers daily deliveries to Buyer's city gates covered under Buyers Operational Balancing Agreements (OBA) for both Tennessee and Algonquin. As such, any imbalances caused by Seller over or under delivering Buyer's Daily Nominated Quantities shall be the physical and financial responsibility of Seller. Any imbalances caused by Buyer physically taking greater or less than Buyers Daily Nominated Quantities shall be the physical and financial responsibility of Buyer. 4.2.3 Projected Requirements. Buyer shall periodically provide Seller information concerning Buyer's expected Gas requirements on its distribution system. Buyer will also provide Seller information concerning any known or expected events that will cause material changes in Buyers daily Gas requirements as soon as the information becomes known to Buyer. Buyer and Seller agree to work together on a daily basis to ensure that nominations (including any necessary adjustments thereto) are made timely on all applicable Transporters and such nominations reflect, as much as reasonably possible, Buyer's expected requirements. 4.2.4 Modification of Contracts. Seller will fully comply with all terms and conditions of the contracts listed in Appendix 1. Seller shall not amend, extend or cause the early termination of any transportation, underground storage or Gas Commodity Contract of Buyer which is subject to this Agreement without the prior consent of Buyer. In the event such consent is provided orally it shall be followed up in writing by Buyer within 24 hours. ARTICLE V TERM OF AGREEMENT 5.1 Primary Term. This Agreement shall become effective on November 1, 1999 and shall remain in full force and effect through October 31, 2002, 5.2 Early Termination. If either Party commits and has been notified in writing of a material breach of any provision of this Agreement not excused by a Force Majeure event, and fails to cure such breach within twenty four hours of such written notice, this Agreement may be immediately terminated by the non-breaching party. 5.3 Winding Up. At the end of the primary term or any other termination of this Agreement, Seller shall immediately assign back to Buyer all of Buyer's right, title and interest in the contracts listed on Appendix I free and clear of all claims, liens, encumbrances, restrictions and defects in title of any nature incurred as a result of Seller's acts or omissions. ARTICLE VI TITLE AND TAXES 6.1 Transfer of Title, Possession and Control. Title to the Gas sold hereunder shall pass from Seller to Buyer upon delivery of said Gas to the Delivery Points as reflected in Appendix 1. As between the Parties hereto, Seller shall be deemed to be in control and possession of all Gas delivered hereunder and shall indemnify and hold Buyer harmless from any damage, injury or losses which occur prior to the delivery to Buyer at the Delivery Points; otherwise, Buyer shall be deemed to be in exclusive control and possession thereafter and shall indemnify and hold Seller harmless from any other injury, damage or losses. 6.2 Warranty of Title. Except as set forth below, Seller warrants title to all Gas delivered hereunder by Seller, including the Ending Underground Storage Balance or that Seller has the right to sell the same, and that such Gas is free from liens and adverse claims of every kind. Seller will indemnify and save Buyer harmless against all loss, damage and expense of every character on account of adverse claims to the Gas delivered by it before delivery to Buyer. 6.3 Taxes. Other than ad valorem taxes on underground storage Gas which are subject to section 6.4 below, Buyer shall reimburse Seller for any taxes, fees or charges other than an income tax, which are levied by a governmental or regulatory body on the Gas sold under this Agreement. 6.4 Ad Valorem Taxes. If any underground storage Gas is subject to ad valorem property taxes during the term of this Agreement, Buyer shall be responsible for payment of such taxes regardless of whether title to such underground storage Gas is held by Buyer or Seller except if Seller injects Gas into underground storage for its own account or withdraws Gas from underground storage for purposes other than meeting the city gate requirements of Buyer, then Seller shall be responsible for payment of all applicable ad valorem taxes on the amounts so injected or withdrawn. ARTICLE VII QUALITY AND PRESSURE 7.1 Pressure Requirements. All Gas delivered at the Delivery Points shall be at the pressure existing in Tennessee and Algonquin's facilities. Neither Seller nor Buyer shall be obligated to install or operate compression facilities. ARTICLE VIII MEASUREMENT AND TESTS 8.1 Measurement Point. All Gas sold hereunder shall be measured at the Delivery Points on Tennessee and Algonquin systems at pressures in existence at the time of delivery and shall be measured to the unit of one MMBtu. 8.2 Standards for Measurement and Tests. Unless specified herein to the contrary, the standards for measurement and tests shall be governed by those standards set forth in the currently effective Tennessee and Algonquin tariffs. ARTICLE IX BILLING AND PAYMENT 9.1 Billing and Payment. Seller shall render to Buyer, at the address indicated in Section 12.2 hereof, on or before the third business Day of each Month an estimate of all Gas volumes purchased during the preceding Month and on or before the fifteenth (15th) Day of each calendar Month an invoice for all Gas purchased during the preceding Month, according to the measurements, computations, and prices provided herein. Invoices may be based initially upon estimates, but will be corrected to actual as soon as possible. Buyer agrees to make payment hereunder to Seller for its account in available funds by wire transfer or by mail at such location as Seller may from time to time designate in writing. Payment shall be made by Buyer within ten (10) Days of the date of receipt of Sellers invoice. Notwithstanding the above, if a good faith dispute arises between the Parties over the amounts due under the invoice for any matters, other then any reimbursement for the demand or reservation charges under the firm transportation and underground storage contracts, then Buyer will pay that portion of the invoice(s) not in. dispute on or before the due date and both Parties will continue to perform their obligations under this Agreement during such dispute. 9.2 Review of Books and Records. For a period of two years after the date of final billing for the last Month in the Term of this Agreement, Buyer and Seller shall have the right to inspect and examine, at reasonable hours, the books, records and charts of the other pertaining to any term or condition of this Agreement to the extent necessary to verify the accuracy of any invoice, charge or computation made pursuant to this Agreement. ARTICLE X REGULATORY BODIES 10.1 Laws and Regulations. This Agreement shall be subject to review and approval by the DTE. In the event such approval is not obtained on or before October 15 1999 in a form acceptable to Buyer, then this Agreement shall be null and void and the services contemplated hereunder shall not commence. This Agreement shall also be subject to all valid applicable governmental laws and orders, including but not limited to the FERC and DTE, regulatory authorizations directives, rules and regulations of any governmental body or official having jurisdiction over the Parties, their facilities, the Gas or this Agreement or any provision thereof, but nothing contained herein shall be construed as a waiver of any right to question or contest any such law, order, rule or regulation in any forum having jurisdiction. 10.2 Applicable Law. This Contract shall be construed in accordance with the laws of the Commonwealth of Massachusetts, excluding any conflict of laws and principles of said jurisdiction that might require the application of the laws of another jurisdiction. 10.3 Changes in Law or Regulation. If any federal or state statute or regulation or order by a court of law or regulatory authority directly or indirectly (i) prohibits performance under this Agreement, (ii) makes such performance illegal or impossible, or (iii) effects a change in a substantive provision of this Agreement which has a significant material adverse impact upon the ability of either Party to perform its obligations under this Agreement, then the Parties will use all reasonable efforts to revise the Agreement so that: (a) performance under the Agreement is no longer prohibited, illegal, impossible or is no longer impacted in a material adverse fashion, and (b) the Agreement is revised in a manner that preserves, to the maximum extent possible, the respective positions of the Parties. Each Party will provide reasonable and prompt notice to the other Party as to any proposed law, regulations or any regulatory proceedings or actions that could affect the rights and obligations of the Parties. If the Parties are unable to revise the Agreement in accordance with the above, then the Party whose performance is rendered prohibited, illegal, impossible or is impacted in a material adverse manner shall have the right, at its sole discretion, to suspend this Agreement upon written notice to the other Party. Either Party may then terminate this Agreement upon 30 Days written notice to the other Party. ARTICLE XI FORCE MAJEURE 11.1 Suspension of Receipt and Delivery obligations. If Buyer or Seller is rendered unable, wholly or in part, by Force Majeure to perform obligations under this Agreement, other than the obligation to make payments due under this Agreement, it is agreed that the performance of the respective obligations of Seller and Buyer to deliver or purchase and receive Gas, so far as they are affected by Force Majeure, shall be excused and suspended from the inception of any such inability until it is corrected, but for no longer period. Buyer or Seller, whichever is claiming such inability, shall give notice thereof to the other as soon as practicable after the occurrence of the Force Majeure, Such notice may be given orally or in writing but, if given orally, it shall be promptly confirmed in writing, giving reasonably full particulars. Such inability shall be promptly corrected to the extent it may be corrected through the exercise of reasonable diligence by the Party claiming inability by reason of Force Majeure. 11.2 Liability During Force Majeure. Neither Buyer nor Seller shall be liable to the other for any losses or damages, regardless of the nature thereof and however occurring, whether such losses or damages be direct or indirect, immediate or remote, by reason of, caused by, arising out of or in any way attributable to suspension of the performance of any obligation of either Party to the extent that such suspension occurs because a Party is rendered unable, wholly or in part, by Force Majeure to perform its obligations. 11.3 Force Majeure. The term Force Majeure means an event: (i) that was not within the control of the Party claiming its occurrence; (ii) that could not have been prevented or avoided by such Party through the exercise of due diligence; and (iii) that prohibits or prevents such Party from performing its obligations under this Agreement. Events that may give rise to a claim of Force Majeure include: 11.3.1 Acts of God. The term acts of God, including earthquakes, epidemics, fires, floods, landslides, lightning, storms, washouts, weather related events such as hurricanes or freezing or failure of wells or lines of pipe used to supply the Gas described in this Agreement which prevents delivery to the delivery points, and other similar, unusual and severe natural calamities. 11.3.2 Acts of the public enemy, wars, blockage, insurrections, riots. civil disturbances and arrests. 11.3.3 Strikes, lockouts or other industrial disturbances. 11.3.4 Explosions, breakage, accidents to equipment, facilities or lines of pipe used to supply the Gas under this Agreement or explosions, breakage, accidents to equipment, facilities or lines of pipe used to enable Buyer to receive Gas under this Agreement, including without limitation to equipment, facilities or lines of pipe related to Buyers liquefied natural gas facilities. 11.3.5 The temporary inability of Transporters to receive, transport or deliver the Gas described in this Agreement; or 11.3.6 Any other cause of a similar type, provided that such cause satisfies each of the three conditions referenced in Section 11.3 hereof (i.e. "(i)-(iii)" 11.4 Termination. If a Force Majeure event continues for a period of two (2) Days, and the parties, working together in good faith, have been unable to resolve such Force Majuere event, then the Party which did not claim such Force Majeure may at any time thereafter terminate this Agreement upon forty eight (48) hours prior written notice to the extent the Force Majeure event has not been corrected prior to the expiration of such notice period. ARTICLE XII MISCELLANEOUS 12.1 Confidentiality. Except as otherwise provided herein, Seller and Buyer agree to maintain the confidentiality of the price provisions of this Agreement and Seller and Buyer agree not to divulge same to any third Party except to the extent, and only to the extent, required by law, court order or the order or regulation of an administrative agency having jurisdiction over Buyer and Seller, or the subject matter of this Agreement. If required to be disclosed, then the Party subject to the disclosure requirement shall (a) notify the other Party immediately, and (b) cooperate to the fullest extent in seeking whatever confidential status may be available to protect any material so disclosed. 12.2 Notices. Except as otherwise expressly provided in this Agreement, every notice, request, statements and invoices provided in this Agreement shall be in writing and directed to the Party to whom given, made or delivered at such Party's address as follows: Buyer: Boston Gas Company One Beacon Street Boston, MA 02108 Attention: Elizabeth C. Danehy Director of Gas Acquisition & Transportation Services Telephone: 617-723-5512 ext. 2225 Fax: 617-367-6463 For Payments: Boston Gas Company Fleet Bank of Massachusetts Account # 02-0000-4039-00101 ABA # 011-500-101 Seller: El Paso Energy Marketing Company 1001 Louisiana Street Houston, TX 77002 Attention: Russell A. Mahan For Payments: El Paso Energy Marketing Company Mellon Bank Account # 043000261 ABA # 0209517 Either Buyer or Seller may change one or more of its addresses for receiving invoices, statements, notices and payments by notifying the other in writing. 12.3 Headings. The Table of Contents and the headings of any article, section or subsection of this Agreement are for purposes of convenience only and shall not be interpreted as having meaning or effect. 12.4 Waiver of Default. No waiver by either Party of one or more defaults or breaches by the other in performance of any of the terms or provisions of this Agreement shall operate or be construed as a waiver of any future default or breach, whether of a like or of a different character. 12.5 Entire Agreement. The terms and conditions contained herein constitute the full and complete agreement between the Parties and any change to be made must be submitted in writing and agreed to by both Parties, 12.6 Enforceability. This Agreement shall inure to the benefit of and be binding upon the parties and their respective heirs, successors and assigns. Each Party represents that it has all necessary power and authority to enter into and perform its obligations under this Agreement and that this Agreement constitutes a legal, valid and binding obligation of that Party enforceable against it in accordance with its terms, except as such enforceability may be affected by any bankruptcy law or the application of principles of equity. 12.7 Assignment and Organizational Changes. Seller shall not assign its rights or obligations under this Agreement without the express written consent of Buyer. In the event of a Change of Control of Seller occurring during the term of this Agreement, Buyer shall have the right to terminate this Agreement upon thirty (30) Days written notice to Seller. For purposes of this section, 12.7 "Change of Control" means the occurrence of any one or more of the following events: (a) the shareholders of Seller approve a merger or consolidation of Seller with any other entity, (b) the shareholders of Seller approve a plan of liquidation of Seller or an agreement for the sale or disposition by Seller of all or substantially all of its assets, or (c) if a majority of the key individuals at Seller, who at the beginning of this Agreement are providing the services for Buyer under this Agreement are no longer employed by Seller. 12.8 Y2K Compliance. Seller expressly warrants and represents that all computer hardware or software used in Seller's performance of this Agreement are and will continue to be year 2000 compliant. For purposes of this section 12.8, the term "year 2000 compliant" means that date data outside of the range of 1900-1999 will be correctly processed in any level of computer hardware or software including but not limited to, microcode, firmware, application programs, files and data bases. In no event shall any Y2K related failure of any computer hardware or software relied upon by Seller in the performance of this Agreement be deemed a Force Majeure event. 12.9 GISB Compliance. Seller warrants and represents that all computer hardware or software used in Seller's performance of this Agreement is and will continue to be compatible with the latest software release of the Gas Industry Standards Board. IN WITNESS WHEREOF, the parties hereto have caused these presents to be executed by their respective officers thereunto duly authorized as of the Day and year first written, BOSTON GAS COMPANY EL PASO ENERGY MARKETING COMPANY By: /s/ William R. Luthern By: /s/ Kathleen Eisbrenner ----------------------- ---------------------- Signature Signature William R. Luthern Kathleen Eisbrenner ----------------------- ---------------------- Print Name Print Name Vice President Vice President ----------------------- ---------------------- Buyer Seller ESSEX GAS COMPANY COLONIAL GAS COMPANY By: /s/ William R. Luthern By: /s/ William R. Luthern ----------------------- ---------------------- Signature Signature William R. Luthern William R. Luthern ----------------------- ---------------------- Print Name Print Name Vice President Vice President ----------------------- ---------------------- Buyer Buyer AMENDMENT TO THE GAS RESOURCE PORTFOLIO MANAGEMENT AND GAS SALES AGREEMENT BETWEEN BOSTON GAS COMPANY, COLONIAL GAS COMPANY, AND ESSEX GAS COMPANY AS BUYER AND EL PASO ENERGY MARKETING COMPANY AS SELLER DATED SEPTEMBER 14,1999 Whereas, Boston Gas Company, Colonial Gas Company and Essex Gas Company (hereinafter jointly referred to as "Buyer") and El Paso Energy Marketing Company ("Seller") are parties to a certain Gas Resource Portfolio Management and Gas Sales Agreement dated September 14, 1999 (the "Agreement"; and, Whereas, the parties wish to clarify certain provisions of the Agreement with respect to the timing of transfer of title to natural gas in Underground Storage; And Whereas, the Department of Telecommunications and Energy's October 18, 1999 order in D.T.E. 99-76 approving the Agreement required that the Agreement be amended to include certain reporting requirements by Seller to Buyer; Now therefore in accordance with section 12.5 of the Agreement, the parties agree to the following revisions to the Agreement: I. Section 4.1.1 of the Agreement is deleted and replaced with the following Section 4.1.1 4.1.1 Transfer of Gas in Underground Storage. The Initial Underground Storage Balance shall be under the control and discretion of Seller effective with the Term of this Agreement. Title to such Initial Underground Storage Balance shall reside with Buyer so long as the Gas remains in inventory and shall transfer to Seller upon withdrawal at no cost to Seller. No resale agreement or other indicia of the transfer other than this Agreement shall be necessary to evidence such transfer of title. Buyer warrants title to all Gas withdrawn from Underground Storage and delivered to Seller hereunder, and further warrants that such Gas is free from liens and adverse claims of every kind upon such delivery. Buyer will indemnify and save Seller harmless against all loss, damage and expense of every character on account of adverse claims to such Gas prior to the transfer of title from Seller to Buyer. Seller shall ensure that all tariff provisions and other compliance requirements of underground storage vendors applicable to Gas in underground storage are met and penalties are avoided. Any penalties incurred by Buyer or Seller as a result of Sellers utilization of Gas in underground storage shall be the sole responsibility of Seller. Prior to April 1st of each year. Seller and Buyer will agree on underground storage refill volumes to be injected into underground storage over the following seven Month period, such volumes to be priced in accordance with section 3.4 above. Unless otherwise agreed to in writing prior to March 15, 2002, at the end of this Agreement, Seller shall cause Buyer's underground storage to be 95 percent full and return control, discretion and title of such Gas in underground storage to Buyer. Buyer and Seller agree to work together in complying with all contract termination provisions, including but not limited to the two (2) underground storage contracts that Buyer is holder of on National Fuel Gas Supply, II. The phrase "including the Ending Underground Storage Balance" is deleted from the second line of Section 6.2 of the Agreement. III. The following section 12.10 is added to the Agreement: 12.10 Affiliate Transactions Seller shall inform Buyer quarterly as to the terms of any release or assignment of the portfolio assets listed in Appendix I to a competitive affiliate, or customers of a competitive affiliate. Such reports shall indicate that Seller has not released or assigned the portfolio assets without simultaneously posting the offering electronically on the bulletin board of the applicable interstate pipeline. For the purposes of these reports, competitive affiliate shall be defined as any unregulated affiliate that is engaged in the sale or marketing of products or services on a competitive basis. All other terms and conditions of the Agreement shall remain in full force and effect. BOSTON GAS COMPANY COLONIAL GAS COMPANY By: William R. Luthern By: William R. Luthern ------------------------------ ------------------------------ Print Name Print Name /s/ William R. Luthern /s/ William R. Luthern ------------------------------ ------------------------------ Signature Signature Vice President Vice President ------------------------------ ------------------------------ Title Title 4 Nov. 99 4 Nov. 99 ------------------------------ ------------------------------ Date Date ESSEX GAS COMPANY By: William R. Luthern ------------------------------ Print Name By: /s/ William R. Luthern ------------------------------ Signature Vice President ------------------------------ Title 4 Nov. 99 ------------------------------ Date EL PASO ENERGY MARKETING COMPANY By: Steve Durio ------------------------------ Print Name /s/ Steve Durio ------------------------------ Signature Vice-President, Marketing ------------------------------ Title 4 Nov. 99 ------------------------------ Date EX-10.2.1 4 DEF. COMP. PLAN - DATED 10-27-99 Exhibit 10.2.1 EASTERN ENTERPRISES Deferred Compensation Plan for Trustees Amendment Pursuant to Paragraph 12 of the Eastern Enterprises Deferred Compensation Plan for Trustees (as amended, the "Plan"), the Plan is hereby amended as follows: 1. Paragraph 13 ("Miscellaneous") of the Plan is renumbered as Paragraph 14 and a new Paragraph 13 is added to read in its entirety as follows: "13. Changes in the Common Stock In the event of a stock dividend, stock split, recapitalization or similar event affecting the Common Stock, the number of Share Units allocated to Share Unit Accounts under the Plan shall be appropriately adjusted. In the event of a merger, consolidation or similar transaction in which Eastern is acquired or ceases to exist (a "transaction"), then: (a) there shall be established under the Plan a new notional investment alternative for amounts allocated to Cash Accounts, under which amounts from time to time allocated by a member to such alternative shall be deemed invested (notwithstanding Section 6.b. above) in one or more (as from time to time specified by the member) money market funds or other mutual funds administered by the Vanguard Group of Investment Companies in lieu of earning a notional interest return; and (b) if the acquiring or surviving entity or an affiliate thereof has equity securities that are publicly traded on a national securities exchange or NASDAQ ("successor stock"), each member participating in the Plan for whom a Share Unit Account is maintained may elect to have some portion or all of the balance of such Share Unit Account, determined by assigning to the Share Units allocated to such Account the same value as an Eastern shareholder with an equivalent number of shares of Common Stock would receive in the transaction, either (i) notionally reinvested in successor stock (valued as of its closing price on the date of the transaction), after which references in the Plan to "Common Stock", "Share Units", "Share Unit Account", "Fair Market Value" and related terms shall be construed as referring to the successor stock and units representing that stock, or (ii) allocated to the member's Cash Account (or to a new Cash Account established for the member, if the member has not previously had a Cash Account). If neither the acquiring or surviving entity in a transaction, nor its affiliates, have equity securities that are publicly traded on a national securities exchange or NASDAQ, the balance of each member's Share Unit Account, determined as provided in the preceding sentence, shall be allocated to the member's Cash Account (or to a new Cash Account established for the member, if the member has not previously had a Cash Account). In applying subsection (a) above, the Board may establish such reasonable rules as it deems necessary to administer allocations by members among the notional interest and Vanguard funds portions of Cash Accounts; provided, that such rules may not restrict the ability of a member to effectuate notional allocations or reallocations of his or her Cash Account less frequently than quarterly. Upon or following a transaction as hereinabove defined, the provisions of this Paragraph 13 may not be modified in any manner that adversely affects a member's rights hereunder without the written consent of such member." 2. Renumbered Paragraph 14 (formerly Paragraph 13) of the Plan ("Miscellaneous") is hereby amended by adding thereto the following subparagraph: "Reference is hereby made to the declaration of trust establishing Eastern Enterprises (formerly Eastern Gas and Fuel Associates) dated July 18, 1929, as amended, a copy of which is on file in the office of the Secretary of the Commonwealth of Massachusetts. The name "Eastern Enterprises" refers to the trustees under said declaration as trustees and not personally; and no trustee, shareholder, officer or agent of Eastern Enterprises shall be held to any personal liability in connection with the affairs of said Eastern Enterprises, but the trust estate only is liable." IN WITNESS WHEREOF, Eastern Enterprises has caused this instrument of amendment to be executed by its duly authorized officer as of the 27th day of October, 1999. EASTERN ENTERPRISES By: /s/ J. Atwood Ives ------------------------- - ---------- As approved by the Board of Trustees October 27, 1999 EX-10.2.2 5 DEF. COMP. PLAN - DATED 12-20-99 Exhibit 10.2.2 EASTERN ENTERPRISES Deferred Compensation Plan for Trustees Amendment (December 1999) Pursuant to Paragraph 12 of the Eastern Enterprises Deferred Compensation Plan for Trustees (as amended, the "Plan"), Paragraph 14 of the Plan ("Miscellaneous") is hereby amended by denominating the first subparagraph (begins: "The Plan was originally effective . . .") as subparagraph (a), by denominating the next subparagraph (begins: "Reference is hereby made . . .") as subparagraph (c), and by inserting immediately after subparagraph (a) and before subparagraph (c) the following new text, effective December 1, 1999: "(b) Reference is made to Eastern's Restricted Stock Plan for Non-Employee Trustees (the "Restricted Stock Plan"), under which Eligible Trustees have been granted shares of Eastern stock subject to specified forfeiture restrictions. In the case of each Eligible Trustee who (i) as of December 1, 1999 held shares of such stock as to which the Eligible Trustee had not made a so-called "83(b) election" ("applicable restricted shares") and (ii) elects to relinquish his or her applicable restricted shares in accordance with such procedures as the Secretary of Eastern may prescribe, there shall be credited to the Eligible Trustee's Share Unit Account, effective as of the date of such relinquishment, a number of vested Share Units equal to the number of applicable restricted shares so relinquished. The Share Units credited pursuant to the immediately preceding sentence shall be treated for purposes of the Plan in the same manner as other Share Units credited to the Eligible Trustee's Share Unit Account." IN WITNESS WHEREOF, Eastern Enterprises has caused this instrument of amendment to be executed by its duly authorized officer this 20th day of December, 1999. EASTERN ENTERPRISES By: /s/ J. Atwood Ives --------------------------- EX-10.5 6 SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN Exhibit 10.5 Eastern Enterprises Supplemental Executive Retirement Plan (Amended and Restated Effective September 1, 1999) 1. Purpose. The purpose of this Plan is to provide key management personnel of Eastern Enterprises and its subsidiaries with an appropriate level of retirement income by supplementing the retirement benefits provided under the Eastern Enterprises Headquarters Retirement Plan, the Boston Gas Company Retirement Plan, and the Midland Enterprises Inc. Salaried Retirement Plan, as applicable. The Plan as originally adopted and as subsequently amended is herein amended and restated effective September 1, 1999. 2. Definitions. For purposes of this Plan, the following terms will have the following meanings: (a) The word "Eastern" will mean Eastern Enterprises and any successor, including without limitation any successor to or acquiror of the stock or assets of Eastern in a transaction constituting a Change of Control. (b) The word "Plan" will mean the amended and restated Eastern Enterprises Supplemental Executive Retirement Plan set forth herein, together with all amendments hereto. Where the context requires, the term "Plan" also includes the Eastern Enterprises Supplemental Executive Retirement Plan as in effect prior to September 1, 1999. (c) The words "Retirement Plan" will mean, as applicable, the Eastern Enterprises Headquarters Retirement Plan, the Boston Gas Company Retirement Plan, and the Midland Enterprises Inc. Salaried Retirement Plan, as from time to time amended. (d) The words "Participating Subsidiary" will mean any Participating Employer (as defined in the Retirement Plan), other than Eastern. (e) The word "Compensation" will have the meaning provided in (i) or (ii) below, whichever is applicable. (i) With respect to any Officer first receiving benefits under the Plan before January 1, 1994, Compensation" means, for any year, the salary paid by Eastern or by a Participating Subsidiary to such Officer for such year (calculated as of his or her Earnings Measurement Date, as defined in the Retirement Plan) and fifty percent (50%) of bonuses and incentive awards paid (whether in cash or stock) by Eastern or by a Participating Subsidiary to such Officer in such year; provided, that amounts deferred by such Officer under Eastern's Deferred Compensation Plan for Certain Management Employees shall be treated as paid in the year they would have been payable but for such deferral; further provided, that in determining for the purposes hereof the amount of an incentive award paid (whether in cash or stock) under Eastern's Executive Incentive Compensation Plan (x) there shall be included only the lesser of the amount paid or the target award amount established in creating the incentive opportunity to earn such award and (y) awards based on a fixed number of shares of Eastern stock shall be valued at the price for Eastern stock utilized in creating the incentive opportunity to earn such award; and, further provided, that no amount will be included with respect to stock options or stock appreciation rights. (ii) With respect to any Officer first receiving benefits under the Plan on or after January 1, 1994, "Compensation" means, for any calendar year, the salary paid by Eastern or by a Participating Subsidiary to such Officer for such calendar year (calculated as of his or her Earnings Measurement Date, as defined in the Retirement Plan) and one hundred percent (100%) of bonuses and incentive awards (whether payable in cash or stock) earned by such Officer with respect to such calendar year under Eastern's Executive Incentive Compensation Plan or any similar executive incentive plan adopted by Eastern after January 1, 1994; provided, that amounts deferred by such Officer under any deferred compensation and/or savings plan maintained by Eastern or any Participating Subsidiary from time to time shall be treated as paid in the calendar year they would have been payable but for such deferral, and the election to so defer amounts earned shall be disregarded for purposes of determining amounts earned; further provided, that in determining for purposes hereof the amount of an incentive award earned (whether payable in cash or stock), (a) a bonus or award that relates to a plan period of more than one calendar year, when earned in accordance with such Plan at the end of such period, shall be deemed to have been earned in equal annual installments during such period, and (b) awards based on a fixed number of shares of Eastern stock shall be valued at the price for Eastern stock utilized in creating the incentive opportunity to earn such award; and, further provided, that no amounts will be included with respect to stock options, stock appreciation rights or restricted stock awards. (f) The word "Officer" will mean any active employee of Eastern or a Participating Subsidiary employed as a Chairman, a President, a Vice President, a General Counsel, an Assistant Vice President, a Treasurer, a Secretary, or a Controller. In addition to the offices named in the preceding sentence, the Compensation Committee may from time to time designate other offices of Eastern or a Participating Subsidiary, the holders of which will be Officers within the meaning of this Section 2(f). (g) The words "Eligible Officer" will mean any Officer who satisfies the eligibility requirements set forth in Section 4 of the Plan. (h) The words "Executive Service" will mean the period of service which an employee serves as an Officer, except that no service after age sixty-five (65) will be counted as Executive Service. (i) The words "Break in Service" will have the same meaning as in the Retirement Plan. (j) The words "Computation Period" will have the same meaning as in the Retirement Plan. (k) The words "Hour of Service" will have the same meaning as in the Retirement Plan. (l) The words "Social Security Benefit" will have the same meaning as in the Retirement Plan. (m) A "Change of Control" will be deemed to have occurred if, after January 1, 1998, any of the following occurs: (i) any "person" (as such term is used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934, as amended) or group of "persons" (as so defined), other than Eastern, becomes a beneficial owner directly or indirectly of securities representing twenty-five percent (25%) or more of the combined voting power of the then outstanding voting securities of Eastern; or (ii) there is consummated a merger or consolidation ("merger") involving Eastern and immediately after such merger the beneficial owners immediately prior to such merger of the then outstanding voting securities of Eastern do not continue to own beneficially at least sixty percent (60%) of the voting securities of the entity or entities resulting from such merger; or (iii) there is consummated a sale, lease, exchange, spin-off or other transfer (any of the foregoing, a ("transfer") of all or substantially all of the assets or business of Eastern and its subsidiaries, other than any such transfer resulting in beneficial ownership of not less than sixty percent (60%) of the assets or business so transferred or not less than sixty percent (60%) of the voting securities of the entity or entities to which such assets were transferred by the owners immediately prior to the transfer of the then outstanding voting securities of Eastern; or (iv) within any two-year period, individuals who at the beginning of such period constituted the Board of Trustees of Eastern cease for any reason to constitute a majority thereof; provided, that any trustee who is not in office at the beginning of such two-year period but whose election or nomination for election was approved by a vote of at least two-thirds of the trustees in office at the time of such approval who were either trustees of Eastern at the beginning of such period or who were elected to the Board of Trustees pursuant to an election which was, or for which the nomination for election was, previously so approved shall be deemed to have been in office at the beginning of such two-year period; or (v) in the case of an Eligible Officer employed by a Participating Subsidiary, Eastern sells or otherwise disposes of all or substantially all of its voting securities of the Participating Subsidiary or the Participating Subsidiary sells or otherwise disposes of all or substantially all of its assets, excluding in either case any transaction resulting in beneficial ownership of not less than fifty percent (50%) of the assets or business so transferred or not less than fifty percent (50%) of the voting securities of the entity or entities to which such assets were transferred by the owners immediately prior to the transfer of the then outstanding voting securities of Eastern. (n) The words "COC Agreement" mean an agreement between an Officer and Eastern or one or more subsidiaries of Eastern providing for severance pay or other benefits to the Officer in the event of a Change of Control or similar change in the control of Eastern and its subsidiaries or upon termination of the Officer's employment in connection with or during a specified period that includes such Change of Control or similar change. (p) The words "Beginning Date" means, with respect to an Officer, the earlier of (i) the date on which Eastern enters into a definitive agreement the transactions contemplated by which will, when consummated, constitute a Change of Control with respect to such Officer, or (ii) the date which precedes the Change of Control by six (6) months. (q) The words "Protected Period" mean, with respect to any Officer, the period beginning on the Beginning Date for such Officer and ending on the date which follows the related Change of Control by twenty-four (24) months. Wherever used in the Plan, the masculine pronoun will include the feminine. 3. Administration. The Plan will be administered by the Compensation Committee of Eastern, which will have full power and authority to construe, interpret and administer the Plan. Decisions of the Compensation Committee will be final and binding on all persons. The Compensation Committee may, in its discretion, adopt, amend and rescind rules and regulations, not inconsistent with the Plan, relating to the administration thereof. In individual cases, the Compensation Committee may also credit any Officer for either eligibility or benefit-determination purposes, or both, with periods of service in addition to those otherwise taken into account under the Plan, whether or not such Officer has actually performed service for Eastern or its subsidiaries in such periods. 4. Eligibility. All Officers fifty-five (55) years of age or older who (i) are serving in those positions of responsibility that most greatly influence Eastern's performance (such positions to be designated from time to time by the Compensation Committee with reference to this Section 4); (ii) have completed at least twenty-four (24) consecutive months of service in one or more of the positions so designated by the Compensation Committee; and (iii) are Members in the Retirement Plan (as defined therein) will be covered by the Plan and will be eligible to receive benefits hereunder, subject to the provisions of the Plan. The Compensation Committee may extend eligibility under the Plan on an individual basis to other employees of Eastern or of its subsidiaries; provided, however, that no individual (other than a spouse or beneficiary of an Eligible Officer) who is not a Member in the Retirement Plan will be eligible to receive benefits under the Plan. An Officer who, at any time during his or her Protected Period satisfies the requirements of (i), (ii) and (iii) of this Section 4 will also be an Eligible Officer covered by the Plan, whether or not he or she has attained age fifty-five (55), if the employment of such Officer with Eastern and its subsidiaries terminates under circumstances which at the time or upon a subsequent Change of Control entitle such Officer to a severance payment or payments under a COC Agreement (but if the employment of such Officer so terminates, he or she shall be deemed to have been an Eligible Officer from the beginning of the Protected Period). 5. Amount of Benefit. Subject to the offset described in Section 7 below, the actuarial adjustments described in Section 8 below and the off-sets described in Section 9 below, the benefit provided under the Plan with respect to any Eligible Officer will be determined as follows: (a) Termination of Employment At or After Age 62/60. (i) Except as otherwise provided in Section 5(a)(ii) below or Section 5(c) below, every Eligible Officer whose employment by Eastern and its subsidiaries terminates (other than by death) upon or after his or her attaining age sixty-two (62) will be eligible to receive an annual amount which is the product of (i) his or her average annual Compensation for those five (5) years, selected from among the last ten (10) years of his or her Executive Service, in which his or her aggregate Compensation was highest, and (ii) a percentage determined according to the following table: Years of Executive Service Percentage ------------------ ---------- Less than 10 None 10 35 11 36.5 12 38 13 39.5 14 41 15 42.5 16 44 17 45.5 18 47 19 48.5 20 or more 50 For purposes of this Section 5(a)(i), a Computation Period in which an Officer has one thousand (1,000) or more Hours of Service as an Officer will be deemed to be a "year of Executive Service," except that years of Executive Service prior to any Break in Service will be disregarded to the extent that Years of Vesting Service (within the meaning of the Retirement Plan) prior to such Break in Service would be disregarded for purposes of the Retirement Plan. (ii) Subject to Section 5(c) below, every Eligible Officer whose employment by Eastern and its subsidiaries terminates (other than by death) upon or after his or her attaining age sixty (60) and who first receives benefits under the Plan on or after January 1, 1994 will be eligible to receive an annual amount which is the product of (i) his or her average annual Compensation for those five (5) calendar years, selected from among the last ten (10) calendar years of his or her Executive Service, in which his or her aggregate Compensation was highest, and (ii) a percentage determined according to the following table: Non-Calendar Years of Executive Service Percentage --------------------- ---------- Less than 10 None 10 35 11 36.5 12 38 13 39.5 14 41 15 42.5 16 44 17 45.5 18 47 19 48.5 20 or more 50 For purposes of this Section 5(a)(ii), a Computation Period in which an Officer has one thousand (1,000) or more Hours of Service as an Officer will be deemed to be a "non-calendar year of Executive Service," and a calendar year in which an Officer has one thousand (1,000) or more Hours of Service as an Officer will be deemed to be a "calendar year of Executive Service", except that if any Years of Vesting Service (within the meaning of the Retirement Plan) prior to any Break in Service with respect to such Officer would be disregarded for purposes of the Retirement Plan, an equivalent number of non-calendar years of Executive Service and an equivalent number of calendar years of Executive Service will be disregarded hereunder. (b) Termination of Employment Before Age 62/60. (i) Except as otherwise provided in Section 5(b)(ii) below or Section 5(c) below, every Eligible Officer whose employment by Eastern and its subsidiaries terminates (other than by death) upon or after his or her attaining age fifty-five (55), but before his or her attaining age sixty-two (62), will be eligible to receive an annual amount equal to the amount calculated under Section 5(a)(i) above multiplied by a percentage determined according to the following table: Age at Commencement of Benefit Percentage ------------------- ---------- 61 95 60 90 59 85 58 80 57 75 56 70 55 65 (ii) Subject to Section 5(c) below, every Eligible Officer whose employment by Eastern and its subsidiaries terminates (other than by death) upon or after his or her attaining age fifty-five (55), but before his or her attaining age sixty (60), and who first receives benefits under the Plan on or after January 1, 1994 will be eligible to receive an annual amount equal to the amount calculated under Section 5(a)(ii) above multiplied by a percentage determined according to the following table: Age at Commencement of Benefit Percentage ------------------- ---------- 59 95 58 90 57 85 56 80 55 75 (c) Benefits Following a Change of Control. Every Eligible Officer whose employment by Eastern and its subsidiaries terminates (other than by death) under circumstances which at the time or upon a subsequent Change of Control entitle him or her to a severance payment or payments under a COC Agreement will be eligible to receive an annual amount determined under this paragraph (c). The annual amount determined under this paragraph (c) is the product of (i) The Eligible Officer's average annual Compensation for those five (5) calendar years, selected from among the last ten (10) calendar years of his or her Executive Service, in which his or her aggregate Compensation was highest; provided, that the computation of such Eligible Officer's average annual Compensation for purposes of this paragraph (i) shall include the period by reference to which the severance payment or payments under the COC Agreement are determined (for example, three years in the case of a severance payment equal to three years of compensation) and the amount of such severance payment or payments, if the inclusion of such factors in the computation would result in a higher amount of average annual Compensation than would result from a determination under this paragraph (i) without regard to such factors; and (ii) a percentage determined according to the following table: Non-Calendar Years of Executive Service Percentage -------------------------- ---------- Less than 10 None 10 35 11 36.5 12 38 13 39.5 14 41 15 42.5 16 44 17 45.5 18 47 19 48.5 20 or more 50 In determining "non-calendar years of Executive Service" for purposes of this paragraph (c)(ii), the rules described in Section 5(a)(ii) shall apply except that an Eligible Officer described in this subsection (c) shall be credited with a number of additional non-calendar years of Executive Service equal to the number of years with respect to which the severance payment or payments under his or her COC Agreement are determined (for example, three years in the case of a severance payment equal to three years of compensation); and (iii) in the case of an Eligible Officer whose age at commencement of benefits is less than sixty (60), a percentage determined according to the following table: Age at Commencement of Benefit Percentage ------------------- ---------- 59 95 58 90 57 85 56 80 55 75 (d) Death Benefits. If an Eligible Officer dies while serving (or deemed to be serving under Section 6 below) as an Eligible Officer, or after termination of employment in accordance with Section 5(e)(i), (ii), (iii) or (iv) but before commencement of benefits, and leaves a surviving spouse, the spouse, if he or she survives to the date benefits commence, will be eligible to receive an annual amount equal to the amount, if any, the Eligible Officer would have been entitled to receive under (a),(b) or (c) above, whichever is applicable, had his or her employment terminated in accordance with Section 5(e)(i), (ii), (iii) or (iv) on the earlier of the day before the Eligible Officer's death or the date of actual termination of employment. (e) Conditions and Limitations. No officer whose employment terminates before his or her attaining age sixty-five (65) will be eligible for benefits under the Plan unless: (i) the Compensation Committee has given the Officer its prior written permission (any Officer who dies shall be deemed to have retired with the prior written permission of the Compensation Committee); or (ii) the Officer has given written notification to the Compensation Committee at least six months in advance of the termination; or (iii) the Officer is terminated by Eastern, or a subsidiary of Eastern, and such termination is not determined by the Compensation Committee to be a discharge for cause which casts such discredit on the Officer or Eastern, or a division or subsidiary of Eastern, as to justify forfeiture of any benefits under this Plan; or (iv) in the case of an Eligible Officer described at Section 5(c) above, the Eligible Officer's employment terminates under circumstances which at the time or upon a subsequent Change of Control entitle him or her to a severance payment or payments under a COC Agreement. No benefit with respect to any Eligible Officer under the Plan will exceed, after adjustment for the offset described in Section 7 below but before actuarial adjustment under Section 8 below and before adjustment for the offsets described in Section 9 below, an amount equal to three (3) times the greater of (i) $90,000 or (ii) the maximum benefit that could be paid with respect to such Eligible Officer under section 415(b)(1)(A) of the Internal Revenue Code of 1986, as from time to time amended (the "Code"), as adjusted pursuant to section 415(d) of the Code and as in effect on the date of such Eligible Officer's termination of employment. Except as otherwise provided herein, an Officer's employment will terminate for purposes of the Plan as of the date on which such Officer (i) retires, resigns or is dismissed from service as an Officer; (ii) dies while serving as an Officer; or (iii) departs from the service of Eastern and its subsidiaries for any reason; provided, that an Officer will not be deemed to have terminated his or her employment solely by reason of a duly approved leave of absence. For purposes of this Section 5 only, the age at which an Officer's employment terminates or his or her benefits commence will be calculated in all cases as of such Officer's nearest birthday. Notwithstanding any other provision of this Plan, an Eligible Officer's surviving spouse shall not be entitled to any benefits hereunder unless such spouse was the person to whom the Eligible Officer was married at the time benefit payments commenced under this Plan (or at the time of the Eligible Officer's death, if earlier). 6. Disability. For purposes of satisfying the length-of-service requirements set forth in Section 4 and Section 5 above, an Officer who is unable to work because of a disability for which he or she is eligible to receive benefits under a long-term disability program sponsored by Eastern or by a Participating Subsidiary will be deemed to continue to serve as an Officer at the same salary he or she was receiving when forced to stop working by reason of his or her disability, until such time as he or she returns to active employment or his or her employment terminates. 7. Offset for Social Security payments. The annual benefit calculated with respect to any Eligible Officer under Section 5 above shall be reduced (but not below zero), before the adjustments described in Section 8 and Section 9 below, by a percentage of the Eligible Officer's Social Security Benefit for any year in which such Eligible Officer is eligible to receive a Social Security benefit (or, if the benefit hereunder becomes payable under Section 5(d) by reason of the Eligible Officer's death, by a percentage of the Social Security Benefit to which the Eligible Officer would have been entitled, but only for those years in which such Eligible Officer, had he or she lived, would have been eligible for Social Security benefits), as follows: for Officers first receiving benefits under the Plan prior to January 1, 1994, such percentage shall be one hundred percent (100%); for Officers first receiving benefits under the Plan on or after January 1, 1994, such percentage shall be fifty percent (50%). 8. Actuarial adjustment. For purposes of determining the benefit provided under this Plan with respect to any Eligible Officer, the amount calculated under Section 5 above with respect to such Eligible Officer, after adjustment for the offset described in Section 7 above, will be actuarially adjusted as necessary to reflect payment in the form specified in Section 10, in the same manner and using the same actuarial assumptions as would apply in determining how an accrued benefit of like amount payable (with the same commencement date) under the Retirement Plan would be actuarially adjusted (if at all) to reflect payment under the Retirement Plan in such specified form. 9. Offset for other benefits. The annual benefit calculated with respect to any Eligible Officer under Section 5(a), Section 5(b) or Section 5(c) above, as adjusted for the offset described in Section 7 above and as further adjusted actuarially under Section 8 above, will be reduced (but not below zero) by the following amounts: (a) the amount payable annually with respect to such Eligible Officer (1) under the Retirement Plan, assuming commencement on the commencement date hereunder and payment (i) if the Eligible Officer is unmarried on such commencement date, in the form of a single life annuity over the life of the Eligible Officer but with sixty (60) monthly payments guaranteed, or (ii) in every other case, in the form of a joint and survivor annuity under which reduced payments will be made to the Eligible Officer for his or her lifetime and, following his or her death, if his or her spouse survives the Eligible Officer, payments equal to one-half the amount payable to the Eligible Officer during his or her lifetime will be paid to such surviving spouse for the remainder of such spouse's lifetime, or (2) under any other retirement plan to which Eastern or any of its subsidiaries or affiliates has contributed (payments under any such other plan to be determined, for purposes of this Section 9, as though payable in the form described in (1)(i) or (1)(ii) above, whichever is applicable); and (b) with respect any Eligible Officer first receiving benefits under the Plan prior to January 1, 1994, and with respect to any Eligible Officer previously employed by Colonial Gas Company or Transgas Inc. who became an Eligible Officer in connection with, or following, the acquisition of Colonial Gas Company by Eastern and its subsidiaries, the amount, if any, which the Compensation Committee reasonably determines, in its sole discretion, to be the amount of annual retirement income or the equivalent thereof to which the Eligible Officer is entitled by reason of any prior employment (including for this purpose any service as a fiduciary or a director), assuming the same form of payment as the applicable benefit form under (a) above. If an Eligible Officer dies while employed (or deemed to be employed under Section 6 above) as an Eligible Officer, or after termination of employment in accordance with Section 5(e)(i), (ii), (iii) or (iv) but before commencement of benefits, and leaves a surviving spouse, the death benefit payable to his or her spouse each year under Section 5(d) above, as adjusted for the offset described in Section 7 above and as further adjusted actuarially pursuant to Section 8 above, will be reduced (but not below zero) by the following amounts: (aa) the death benefit provided the spouse each year under the Retirement Plan, assuming commencement on the same commencement date as hereunder, or under any other retirement plan to which Eastern or any of its subsidiaries or affiliates has contributed (payments under any such other plan to be determined, for purposes of this Section 9, as though payable in the same form and commencing at the same time as the death benefit hereunder); and (bb) with respect to the spouse of an Eligible Officer who dies prior to January 1, 1994, the amount, if any, which the Compensation Committee reasonably determines, in its sole discretion, to be the annual income to which the spouse of such Eligible Officer is entitled under any plan, agreement or arrangement maintained by a prior employer of such Eligible Officer (or in connection with any service of such Eligible Officer as a fiduciary or director), assuming the same form of payment and benefit commencement date as hereunder. 10. Form and Timing of Benefits for Eligible Officers. Benefits provided to an Eligible Officer under the Plan upon the termination of his or her employment will be payable (a) if the Eligible Officer is unmarried on the commencement date of benefits hereunder, in the form of a single-life annuity over the life of the Eligible Officer but with sixty (60) monthly payments guaranteed, or (b) in every other case, in the form of a joint and survivor annuity under which reduced payments will be made to the Eligible Officer for his or her lifetime and, following his or her death, if his or her spouse survives the Eligible Officer, payments equal to one-half the amount payable to the Eligible Officer during his or her lifetime will be paid to such surviving spouse for the remainder of such spouse's lifetime. Benefits payable to a surviving spouse under Section 5(d) above will be payable in the form of a single-life annuity over the life of such surviving spouse. Solely for purposes of determining the amount payable to a surviving spouse under Section 5(d), the benefit the deceased Eligible Officer would have been entitled to receive had such Eligible Officer's employment terminated in accordance with Section 5(e)(i), (ii), (iii) or (iv) shall be assumed to have been payable in the form of a joint and survivor annuity under which reduced payments are payable to the Eligible Officer for his or her lifetime and, following his or her death, reduced payments in the same amount are payable to the Eligible Officer's surviving spouse for the remainder of such spouse's lifetime. Benefits provided hereunder will commence as of the first day of the month next following the Eligible Officer's termination of employment (or the Eligible Officer's death, in the case of benefits described in Section 5(d)), irrespective of the form and timing of benefit payments under the Retirement Plan provided, that in the case of an Eligible Officer described in Section 5(c), benefits shall not commence prior to the first day of the month next following the date the Eligible Officer attains or would have attained age 55. 11. Requirement of Non-Competition. If at any time the Compensation Committee determines that a person receiving benefits hereunder is competing, directly or indirectly, with the business of Eastern, it may discontinue the payment of such benefits to such person. For purposes of this paragraph, the phrase "competing, directly or indirectly, with the business of Eastern" will be deemed to include (without limiting the generality of the same) engaging or being interested, directly or indirectly, as owner, director, officer, employee, partner, through stock ownership (other than ownership of less than two (2%) percent of the outstanding stock of any publicly owned company), investment of capital, lending of money or property, rendering of services or otherwise, either alone or in association with others, in the operation of any type of business or enterprise in any way competitive with the business of Eastern or of any of its subsidiaries. Notwithstanding the foregoing, the Compensation Committee may waive or modify its right to discontinue payments to any person by written agreement with such person. The provisions of this Section 11 shall not apply in the case of an Eligible Officer receiving benefits pursuant to Section 5(c). 12. Limitation of Rights; Special Provision in the Event of Change in Control. Nothing in this Plan will be construed to create a trust or to obligate Eastern or any other person to segregate a fund, purchase an insurance contract, or in any other way currently to fund the future payment of any benefits hereunder, nor will anything herein be construed to give any employee or any other person rights to any specific assets of Eastern or of any other person. Notwithstanding the foregoing, Eastern in its sole discretion may establish a so-called "rabbi" trust or similar trust, whether or not conforming to Rev. Proc. 92-64, or may avail itself of any such trust which it has previously established, to provide for the payment of benefits hereunder, subject to such terms as the Board of Trustees may determine (a "trust"). In the event Eastern establishes a trust in respect of the Plan or causes a pre-existing trust to cover the Plan, and at the time of a Change of Control such trust (i) has not been terminated or revoked and (ii) is not "fully funded" (as hereinafter defined), Eastern shall promptly deposit in such trust cash sufficient to cause the trust to be "fully funded" as of the date of the deposit. For purposes of this subparagraph, any such trust shall be deemed "fully-funded" as of any date if, as of that date, the fair market value of the assets held in trust is not less than (1) the aggregate present value as of that date of all benefits then in pay status under the Plan (including benefits not yet commenced but in respect of Eligible Officers whose employment has terminated in accordance with Section 5(e)(i), (ii), (iii) or (iv)) plus (2) the aggregate present value as of that date of all benefits that would be payable under the Plan if all other persons who are (or, but for not yet having attained age 55, would be) Eligible Officers were deemed to have terminated employment on that date in accordance with Section 5(e)(i), (ii), (iii) or (iv) plus (3) the aggregate present value as of that date of all benefits payable (as determined under rules similar to the rules described in (1) and (2)) under all other defined-benefit type plans and arrangements provided for through the trust, plus (4) the aggregate of the account balances, determined as of such date, under all individual-account type plans and arrangements provided for through the trust. In applying clauses (1), (2) and (3) of the previous sentence, present value shall be determined by using the interest and mortality assumptions used in determining lump sum present values under the qualified defined benefit pension plan maintained by Eastern, of if no such qualified plan is then maintained by Eastern, by applying the assumptions used prior to the Change of Control in determining Eastern's pension expense under FAS 87 or any successor pronouncement with respect to such plan or arrangement. 13. Rights Non-Assignable. No employee or beneficiary or any other person will have any right to assign or otherwise to alienate the right to receive payments under the Plan, in whole or in part. 14. Termination; Amendment. Eastern reserves the right at any time by action of its Board of Trustees to terminate the Plan or to amend its provisions in any way, except that on and after the earlier of (a) the date on which Eastern enters into a definitive agreement the transactions contemplated by which will, when consummated, constitute a Change of Control, or (b) the date which precedes the Change of Control by six (6) months, no such amendment or termination shall reduce the amount of Eastern's obligations, if any, under Section 12 with respect to such Change of Control or extend the period within which Eastern may satisfy such obligations. In addition, the Plan will automatically terminate if at any time (and as of the date that) the Retirement Plan is terminated. Notwithstanding the foregoing, no termination or amendment of the Plan (a "Plan Change") will reduce the benefit, if any, payable under the Plan to any person with respect to an Eligible Officer whose employment with Eastern and its subsidiaries was terminated prior to such Plan Change, nor shall any Plan Change reduce the benefit, if any, to be paid with respect to a person who is (or, but for not yet having attained age 55, would be) an Eligible Officer on the date of such Plan Change below the amount, if any, which such person would have been entitled to receive if his or her employment had terminated in accordance with Section 5(e)(i), (ii), (iii) or (iv) on the day before such Plan Change; provided, however, that benefits otherwise payable hereunder with respect to an individual may be reduced or otherwise modified by separate agreement between Eastern and such individual. Section 15. Other. Reference is hereby made to the declaration of trust establishing Eastern Enterprises (formerly Eastern Gas and Fuel Associates) dated July 18, 1929, as amended, a copy of which is on file in the office of the Secretary of the Commonwealth of Massachusetts. The name "Eastern Enterprises" refers to the trustees under said declaration as trustees and not personally; and no trustee, shareholder, officer or agent of Eastern Enterprises shall be held to any personal liability in connection with the affairs of said Eastern Enterprises, but the trust estate only is liable. IN WITNESS WHEREOF, Eastern has caused this amended and restated Plan to be executed by its duly authorized officer as of the 22nd day of September, 1999. EASTERN ENTERPRISES By: /s/ J. Atwood Ives -------------------------- EX-10.6.4 7 TRUST AGREEMENT - EASTERN & KEY TRUST Exhibit 10.6.4 EASTERN ENTERPRISES Amendment of Trust Agreement Instrument of amendment dated September 22, 1999 by and between Eastern Enterprises ("Eastern") and Key Trust Company of Ohio, N.A. (the "Trustee"): WHEREAS Eastern and the Trustee are parties to a trust agreement originally dated January 29, 1987 and subsequently amended, including to substitute the current Trustee as trustee of the trust established under such agreement (as heretofore amended, the "Trust Agreement"); and WHEREAS Eastern wishes to amend the Trust Agreement as hereinafter provided; and WHEREAS Eastern has reserved the right to make such amendment under Section 10(a) of the Trust Agreement; NOW, THEREFORE, in consideration of these premises, the Trust Agreement is hereby amended as follows, effective immediately: 1. Section 2(a) of the Trust Agreement is amended by deleting that portion of the last sentence thereof which begins "and further provided, that no such modification or supplement . . ." and ends ". . . prior to the Change of Control" and replacing the deleted text with the following: "and further provided, that no such modification or supplement upon or following a Change of Control shall (i) expand the list of plans or other compensation or benefit arrangements (as set forth in the most recent Schedule A delivered to the Trustee prior to the Change of Control) under which compensation or benefits may be provided from assets of the Trust, nor shall any amendment or modification of any such plan or arrangement adopted upon or following the Change of Control be taken into account in determining compensation or benefits that may be provided from assets of the Trust (but nothing in this proviso shall be construed as limiting the right of a Trust Beneficiary to claim benefits from Eastern or its subsidiaries, or a successor, in respect of any such amendment or modification), or (ii) add any person as a Trust Beneficiary who was not an employee or trustee of Eastern prior to the Change of Control." IN WITNESS WHEREOF, Eastern Enterprises and the Trustee have caused this instrument of amendment to be executed by their duly authorized officers as of the date set forth above. EASTERN ENTERPRISES By: /s/ J. Atwood Ives ----------------------------- KEY TRUST COMPANY OF OHIO, N.A. By: /s/ Margaret Halloran, AVP ----------------------------- - ---------- Approved by the Board of Trustees on September 22, 1999 EX-10.19.3 8 CREDIT AGREEMENT DATED 8-10-99 Exhibit 10.19.3 AMENDMENT NO. 3 TO CREDIT AGREEMENT AND OTHER LOAN DOCUMENTS AMENDMENT NO. 3 DATED AS OF AUGUST 20, 1999 ("AMENDMENT NO. 3") TO THE CREDIT AGREEMENT dated as of December 31, 1994 (as amended and in effect immediately prior to the date hereof, the "Credit Agreement"), by and among (a) EASTERN ENTERPRISES, a Massachusetts voluntary association, BOSTON GAS COMPANY, a Massachusetts corporation, MIDLAND ENTERPRISES INC., a Delaware corporation (collectively the "Borrowers"), (b) FIFTH THIRD BANK, MELLON BANK, N.A., MORGAN GUARANTY TRUST COMPANY OF NEW YORK, FLEET NATIONAL BANK, THE BANK OF NOVA SCOTIA, AND BANKBOSTON, N.A. (F/K/A THE FIRST NATIONAL BANK OF BOSTON) (collectively, the "Banks"), and (c) BANKBOSTON, N.A. (F/K/A THE FIRST NATIONAL BANK OF BOSTON), as agent (in such capacity, the "Agent") for the Banks, AND OTHER LOAN DOCUMENTS. WHEREAS, the Borrowers, the Agent and the Banks have agreed to modify certain terms and conditions of the Credit Agreement and the other Loan Documents, as more fully set forth herein; and NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the Borrowers, the Agent and the Banks hereby agree as follows: (Sec.) 1. DEFINITIONS. Capitalized terms used herein and not otherwise defined herein have the meanings given to such terms in the Credit Agreement, as amended hereby. (Sec.) 2. AMENDMENT TO SECTION 1 OF THE CREDIT AGREEMENT. Section 1.1 of the Credit Agreement is hereby amended as follows: (a) The definition of "Designated Documents" set forth in such section is amended and restated in its entirety to read as follows: "Designated Documents": Eastern's, Boston Gas' and Midland's 1998 Form 10-K's and Eastern's, Boston Gas' and Midland's quarterly reports on Form 10-Q's for the fiscal quarters of such Borrowers ended March 31, 1999 and June 30, 1999. (b) The definition of "FNBB" set forth in such section is amended and restated in its entirety to read as follows: "FNBB": BankBoston, N.A. (f/k/a The First National Bank of Boston), a national banking association. (c) The definition of "Special Counsel" set forth in such section is amended and restated in its entirety to read as follows: "Special Counsel": Bingham Dana LLP, or such other firm selected by the Agent. (Sec.) 3. AMENDMENT TO SECTION 4 OF THE CREDIT AGREEMENT. Section 4 of the Credit Agreement is hereby amended by inserting a new subsection 4.18 to read as follows: 4.18 YEAR 2000 PROBLEM. Each of the Borrowers have (i) reviewed the areas within their businesses and operations which could be adversely affected by failure to become "Year 2000 Compliant" (i.e. that computer applications, imbedded microchips and other systems used by any Borrower will be able properly to recognize and perform properly date-sensitive functions involving certain dates prior to and any date after December 31, 1999), (ii) developed a detailed plan and timetable to become Year 2000 Compliant in a timely manner, and (iii) committed adequate resources to support the Year 2000 plan of the Borrowers. Based upon such review, each of the Borrowers reasonably believes that the Borrowers will become "Year 2000 Compliant" in a timely manner except to the extent that failure to do so will not have any materially adverse effect on the business or financial condition of any Borrower. (Sec.) 4. AMENDMENT TO SECTION 5 OF THE CREDIT AGREEMENT. Section 5.5 of the Credit Agreement is hereby amended by deleting the words "the good standing and legal existence of, and the payment of franchise taxes therein by, such Borrower" and substituting in place thereof the words "the good standing and legal existence of, and the payment of franchise taxes therein by, such Borrower (except that with respect to Eastern, such certificate shall certify as to Eastern's filing of all necessary certificates, its payment of all necessary fees and its ability to exercise in Massachusetts all of the powers recited in its Declaration of Trust and to transact business in Massachusetts)". (Sec.) 5. AMENDMENT TO SECTION 6 OF THE CREDIT AGREEMENT. Section 6.1 of the Credit Agreement is hereby amended and restated in its entirety to read as follows: 6.1 COMPLIANCE. On each Borrowing Date, and after giving effect to the Loans to be made on such date (a) each of the Borrowers and the Guarantor shall be in compliance with all of the terms, covenants and conditions of this Agreement and the other Loan Documents applicable to it, (b) there shall exist no Event of Default, and (c) the representations and warranties contained in this Agreement or in any other Loan Document, or otherwise in writing made by any Borrower or the Guarantor in connection herewith or therewith shall be true and correct in all material respects with the same effect as though such representations and warranties had been made on such Borrowing Date (except such thereof as specifically refer to an earlier date and except for changes resulting from mergers, consolidations or Sales of assets or stock not prohibited by paragraphs 8.6, 8.6A or 8.6B and changes occurring in the ordinary course of business that singly or in the aggregate are not materially adverse) and the Agent shall have received a certificate, dated the Borrowing Date, and signed by a duly authorized officer of Eastern, to the same effect as all of the foregoing matters. (Sec.) 6. SUBSTITUTION OF NEW EXHIBIT H TO THE CREDIT AGREEMENT. The Credit Agreement is hereby amended by deleting Exhibit H thereto in its entirety and substituting in place thereof the form of Exhibit H attached hereto. (Sec.) 7. REFERENCES TO THE FIRST NATIONAL BANK OF BOSTON OR FNBB. Each reference in the Credit Agreement and the other Loan Documents to The First National Bank of Boston or FNBB shall be deemed to be a reference to BankBoston, N.A. (Sec.) 8. CONDITIONS TO EFFECTIVENESS. This Amendment No. 3 shall be effective as of the date hereof upon the satisfaction of each of the following conditions: (a) The Amendment. This Amendment No. 3 shall have been duly and properly authorized, executed and delivered to the Agent by the Borrowers, the Agent and the Banks, and shall be in full force and effect. (b) Representations and Warranties; Absence of Default. Each of the representations and warranties made by or on behalf of the Borrowers to the Banks or the Agent in the Credit Agreement, as amended hereby, and the other Loan Documents shall be true and correct in all material respects when made, shall be repeated on and as of the date hereof, and shall be true and correct in all material respects on and as of such date except, in each case, as affected by the consummation of the transactions contemplated hereby or by the Loan Documents and to the extent that such representation or warranty may relate by its terms solely to a prior date, and no Default or Event of Default shall have occurred and be continuing on the date hereof. (Sec.) 9. RATIFICATION, ETC. Except as otherwise expressly set forth herein, all terms and conditions of the Credit Agreement and the other Loan Documents are hereby ratified and confirmed and shall remain in full force and effect. Without limiting the generality of the foregoing, each of the Borrowers expressly affirms all of its obligations under each of the Loan Documents to which it is a party, including, without limitation, the Credit Agreement, as amended hereby. Nothing herein shall be construed to be an amendment or a waiver of any requirements of the Credit Agreement or of any of the other Loan Documents except as expressly set forth herein. (Sec.) 10. COUNTERPARTS. This Amendment No. 3 may be executed in any number of counterparts, which together shall constitute one instrument. (Sec.) 11. GOVERNING LAW. THIS AMENDMENT NO. 3 SHALL BE A CONTRACT UNDER THE LAWS OF THE COMMONWEALTH OF MASSACHUSETTS, SHALL FOR ALL PURPOSES BE CONSTRUED IN ACCORDANCE WITH AND GOVERNED BY THE INTERNAL LAWS OF SAID COMMONWEALTH, WITHOUT REFERENCE TO CONFLICTS OF LAW, AND IS INTENDED TO TAKE EFFECT AS A SEALED INSTRUMENT. (Sec.) 12. IMMUNITY OF INDIVIDUALS. Reference is hereby made to the Declaration of Trust establishing Eastern Enterprises, dated July 18, 1929, a copy of which has been filed with the Secretary of the Commonwealth of Massachusetts and elsewhere as required by law, and to any and all amendments thereto so filed or hereafter filed. The name "Eastern Enterprises" refers to the trustees under said Declaration of Trust, as trustees and not personally, and no trustee, shareholder, officer or agent of Eastern shall be held to any personal liability hereunder or in connection with the affairs of Eastern, but only the trust estate under said Declaration of Trust is liable under this Agreement, any Guaranty, the Notes or any other Loan Document. [REMAINDER OF PAGE INTENTIONALLY LEFT BLANK] IN WITNESS WHEREOF, the parties hereto have executed this Amendment No. 3 as an instrument under seal to be effective as of the date first above written. EASTERN ENTERPRISES By: --------------------------- Title: BOSTON GAS COMPANY By: --------------------------- Title: MIDLAND ENTERPRISES INC. By: --------------------------- Title: BANKBOSTON, N.A. (f/k/a The First National Bank of Boston), Individually and as Agent By: --------------------------- Title: THE BANK OF NOVA SCOTIA By: --------------------------- Title: FIFTH THIRD BANK By: --------------------------- Title: MELLON BANK, N.A. By: --------------------------- Title: MORGAN GUARANTY TRUST COMPANY OF NEW YORK By: --------------------------- Title: FLEET NATIONAL BANK By: --------------------------- Title: EX-13.1 9 PORTIONS INCORPORATED FROM 1999 ANNUAL REPORT Exhibit 13.1
SIX-YEAR FINANCIAL REVIEW Years ended December 31, 1999 1998 1997 1996 1995 1994 - ---------------------------------------------------------------------------------------------------------------------------------- (In thousands, except per share amounts) REVENUES: Natural gas distribution $690,809 $667,106 $ 754,481 $ 755,391 $698,123 $708,694 Marine transportation 267,269 261,061 269,259 301,880 296,339 264,692 Other services 20,624 7,097 -- -- -- -- ----------------------------------------------------------------------------- TOTAL REVENUES 978,702 935,264 1,023,740 1,057,271 994,462 973,386 OPERATING EARNINGS: Natural gas distribution 101,359 88,913 87,773 77,291 69,264 73,438 Marine transportation 21,114 26,634 34,614 58,415 57,828 35,805 Other services (2,932) (9,043) (1,481) -- -- -- Headquarters (6,102) (6,099) (5,589) (5,472) (5,756) (4,221) ----------------------------------------------------------------------------- TOTAL OPERATING EARNINGS 113,439 100,405 115,317 130,234 121,336 105,022 OTHER INCOME (EXPENSE): Interest income 7,964 7,582 8,997 9,419 5,633 1,953 Interest expense (39,136) (33,584) (37,411) (37,290) (41,273) (41,001) Other, net 8,980 5,591 (4,033) (114) 4,109 2,546 ----------------------------------------------------------------------------- EARNINGS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 91,247 79,994 82,870 102,249 89,805 68,520 Provision for income taxes 36,154 29,166 26,954 37,748 26,244 26,311 EARNINGS FROM CONTINUING OPERATIONS BEFORE EXTRAORDINARY ITEMS AND ACCOUNTING CHANGE 55,093 50,828 55,916 64,501 63,561 42,209 Discontinued operations and accounting change (1) -- 8,193 -- -- -- 12,212 Extraordinary items(2) -- 46,960 -- -- (6,500) -- ----------------------------------------------------------------------------- NET EARNINGS $ 55,093 $105,981 $ 55,916 $ 64,501 $ 57,061 $ 54,421 ----------------------------------------------------------------------------- NUMBER OF COMMON SHARES: Outstanding at year end 27,114 22,525 22,383 22,248 22,097 22,272 Diluted weighted average 24,254 22,680 22,498 22,414 22,171 22,626 DILUTED PER SHARE DATA: EARNINGS FROM CONTINUING OPERATIONS BEFORE EXTRAORDINARY ITEMS AND ACCOUNTING CHANGE(3) $2.27 $2.24 $2.49 $2.88 $2.87 $1.87 Discontinued operations and accounting change(1) -- 0.3 -- -- -- 0.54 Extraordinary items(2) -- 2.07 -- -- (0.30) -- ----------------------------------------------------------------------------- NET EARNINGS $2.27 $4.67 $2.49 $2.88 $2.57 $2.41 ============================================================================= Dividends declared $ 1.69 $ 1.65 $ 1.61 $ 1.51 $ 1.42 $ 1.40 Shareholders' equity 27.83 24.24 21.64 20.72 19.30 18.09 FINANCIAL STATISTICS AND RATIOS: Cash from operating activities $ 113,931 $ 134,256 $ 146,640 $ 128,439 $ 163,359 $ 121,885 Capital expenditures 88,117 113,712 89,216 119,783 85,352 64,014 Depreciation and amortization 81,373 75,521 71,322 67,229 64,005 61,197 Total assets 2,019,757 1,518,612 1,530,365 1,514,853 1,463,924 1,422,830 Long-term debt 515,232 385,519 371,492 367,683 379,018 387,901 Shareholders' equity 754,630 546,069 484,470 461,013 426,473 403,004 Debt/equity ratio 41/59 41/59 43/57 44/56 47/53 49/51 Return on total capital(4) 7.0% 8.0% 9.3% 10.6% 10.9% 8.5% Return on equity(4) 8.5% 9.9% 11.9% 14.6% 15.4% 10.6% - ---------------------------------------------------------------------------------------------------------------------------------- (1) Includes accounting change to adopt accrual method for unbilled revenue in 1998, and results from Water Products Group net of tax in 1994. (2) Provision (credits) for Coal Act liabilities of $(74,500) and $10,000 pre-tax in 1998 and 1995, respectively, and loss on early extinguishment of debt of $2,255 pre-tax in 1998. (3) Basic earnings per share from continuing operations before extraordinary items and accounting change were $2.28, $2.26, $2.50, $2.90, $2.88 and $1.87 for 1999 through 1994, respectively. (4) Based on earnings from continuing operations before extraordinary items and accounting change.
STOCK PRICE RANGE 1999 1998 QUARTER HIGH LOW HIGH LOW - ------- ---- --- ---- --- FIRST $45 $36 3/8 $45 5/8 $40 3/8 SECOND 40 9/16 33 1/2 44 3/4 37 5/8 THIRD 47 3/8 38 1/16 43 1/2 38 1/4 FOURTH 57 7/16 46 44 1/4 40 DIVIDENDS DECLARED PER SHARE QUARTER 1998 1997 - ------- ---- ---- FIRST $ .42 $ .41 SECOND .42 .41 THIRD .42 .41 FOURTH .43 .42 ----- ----- TOTAL $1.69 $1.65 ===== ===== EX-21.1 10 SUBSIDIARIES OF THE REGISTRANT Exhibit 21.1 SUBSIDIARIES OF THE REGISTRANT The following table shows all direct and indirect subsidiaries of the registrant except (1) subsidiaries which, considered in the aggregate as a single subsidiary, do not constitute a significant subsidiary, and (2) certain consolidated wholly-owned multiple subsidiaries carrying on the same line of business as to which certain summary information appears below: Jurisdiction of Incorporation ----------------------------- Boston Gas Company Massachusetts Colonial Gas Company Massachusetts Essex Gas Company Massachusetts Midland Enterprises Inc. Delaware Transgas Inc. Massachusetts EX-23.1 11 ACCOUNTANTS CONSENT Exhibit 23.1 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULES TO EASTERN ENTERPRISES: We have audited, in accordance with generally accepted auditing standards, the consolidated financial statements included in Eastern Enterprises Annual Report to Shareholders incorporated by reference in this Form 10-K, and have issued our report thereon dated January 21, 2000. Our audit was made for the purpose of forming an opinion on those statements taken as a whole. The schedules listed in the index on page F-1 are the responsibility of Eastern's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subject to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. /s/ Arthur Andersen Arthur Andersen LLP Boston, Massachusetts January 21, 2000 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference of our reports, dated January 21, 2000, included in, and incorporated by reference into, Eastern Enterprises Annual Report on this Form 10-K for the year ended December 31, 1999, into Eastern's previously filed Post-Effective Amendment No. 1 to Form S-16 Registration Statement No. 2-71614 on Form S-3, Form S-4 Registration Statements No. 333-69039 and No. 333-95693, and Form S-8 Registration Statements No. 2-77146, No. 33-19990, No. 33-40862, No. 33-56424, No. 33-58873 and No. 333-88967. /s/ Arthur Andersen Arthur Andersen LLP Boston, Massachusetts March 9, 2000 EX-27.1 12 FDS FOR TWELVE MONTH PERIOD ENDING 12-31-99
5 This schedule contains summary financial information extracted from the consolidated statement of earnings and the consolidated balance sheets and is qualified in its entirety by reference to such financial statements. 1,000 U.S. DOLLARS 12-MOS DEC-31-1999 JAN-01-1999 DEC-31-1999 1 44,332 0 154,269 18,860 74,555 323,807 2,197,156 906,953 2,019,757 286,771 515,232 26,454 0 27,131 727,499 2,019,757 690,809 978,702 497,887 746,162 90,188 11,969 39,136 91,247 36,154 55,093 0 0 0 55,093 2.28 2.27 EPS - Primary is EPS Basic per SFAS 128 EPS - Fully diluted is EPS - Diluted per SFAS 12
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