SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 1999 OR ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number 0-5464 (LOGO) MASSACHUSETTS ELECTRIC COMPANY (Exact name of registrant as specified in charter) MASSACHUSETTS 04-1988940 (State or other (I.R.S. Employer jurisdiction of Identification No.) incorporation or organization) 25 Research Drive, Westborough, Massachusetts 01582 (Address of principal executive offices) Registrant's telephone number, including area code (508-389-2000) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes (X) No ( ) Common stock, par value $25 per share, authorized and outstanding: 2,398,111 shares at March 31, 1999. PART I FINANCIAL INFORMATION Item 1. Financial Statements - ---------------------------- MASSACHUSETTS ELECTRIC COMPANY Statements of Income Periods Ended March 31 (Unaudited) Three Months Twelve Months ------------ ------------- 1999 1998 1999 1998 ---- ---- ---- ---- (In Thousands) Operating revenue $344,764 $396,714$1,438,467 $1,615,281 -------- ------------------ ---------- Operating expenses: Purchased electric energy: Contract termination charges from New England Power Company, an affiliate55,748 36,822 319,556 36,822 Other New England Power Company - 246,677 218,343 1,096,107 Other 147,800 83 322,807 500 Other operation 75,531 50,782 317,258 219,386 Maintenance 7,226 8,752 31,996 38,234 Depreciation 16,613 14,253 64,060 51,309 Taxes, other than income taxes 9,600 8,949 38,634 31,219 Income taxes 8,654 7,553 37,420 41,411 -------- ------------------ ---------- Total operating expenses 321,172 373,871 1,350,074 1,514,988 -------- ------------------ ---------- Operating income 23,592 22,843 88,393 100,293 Other income (expense), net (2,190) (2,878) (2,822) (2,518) -------- ------------------ ---------- Operating and other income 21,402 19,965 85,571 97,775 -------- ------------------ ---------- Interest: Interest on long-term debt 6,853 6,871 27,055 27,400 Other interest 1,911 1,419 7,860 6,891 Allowance for borrowed funds used during construction - credit (195) (136) (752) (449) -------- ------------------ ---------- Total interest 8,569 8,154 34,163 33,842 -------- ------------------ ---------- Net income $ 12,833 $ 11,811$ 51,408 $ 63,933 ======== ================== ========== Statements of Retained Earnings (In Thousands) Retained earnings at beginning of period $208,537 $201,156$ 197,139 $ 166,803 Net income 12,833 11,811 51,408 63,933 Dividends declared on cumulative preferred stock (154) (240) (787) (2,283) Dividends declared on common stock - (15,588) (26,379) (27,578) Premium on redemption of preferred stock - - (165) (3,736) -------- ------------------ ---------- Retained earnings at end of period $221,216 $197,139$ 221,216 $ 197,139 ======== ================== ========== The accompanying notes are an integral part of these financial statements. Per share data is not relevant because the Company's common stock is wholly owned by New England Electric System. MASSACHUSETTS ELECTRIC COMPANY Balance Sheets (Unaudited) March 31, December 31, ASSETS 1999 1998 ------ ---- ---- (In Thousands) Utility plant, at original cost $1,639,000 $1,626,569 Less accumulated provisions for depreciation 512,296 499,975 ---------- ---------- 1,126,704 1,126,594 Construction work in progress 19,749 16,575 ---------- ---------- Net utility plant 1,146,453 1,143,169 ---------- ---------- Current assets: Cash 8,209 6,994 Accounts receivable: From electric energy services 187,769 188,956 Other (including $3,594,000 and $6,629,000 from affiliates) 4,114 7,358 Less reserves for doubtful accounts 13,480 12,450 ---------- ---------- 178,403 183,864 Unbilled revenues 42,801 56,133 Materials and supplies, at average cost 10,395 9,281 Prepaid and other current assets 2,018 13,886 ---------- ---------- Total current assets 241,826 270,158 ---------- ---------- Deferred charges and other assets 39,022 41,235 ---------- ---------- $1,427,301 $1,454,562 ========== ========== CAPITALIZATION AND LIABILITIES ------------------------------ Capitalization: Common stock, par value $25 per share, authorized and outstanding 2,398,111 shares $ 59,953 $ 59,953 Premium on capital stock 45,942 45,942 Other paid-in capital 193,498 193,498 Retained earnings 221,216 208,537 Unrealized gain on securities, net 280 273 ---------- ---------- Total common equity 520,889 508,203 Cumulative preferred stock 10,674 10,674 Long-term debt 347,372 353,329 ---------- ---------- Total capitalization 878,935 872,206 ---------- ---------- Current liabilities: Long-term debt due in one year 21,000 15,000 Short-term debt to affiliates 37,325 80,725 Accounts payable (including $51,543,000 and $34,506,000 to affiliates) 146,634 127,621 Accrued liabilities: Taxes 6,899 - Interest 8,010 8,509 Other accrued expenses 48,423 40,626 Customer deposits 4,258 4,456 Dividends payable 155 4,951 ---------- ---------- Total current liabilities 272,704 281,888 ---------- ---------- Deferred federal and state income taxes 190,271 200,965 Unamortized investment tax credits 14,110 14,377 Other reserves and deferred credits 71,281 85,126 ---------- ---------- $1,427,301 $1,454,562 ========== ========== The accompanying notes are an integral part of these financial statements. MASSACHUSETTS ELECTRIC COMPANY Statements of Cash Flows Quarters Ended March 31 (Unaudited) 1999 1998 ---- ---- (In Thousands) Operating activities: Net income $ 12,833 $ 11,811 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation 16,613 14,253 Deferred income taxes and investment tax credits, net (10,439) 5,834 Allowance for borrowed funds used during construction (195) (136) Decrease (increase) in accounts receivable, net and unbilled revenues 18,793 (18,127) Decrease (increase) in materials and supplies (1,114) (426) Decrease (increase) in prepaid and other current assets 11,868 1,404 Increase (decrease) in accounts payable 19,013 20,343 Increase (decrease) in other current liabilities 13,999 (1,044) Other, net (12,047) 2,455 -------- -------- Net cash provided by (used in) operating activities$ 69,324 $ 36,367 -------- -------- Investing activities: Plant expenditures, excluding allowance for funds used during construction $(19,701) $(18,488) Other investing activities (58) (87) -------- -------- Net cash provided by (used in) investing activities$(19,759) $(18,575) -------- -------- Financing activities: Dividends paid on common stock $ (4,796) $ (4,796) Dividends paid on preferred stock (154) (240) Long-term debt - issues - 25,000 Long-term debt - retirements - (30,000) Changes in short-term debt (43,400) (4,400) -------- -------- Net cash provided by (used in) financing activities $(48,350) $(14,436) -------- -------- Net increase (decrease) in cash and cash equivalents $ 1,215 $ 3,356 Cash and cash equivalents at beginning of period 6,994 6,743 -------- -------- Cash and cash equivalents at end of period $ 8,209 $ 10,099 ======== ======== The accompanying notes are an integral part of these financial statements. MASSACHUSETTS ELECTRIC COMPANY Notes to Unaudited Financial Statements Note A - Hazardous Waste - ------------------------ The Federal Comprehensive Environmental Response, Compensation and Liability Act, more commonly known as the "Superfund" law, imposes strict, joint and several liability, regardless of fault, for remediation of property contaminated with hazardous substances. A number of states, including Massachusetts, have enacted similar laws. The electric utility industry typically utilizes and/or generates in its operations a range of potentially hazardous products and by- products. Massachusetts Electric Company (the Company) currently has in place an internal environmental audit program and an external waste disposal vendor audit and qualification program intended to enhance compliance with existing federal, state, and local requirements regarding the handling of potentially hazardous products and by-products. The Company has been named as a potentially responsible party (PRP) by either the United States Environmental Protection Agency or the Massachusetts Department of Environmental Protection for 16 sites at which hazardous waste is alleged to have been disposed. Private parties have also contacted or initiated legal proceedings against the Company regarding hazardous waste cleanup. The most prevalent types of hazardous waste sites with which the Company has been associated are manufactured gas locations. (Until the early 1970s, New England Electric System (NEES) was a combined electric and gas holding company system.) The Company is aware of approximately 35 such manufactured gas locations in Massachusetts. The Company has been identified as a PRP at eight of these manufactured gas locations, which are included in the 16 PRP sites discussed above. The Company has reported the existence of all manufactured gas locations of which it is aware to state environmental regulatory agencies. The Company is engaged in various phases of investigation and remediation work at 17 of the manufactured gas locations. The Company is currently aware of other possible hazardous waste sites, and may in the future become aware of additional sites, that it may be held responsible for remediating. In 1993, the Massachusetts Department of Public Utilities approved a settlement agreement that provides for rate recovery of remediation costs of former manufactured gas sites and certain other hazardous waste sites located in Massachusetts. Under that agreement, qualified costs related to these sites are paid out of a special fund established on the Company's books. Rate- recoverable contributions of $3 million, adjusted since 1993 for inflation, are added annually to the fund along with interest, lease payments, and any recoveries from insurance carriers and other third parties. At March 31, 1999, the fund had a balance of $47 million. Predicting the potential costs to investigate and remediate hazardous waste sites continues to be difficult. There are also significant uncertainties as to the portion, if any, of the investigation and remediation costs of any particular hazardous waste site that may ultimately be borne by the Company. The NEES Companies have recovered amounts from certain insurers, and, where appropriate, the Company intends to seek recovery from other insurers and from other PRPs, but it is uncertain whether, and to what extent, such efforts will be successful. At March 31, 1999, the Company had total reserves for environmental response costs of $42 million which includes reserves established in connection with the Company's hazardous waste fund referred to above. The Company believes that hazardous waste liabilities for all sites of which it is aware, and which are not covered by a rate agreement, are not material to its financial position. Note B - New Accounting Standards - --------------------------------- In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (FAS 133), which establishes accounting and reporting standards for such instruments. FAS 133 is effective for fiscal years beginning after June 15, 1999. Under the provisions of industry restructuring settlement agreements approved by state and federal regulators implemented on March 1, 1998, the Company is required to offer a default service option to those customers who, for a variety of reasons, are not purchasing power from a competitive supplier. The Company is required to procure this power supply through competitive bidding. In March 1999, the Company entered into a power supply contract with a third party to provide the physical supply of this power at a variable market rate. In May 1999, the Company entered into a eight month financial contract with another third party to convert this variable rate into a fixed rate for substantially, if not for all, of the physical supply. The Company will bill its retail customers at the fixed rate under the financial contract. Purchases under these contracts are expected to be less than $5 million per month using April 1999 service requirements. Note C - ------ In the opinion of the Company, these financial statements reflect all adjustments (which include normal recurring adjustments) necessary for a fair statement of the results of its operations for the periods presented and should be considered in conjunction with the notes to the financial statements in the Company's 1998 Annual Report. MASSACHUSETTS ELECTRIC COMPANY Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - ----------------------------------------------------------------- This section contains management's assessment of Massachusetts Electric Company's (the Company) financial condition and the principal factors having an impact on the results of operations. This discussion should be read in conjunction with the Company's financial statements and footnotes and the 1998 Annual Report on Form 10-K. Merger Agreements - ----------------- For a full discussion of New England Electric Systems' (NEES) merger agreements with The National Grid Group plc (National Grid) and Eastern Utilities Associates (EUA), see the Merger Agreements sections of the Company's Form 10-K for 1998 and the Company's 1998 Annual Report. Update of Merger Agreements with National Grid and EUA On April 9, 1999, NEES and National Grid received clearance under the Hart-Scott-Rodino (HSR) Antitrust Improvements Act of 1976, as amended. In addition, shareholders of National Grid approved the proposed merger on April 22, 1999 with 99 percent of those voting approving the merger. On May 3, 1999, NEES received the approval of more than the required majority of outstanding shares for the merger with 75 percent of outstanding shares voting in favor of the merger. Of those shares voted, in excess of 94 percent voted in favor of the merger. NEES and National Grid have also filed for merger approval with the Securities and Exchange Commission (SEC), Federal Energy Regulatory Commission (FERC), and Nuclear Regulatory Commission (NRC). NEES and National Grid have also made filings in the states in which NEES subsidiaries operate where support or approval for the merger is required. On April 21, 1999, the New Hampshire Public Utilities Commission (NHPUC) issued an order finding that the NEES/National Grid merger filing did not satisfy the requirements for exemption from the NHPUC's formal review process. Hearings on the merger are scheduled for June 1999. On April 29, 1999, the Committee on Foreign Investment in the United States under the Exon-Florio Provisions of the Omnibus Trade and Competitiveness Act of 1988 concluded there were no issues of national security to warrant any investigation. The NEES/National Grid merger is expected to be completed by early 2000. On April 29, 1999, NEES and EUA also received clearance under HSR for the NEES acquisition of EUA. NEES and EUA have filed for merger approval with the FERC and the Commonwealth of Massachusetts. The acquisition of EUA also requires approval by the SEC and NRC, and approval by certain states in which EUA subsidiaries operate. On May 17, 1999, EUA shareholders approved the acquisition of EUA by NEES. The acquisition of EUA is expected to be completed by early 2000. Impact of Mergers on Distribution Rates - --------------------------------------- On April 29, 1999, the Company and Eastern Edison Associates (Eastern Edison), a wholly owned subsidiary of EUA, filed a rate consolidation plan with the Massachusetts Department of Telecommunications and Energy, reflecting the acquisition of EUA by NEES and the merger of Eastern Edison into the Company. In the filing, the companies proposed that effective January 1, 2001, Eastern Edison's customers would pay the same delivery rates as the Company. The filing calls for an extension of the Company's distribution rate freeze through December 31, 2002. The freeze would be extended an additional two years upon completion of the NEES/National Grid merger. Industry Restructuring - ---------------------- For a full discussion of industry restructuring activities in Massachusetts, the NEES companies' divestiture of its nonnuclear generating business, stranded cost recovery, and the impact of restructuring on the distribution business, see the "Industry Restructuring" and "Impact of Restructuring on Distribution Business" sections of the Company's Form 10-K for 1998 and the Company's 1998 Annual Report. Regulatory Asset Recovery - ------------------------- Historically, electric utility rates have been based on a utility's costs. As a result, electric utilities are subject to certain accounting standards that are not applicable to other business enterprises in general. Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (FAS 71), requires regulated entities, in appropriate circumstances, to establish regulatory assets, and thereby defer the income statement impact of these charges because they are expected to be included in future customer charges. At March 31, 1999, the Company had approximately $14 million in net regulatory assets. Under existing ratemaking practices and provisions of industry restructuring settlement agreements approved by state and federal regulators (Massachusetts Settlement), the Company has the ability to recover through rates its specific costs of providing ongoing distribution services and stranded costs billed to it by NEP. The Company has believed these factors have allowed it to continue to apply FAS 71. Currently, there is much regulatory and other movement toward establishing performance-based rates. It is possible that the adoption of performance-based rates, future regulatory rules, or other circumstances could cause the application of FAS 71 to be discontinued. Absent the circumstances described in the next paragraph, this discontinuation would result in a noncash write-off of previously established regulatory assets. In addition, reserves for depreciation may also have to be increased to comply with unregulated accounting practices. In April 1999, the Company filed a rate plan which, if approved, may cause the application of FAS 71 to be discontinued upon consummation of the NEES/National Grid merger. Because the discontinuation of FAS 71 would be coincident with the completion of the NEES/National Grid merger, the regulatory assets would not be written off but instead would be reclassified to either an intangible asset account or a goodwill account. Year 2000 Readiness Disclosure - ------------------------------ Over the course of this year, most companies will face a potentially serious information systems (computer) problem because many software applications and operational programs written in the past may not properly recognize calendar dates associated with the year 2000 (Y2K). This could cause computers to either shut down or lead to incorrect calculations. During 1996, the NEES companies began the process of identifying the changes required to their computer software and hardware to mitigate Y2K issues. The NEES companies established a Y2K Project team to manage these issues, which has consisted of as many as 70 full-time equivalent staff at some points in time, primarily external consultants being overseen by an internal Y2K management team. To facilitate the Y2K Project, NEES entered into contracts with Keane, Inc. and IBM to provide personnel support to the Y2K Project. Through March 31, 1999, the NEES companies have spent approximately $17 million with these vendors, which is included in the cost figures disclosed below. The Y2K Project team reports project progress to a Y2K Executive Oversight Committee each month. The team also makes regular reports to NEES' Board of Directors and its Audit Committee. The NEES companies have separated their Y2K Project into four parts as shown below, along with the estimated completion dates for each part. Substantial Contingency Testing Completion Documentation, of Critical and Clean Category Specific Example Systems Management - -------- ---------------- ----------- ------------------- Mainframe/Midrange Accounting/Customer Completed Throughout 1999 systems service integrated systems Desktop systems Personal computers/ June 30, 1999 Throughout 1999 Department software/ Networks Operational/ Dispatching systems/ June 30, 1999 Throughout 1999 Embedded Transmission and systems Distribution systems/ Telephone systems External issues Electronic Data June 30, 1999 Throughout 1999 Interchange/Vendor communications The NEES companies are using a three-phase approach in coordinating their Y2K Project for system-related issues: (I) Assessment and Inventory, (II) Pilot Testing, and (III) Renovation, Conversion, or Replacement of Application and Operating Software Packages and Testing. Phase I, which was an initial assessment of all systems and devices for potential Y2K defects, was completed in mid-1997. These assessments included, but were not limited to, the review of program code for mainframe and midrange systems, analysis of personal computer hardware and network equipment for desktop systems, reaching consensus with key "data exchange" partners regarding the approach and execution of plans to address Y2K- related issues, and coordination with other New England Power Pool (NEPOOL) member utilities related to operational systems, such as transmission systems. Phase II, which consisted of renovation pilots for a cross-section of systems in order to facilitate the establishment of templates for Phase III work, was completed in late 1997. Phase III, which is currently ongoing, requires the renovation, conversion, or replacement of the remaining applications and operating software packages. Critical systems include major operational and informational systems such as the NEES companies' financial-related and customer information systems. These mission critical systems were first addressed at an individual component level, and then, upon satisfactory completion of that testing, reviewed at an integrated level, during which the Y2K Project team tested for Y2K problems which could be caused by various system interfaces. Additionally, contingency plans are being formulated for mission critical systems, as described below. The overall Y2K Project has also been designed such that Y2K- related work performed by external consultants is reviewed by NEES employees, and vice-versa. The Y2K Project team management periodically benchmarks its progress against the recommended progress schedule documented by the North American Electric Reliability Council (NERC), and is currently ahead of the recommended schedule. The NEES companies have also implemented a formalized communication process with third parties to give and receive information related to their progress in remediating their own Y2K issues, and to communicate the NEES companies' progress in addressing the Y2K issue. These third parties include major customers, suppliers, and significant businesses with which the NEES companies have data links (such as banks). The NEES companies have identified standard offer generation service providers, telecommunications companies, and the Independent System Operator- New England (ISO New England) as critical to business operations. The NEES companies have been in contact with all of these parties regarding the progress of their Y2K remediation efforts, and will continue to monitor their ongoing remediation efforts through continued communications. The NEES companies cannot predict the outcome of other companies' remediation efforts. Therefore, contingency plans are being developed, as described below. The NEES companies believe total costs associated with making the necessary modifications to all centralized and noncentralized systems will be approximately $28 million. These costs include the replacement of approximately one thousand desktop computers. In addition, the NEES companies are spending $7 million related to the replacement of the human resources and payroll system, in part due to the Y2K issue. As of March 31, 1999, total Y2K-related costs of approximately $30 million have been incurred, of which approximately $4 million has been capitalized. The NEES companies continually review their cost estimates based upon the overall Y2K Project status, and update these estimates as warranted. The NEES companies are in the process of developing Y2K contingency plans to allow for critical information and operating systems to function from January 1, 2000 forward. If required, these plans are intended to address both internal risks as well as potential external risks related to suppliers and customers. Part of the contingency planning for accounting and desktop systems will include taking extensive data back-ups prior to year-end closing. For operational systems, the NEES companies have in place an overall disaster recovery program, which already includes periodic disaster simulation training (for outages due to severe weather, for instance). As part of Y2K contingency planning, the NEES companies will review their disaster recovery plans, modifying them for Y2K-specific issues, such as a potential loss of telecommunication services. The NEES companies expect that these contingency plans will be in place by the third quarter of 1999. Interregional and regional contingency plans are being formulated that address emergency scenarios due to the interconnection of utility systems throughout the United States. At a regional level, the NEES companies are participating and cooperating with NEPOOL and ISO New England. Overall regional activities, including those of NEPOOL and ISO New England, will be coordinated by the Northeast Power Coordinating Council, whose activities will be incorporated into the interregional coordinating effort by NERC. The target for the completion of this planning process is mid-1999. The NEES companies have noted that the Y2K coordination efforts by ISO New England began in May 1998, resulting in a demanding and difficult schedule to attain regional and interregional target dates. The NEES companies believe that the contingency plans being developed both internally and on a regional level should substantially mitigate the risks of Y2K-related failures at NEES company facilities or those caused by the inability of entities, such as ISO New England, to maintain the short-term reliability of various generator and/or transmission lines on a regional or interregional basis. Such risks include temporary disruptions of electric service, which the NEES companies believe is the worst case Y2K scenario with a reasonable chance of occurring. In the event that a short-term disruption in service occurs, NEES does not expect that it would have a material impact on its financial position or results of operation. While the NEES companies believe that their overall Y2K program will satisfactorily address all critical operational and system-related issues, significant risks remain. These risks include, but are not limited to, the Y2K readiness of third parties, including other utilities, power suppliers, and ISO New England, cost and timeline estimates of remaining Y2K mitigation efforts, and the overall accuracy of assumptions made related to future events in the development of the Y2K mitigation effort. Earnings - -------- Net income for the first quarter of 1999 increased $1 million compared with the corresponding period in 1998. The increase is due primarily to a distribution rate increase implemented in March 1998 and increased kilowatthour (kWh) deliveries of 3.2 percent. These increases were partially offset by increased operation and maintenance expenses, depreciation expense, and property tax expense. Operating Revenue - ----------------- Operating revenue decreased $52 million in the first quarter of 1999 compared with the corresponding period in 1998 reflecting lower purchased power rates pursuant to the Massachusetts Settlement implemented in March 1998. Commencing in March 1998, the revenues that the Company was billing related to contract termination charges (CTC) from New England Power Company (NEP), purchased power costs, and transmission wheeling costs became subject to fully reconciling true-up mechanisms based on actual NEP billings. Prior to March 1998, only the fuel component of purchased power expense was subject to a similar fully reconciling true-up mechanism. The decrease in 1999 operating revenue was offset by a $41 million distribution rate increase in accordance with the Massachusetts Settlement, as well as a 3.2 percent increase in kWh deliveries as a result of a continued strong economy and the effect of weather. Operating Expenses - ------------------ Operating expenses for the first quarter of 1999 decreased $53 million compared with the corresponding period in 1998, primarily due to reduced purchased electric energy expenses. The decrease in purchased electric energy due to the lower rates from power suppliers is partially offset by the implementation of CTC billing from NEP which commenced in March 1998. The decrease is also partially offset by increased operation and maintenance costs, increased depreciation expense, and increased property tax expense. The decrease in purchased electric energy is principally due to reduced rates billed to the Company by suppliers. Historically, the Company purchased all of its electrical requirements from NEP under the provisions of an all-requirements contract at NEP's standard resale rate. Effective March 1, 1998, the contract was amended, terminating the all-requirements provision of the contract and resulting in CTCs, the fixed portion of which the Company will pay monthly to NEP through the end of 2000. The Company's customers also gained the right to choose their power supplier. NEP continued to supply power to the Company, at lower rates, for customers that continued to take power from the Company, until September 1, 1998, when USGen New England, Inc., an indirect wholly owned subsidiary of PG&E Corporation, and TransCanada Power Marketing, Ltd. became the Company's principal wholesale power suppliers. The increase in other operation and maintenance expenses is primarily due to increased transmission billings from NEP of approximately $22 million which, prior to March 1, 1998, were a component of purchased power expense. These transmission expenses are included as part of the transmission true-up mechanism as discussed in the "Operating Revenue" section. The increase in operation and maintenance expenses is also due to costs associated with year 2000 computer readiness allocated to the Company and increased healthcare costs. The increase in depreciation expense in the first quarter of 1999 primarily reflects a portion of the $11 million increase in annual depreciation expense provided for in the Massachusetts Settlement, which went into effect on March 1, 1998, and depreciation expense on new utility plant expenditures. Other Income - ------------ The increase in other income reflects the impact of a $1.3 million write-off of loss on reacquired debt in the first quarter of 1998. Utility Plant Expenditures and Financing - ---------------------------------------- Cash expenditures for utility plant totaled $20 million for the first three months of 1999. The funds necessary for utility plant expenditures during the period were primarily provided by net cash from operating activities, after the payment of dividends. At March 31, 1999, the Company had $37 million of short-term debt outstanding representing borrowings from affiliates. The Company's ability to issue short-term debt is limited by the need to obtain regulatory approval from the SEC under the Public Utility Holding Company Act of 1935. Approval has been granted for up to $150 million. At March 31, 1999, the Company had lines of credit with banks totaling $55 million which are available to provide liquidity support for commercial paper borrowings and other corporate purposes. There were no borrowings under these lines of credit at March 31, 1999. For the twelve-month period ending March 31, 1999, the ratio of earnings to fixed charges was 3.52. PART II. OTHER INFORMATION Item 1. Legal Proceedings - -------------------------- Information concerning a rate filing by the Company with the Massachusetts Department of Telecommunications and Energy on April 30, 1999, discussed in Part I of this report in Management's Discussion and Analysis of Financial Condition and Results of Operations, is incorporated herein by reference and made a part hereof. Item 4. Submission of Matters to a Vote of Security-Holders - ------------------------------------------------------------ On March 17, 1999, the Annual Meeting of Stockholders was held. The following actions were taken by the unanimous vote of the 2,398,111 shares having general voting rights represented at the meeting: The number of directors was fixed at seven. The following were elected as directors of the Company: Cheryl A. LaFleur Robert L. McCabe Lydia M. Pastuszek Lawrence J. Reilly Christopher E. Root Nancy H. Sala Richard P. Sergel John G. Cochrane was elected Treasurer and Geraldine M. Zipser was elected Clerk. PricewaterhouseCoopers was selected as auditor for 1999. Item 6. Exhibits and Reports on Form 8-K - ----------------------------------------- The Company is filing the following revised exhibit for incorporation by reference into its registration statement on Form S-3, Commission File No. 33-59145. 12 Statement re computation of ratios The Company is filing Financial Data Schedules. The Company filed reports on Form 8-K dated February 1, 1999, and March 31, 1999, containing Items 5 and 7 and Item 7, respectively. SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report on Form 10-Q for the quarter ended March 31, 1999 to be signed on its behalf by the undersigned thereunto duly authorized. MASSACHUSETTS ELECTRIC COMPANY s/John G. Cochrane John G. Cochrane, Treasurer, Authorized Officer, and Principal Financial Officer Date: May 17, 1999