-----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, H8cbuO0ToNlko6bH9NwXIc2klF3yIHHPcGPJ/eaR4nwi+ZjM39Ny4IzNR/SZDkeP CHJ6wqZLChjQCw9WJsGfhQ== 0000012473-99-000002.txt : 19990816 0000012473-99-000002.hdr.sgml : 19990816 ACCESSION NUMBER: 0000012473-99-000002 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19990630 FILED AS OF DATE: 19990813 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BLACKSTONE VALLEY ELECTRIC CO CENTRAL INDEX KEY: 0000012473 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 050108587 STATE OF INCORPORATION: RI FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 000-02602 FILM NUMBER: 99688470 BUSINESS ADDRESS: STREET 1: WASHINGTON HWY STREET 2: P O BOX 111 CITY: LINCOLN STATE: RI ZIP: 02865 BUSINESS PHONE: 617-352-95 MAIL ADDRESS: STREET 1: P O BOX 111 STREET 2: WASHINGTON HIGHWAY CITY: LINCOLN STATE: RI ZIP: 02865 FORMER COMPANY: FORMER CONFORMED NAME: BLACKSTONE VALLEY GAS & ELECTRIC CO DATE OF NAME CHANGE: 19600201 10-Q 1 BVE 2ND QUARTER 1999 10Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (Mark one) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 1999 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period _________________ to ___________________ Commission File Number 0-2602 BLACKSTONE VALLEY ELECTRIC COMPANY (Exact name of registrant as specified in its charter) Rhode Island 05-0108587 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 750 W. Center Street, West Bridgewater, Massachusetts (Address of principal executive offices) 02379 (Zip Code) (508) 559-1000 (Registrant's telephone number including area code) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes....X......No.......... Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practical date. Class Outstanding at July 31, 1999 Common Shares, $50 par value 184,062 shares PART I - FINANCIAL INFORMATION Item 1. Financial Statements BLACKSTONE VALLEY ELECTRIC COMPANY CONDENSED BALANCE SHEETS (In Thousands)
June 30, December 31, ASSETS 1999 1998 Utility Plant in Service $ 140,940 $ 144,120 Less: Accumulated Provision for Depreciation and Amortization 61,901 60,534 Net Utility Plant in Service 79,039 83,586 Construction Work in Progress 2,672 2,065 Net Utility Plant 81,711 85,651 Current Assets: Cash and Temporary Cash Investments 521 178 Accounts Receivable - Associated Companies 334 169 - Other - Net 15,632 17,498 Materials, Supplies and Other Current Assets 1,329 1,286 Total Current Assets 17,816 19,131 Deferred Debits and Other Non-Current Assets 31,911 29,363 Total Assets $ 131,438 $ 134,145 0 LIABILITIES AND CAPITALIZATION Capitalization: Common Stock, $50 Par Value $ 9,203 $ 9,203 Other Paid-In Capital 17,908 17,908 Retained Earnings 14,118 14,547 Total Common Equity 41,229 41,658 Non-Redeemable Preferred Stock 6,130 6,130 Long-Term Debt - Net 32,000 32,000 Total Capitalization 79,359 79,788 Current Liabilities: Current Maturities of Long-Term Debt 1,500 1,500 Notes Payable 750 Accounts Payable - Associated Companies 8,939 13,642 - Other 1,741 684 Taxes Accrued 1,558 1,493 Interest Accrued 706 779 Other Current Liabilities 4,670 5,276 Total Current Liabilities 19,864 23,374 Accumulated Deferred Taxes, Deferred Credits and Other Non-Current Liabilities 32,215 30,983 Total Liabilities and Capitalization $ 131,438 $ 134,145 See accompanying notes to condensed financial statements.
BLACKSTONE VALLEY ELECTRIC COMPANY CONDENSED STATEMENTS OF INCOME (In Thousands)
Three Months Ended Six Months Ended June 30, June 30, 1999 1998 1999 1998 Operating Revenues $ 28,965 $ 30,965 $ 62,199 $ 62,146 Operating Expenses: Purchased Power (principally from an affiliate) 16,698 19,551 37,635 38,615 Other Operation and Maintenance 5,888 5,495 11,681 10,811 Depreciation 1,665 1,585 3,307 3,124 Taxes - Other Than Income 1,813 1,820 3,886 3,634 Income Taxes - Current 1,205 402 1,682 16 - Deferred (Credit) (410) 205 (114) 1,577 Total 26,859 29,058 58,077 57,777 Operating Income 2,106 1,907 4,122 4,369 Other Income (Deductions) - Net (31) (38) (80) (81) Income Before Interest Charges 2,075 1,869 4,042 4,288 Interest Charges: Interest on Long-Term Debt 734 777 1,460 1,546 Other Interest Expense 201 215 407 444 Allowance for Borrowed Funds Used During Construction (Credit) (19) (30) (47) (50) Net Interest Charges 916 962 1,820 1,940 Net Income 1,159 907 2,222 2,348 Preferred Dividend Requirements 73 72 145 144 Net Earnings $ 1,086 $ 835 $ 2,077 $ 2,204 See accompanying notes to condensed financial statements.
BLACKSTONE VALLEY ELECTRIC COMPANY CONDENSED STATEMENTS OF CASH FLOWS (In Thousands)
Six Months Ended June 30, 1999 1998 CASH FLOW FROM OPERATING ACTIVITIES: Net Income $ 2,222 $ 2,348 Adjustments to Reconcile Net Income to Net Cash Provided from Operating Activities: Depreciation and Amortization 3,476 3,396 Deferred Taxes (115) 1,577 Investment Tax Credit, Net (88) (89) Other - Net 684 (1,069) Change in Operating Assets and Liabilities (2,600) (7,036) Net Cash Provided From Operating Activities 3,579 (873) CASH FLOW FROM INVESTING ACTIVITIES: Construction Expenditures (1,585) (2,690) Proceeds from Divestiture of Generation Assets 250 Net Cash (Used In) Investing Activities (1,335) (2,690) CASH FLOW FROM FINANCING ACTIVITIES: Common Stock Dividends Paid to EUA (2,507) (699) Preferred Dividends Paid (144) (144) Net Increase in Short-Term Debt 750 4,720 Net Cash (Used In) Provided From Financing Activities (1,901) 3,877 Net Increase in Cash and Temporary Cash Investments 343 314 Cash and Temporary Cash Investments at Beginning of Period 178 408 Cash and Temporary Cash Investments at End of Period $ 521 $ 722 Supplemental disclosures of cash flow information: Cash paid during the period for: Interest (Net of Amount Capitalized) $ 1,455 $ 1,610 Income Taxes $ 580 $ 920 See accompanying notes to condensed financial statements.
BLACKSTONE VALLEY ELECTRIC COMPANY NOTES TO CONDENSED FINANCIAL STATEMENTS The accompanying Notes should be read in conjunction with the Notes to Financial Statements appearing in Blackstone Valley Electric Company's (Blackstone or the Company) 1998 Annual Report on Form 10-K and the Company's Quarterly Report on Form 10-Q for the period ended March 31, 1999. Note A - In the opinion of the Company, the accompanying unaudited condensed financial statements contain all normal and recurring adjustments necessary to present fairly the financial position of the Company as of June 30, 1999 and December 31, 1998, and the results of operations for the three and six months ended June 30, 1999 and 1998 and cash flows for the six months ended June 30, 1999 and 1998. The year-end condensed balance sheet data was derived from audited financial statements but does not include all disclosures required under generally accepted accounting principles. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. In June 1998, the Financial Accounting Standards Board issued SFAS133, "Accounting for Derivative Instruments and Hedging Activities," which is effective in fiscal year 2001. This statement requires the recognition of all derivative instruments as either assets or liabilities in the statement of financial position and the measurement of those instruments at fair value. The Company does not expect SFAS133 to have a material impact on its financial position or results of operations. Note B - Results shown for the respective interim periods being reported herein are not necessarily indicative of results to be expected for the fiscal years due to seasonal factors which are inherent in electric utilities in New England. A greater proportionate amount of revenues is earned in the first and fourth quarters (winter season) of each year because more electricity is sold due to weather conditions, fewer daylight hours, etc. Note C - Commitments and Contingencies: Environmental Matters EUA recently identified new sites related to the production of manufactured gas at which pre-existing environmental conditions may exist. Three sites are associated with Blackstone; a manufactured gas plant was located at High Street in Central Falls, and two remote gas holders were located at Exchange Street in Pawtucket, and Pond Street in Woonsocket, all in Rhode Island. Each of these sites were built in the 1800's and ceased operations early this century. EUA may have joint and several liability for investigation and remediation at these sites, if such actions are necessary. EUA is currently conducting a preliminary assessment of the potential costs of remediation and therefore, has not yet provided for this potential liability. Blackstone is currently recovering certain environmental cleanup costs in rates. In addition, the Company will seek recovery of certain costs from its insurance carriers and other possible responsible parties. As a result, the Company does not believe that the ultimate impact of the cleanup costs associated with these additional environmental sites will be material to its results of operation or its financial position. Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations The following is Management's discussion and analysis of certain significant factors affecting the Company's earnings and financial condition for the interim periods presented in this Form 10-Q. Merger Update On February 1, 1999, EUA and New England Electric System (NEES) announced a merger agreement under which NEES will acquire all outstanding shares of EUA for $31 per share in cash. The merger agreement, which is subject to the approval of EUA shareholders and various regulatory agencies, values the equity of EUA at approximately $634 million, which represents a 23% premium above the price of EUA shares on December 4, 1998, the last trading day before other regional merger announcements affected EUA's share price. EUA shareholders will continue to receive dividends at the current level, as declared by the Board of Trustees, until the closing of the merger. EUA and NEES expect that the merger will be finalized by early 2000, but are trying to accomplish it earlier. At EUA's Annual Meeting of Shareholders on May 17, 1999, EUA shareholders voted to approve EUA's merger with NEES. At the meeting, 97% of the votes received were in favor of the merger. On May 5, 1999, EUA and NEES filed a joint application with the Federal Energy Regulatory Commission (FERC) seeking FERC approval and related waivers or authorizations to merge EUA and NEES and to subsequently merge and consolidate the complimentary operating companies of EUA and NEES. On May 20, 1999, EUA and NEES jointly filed a rate consolidation plan with the Rhode Island Public Utilities Commission reflecting consolidated rates for each company's Rhode Island subsidiaries, indicating savings to Rhode Island customers of approximately $79 million. A similar filing was made for EUA's and NEES's Massachusetts subsidiaries on April 30, 1999 with the Massachusetts Department of Telecommunications and Energy indicating savings of over $100 million. As part of the merger process, on July 19, 1999, a Voluntary Early Retirement Program was offered to certain of EUA's and NEES's union and non- union employees who are least fifty-five years of age. In addition, information on the Limited Hardship Early Decision Option (LHEDO) to be offered in September 1999, the employees' voluntary severance package and relocation assistance for those employees who qualify have also been announced. Overview Net Earnings for the three months ended June 30, 1999 were $1.1 million as compared to $835,000 for the same period in 1998, an increase of 30.1%. Net earnings for the six months ended June 30, 1999 were $2.1 million versus $2.2 million for the six months ended June 30, 1998, a decrease of 5.8%. Kilowatthour Sales Kilowatthour (kWh) sales increased 1.4% in the second quarter and 3.2% in the year-to-date period of 1999 as compared to the same periods of 1998, largely due to warmer weather in 1999, particularly in the month of June. Sales to residential customers increased 3.3% and 7.4% in the respective periods, and sales to commercial customers increased 4.7% and 6.6% in the respective periods as compared to 1998. Operating Revenues Operating Revenues for the three months ended June 30, 1999 decreased by $2.0 million or 6.5% as compared to the same period of 1998, while revenues for the six month period ended June 30, 1999 were relatively unchanged as compared to the same period in 1998. These changes were due primarily to a reduction in wholesale contract termination charge rates, partially offset by increased standard offer rates, effective April 1, 1999 and January 1, 1999 respectively, pursuant to restructuring settlement agreements. Additional offsets to these changes were the impacts of an approximate 1.4% increase in kWh sales in the second quarter and a 3.2% increase in year-to-date kWh sales. Operating Expenses Purchased Power expense for the quarter and six months ended June 30, 1999 decreased by approximately $2.9 million or 14.6% and approximately $1.0 million or 2.5%, respectively, as compared to the same periods in 1998. These decreases were primarily due to decreased generation-related expenses as a result of a decrease in the wholesale contract termination charge rate, offset by increased kWh sales and an increase in the wholesale standard offer rate. Other Operation and Maintenance (O&M) expenses increased approximately $400,000, or 7.2%, and approximately $900,000 or 8.1% in the second quarter and year-to-date period of 1999, respectively, as compared to the same periods of 1998. The increase in the second quarter was due to increased conservation and load management (C&LM) expenses and the allocation of increased expenses from EUA's Service Corporation. The year-to-date increase was due to adjustments to 1998 employee incentive plan accruals recorded in the first quarter of 1999 and increased C&LM expenses of approximately $200,000. Income Taxes Blackstone's effective income tax rate for the six months ended June 30, 1999 increased from approximately 40.2% to 41.1%, when compared with the same period of a year ago. This increase was primarily due to reduced plant-related tax benefits. Liquidity and Sources of Capital Blackstone's need for permanent capital is primarily related to investments in facilities required to meet the needs of its existing and future customers. Traditionally, construction requirements in excess of internally generated funds are financed through short-term borrowings which are ultimately funded with permanent capital. In July 1997, several EUA System companies, including Blackstone, entered into a three-year revolving credit agreement allowing for borrowings in aggregate of up to $145 million from all sources of short-term credit. As of June 30, 1999, various financial institutions have committed up to $75 million under the revolving credit facility. In addition to the $75 million available under the revolving credit facility, EUA System companies maintain short-term lines of credit with various banks totaling $90 million for an aggregate amount available of $165 million. At June 30, 1999, these unused EUA System short-term lines of credit amounted to approximately $113.5 million. Blackstone had $750,000 of short-term debt at June 30, 1999. During the first six months of 1999 Blackstone's internally generated funds available after the payment of dividends amounted to approximately $3.0 million, while cash construction requirements for the same period amounted to approximately $1.6 million. Electric Utility Industry Restructuring Legislation enacted in Rhode Island in 1996 and Massachusetts in 1997 along with approved electric utility industry restructuring settlement agreements in both states and at the federal level, granted EUA's Rhode Island and Massachusetts electric customers with choice of electricity supplier and rate reductions commencing January 1, 1998 and March 1, 1998, respectively. Until a customer chooses an alternative supplier, that customer will receive standard offer service from the retail distribution company. Blackstone and Newport are required to arrange for standard offer service through December 31, 2009 and Eastern Edison must arrange for this service through February 28, 2005. Under the approved settlement agreements, Montaup had guaranteed standard offer supply at a fixed price schedule for the duration of the standard offer periods and Blackstone, Newport and Eastern Edison agreed to subject their standard offer requirements to a competitive bidding process in which competitive suppliers would bid against the guaranteed price. Through its successful divestiture process, combined with a competitive bidding process conducted in late 1998, Montaup has assigned 100% of its standard offer obligation. A majority of this standard offer assignment became effective January 1, 1999 with the remainder to be effective with the closing of the transfer of power purchase agreements to Constellation Power Source Inc. (Constellation), see Generation Divestiture below. The guaranteed standard offer price will increase over time to encourage customers to leave standard offer service and enter the competitive power supply market. Provisions of the approved settlement agreements also allowed Montaup to replace its all-requirements wholesale contracts with its affiliated retail distribution companies with a contract termination charge (CTC) which permits Montaup to recover, among other things, its above market investments and commitments in generation assets along with an 80% ratepayer/20% shareholder sharing mechanism for ongoing nuclear generation operations. Montaup began billing the CTC coincident with retail access and the distribution companies are recovering the CTC through a non-bypassable transition charge to all of their distribution customers. As part of the approved settlement agreements, Montaup agreed to divest its entire generation portfolio. The net proceeds of the sale, as defined in the settlement agreements, will be used to mitigate Montaup's CTC to its retail affiliates via a Residual Value Credit (RVC). The RVC reduces the fixed component of the CTC by an amount equal to the net proceeds, with a return, over the period commencing on the date the RVC is implemented through December 31, 2009. Effective April 1, 1999, subject to dispute resolution procedures pursuant to restructuring settlement agreements, Montaup reduced its CTC to its retail subsidiaries to reflect the RVC and other adjustments. Montaup lowered its CTC billed to Blackstone from 3.0 cents per kWh to 2.04 cents per kWh. Blackstone's retail transition charge decrease to reflect this change was authorized by the RIPUC effective May 1, 1999. Effective January 1, 1999 the standard offer service rate for Blackstone customers was increased from an average 3.2 cents per kilowatthour to an average 3.5 cents per kilowatthour. Coincident with the May 1, 1999 reduction in Blackstone's retail transition charge, the standard offer rate was changed to a flat rate of 3.5 cents per kilowatthour for all customer classes. Generation Divestiture By the end of 1998, pursuant to settlement agreements approved by federal and state regulators, Montaup has signed agreements to sell all of its non- nuclear power generation assets and power purchase agreements to various non- affiliated parties in connection with electric utility restructuring undertaken in Massachusetts and Rhode Island. At the end of 1998, Montaup sold several diesel-powered generating units (totaling approximately 16 mw) owned by Newport to Illinois-based Wabash Power Equipment Company and its 50% share (approximately 280 mw) of Unit 2 of the Canal generating station in Sandwich, Massachusetts to Southern Energy Canal, LLC an indirect subsidiary of The Southern Company, for approximately $75 million. On April 7, 1998, Montaup entered into an agreement to transfer power purchase contracts for approximately 170 mw of output from Ocean State Power I and Ocean State Power II to TransCanada Power Marketing Ltd., an indirect subsidiary of TransCanada Pipelines Limited; the transfer was effective June 1, 1999. On December 21, 1998, Montaup entered into an agreement to transfer purchase power contracts totaling approximately 177 mw to Constellation Power Source, Inc., a wholly- owned affiliate of the Baltimore Gas and Electric Company; the transfer will become effective on September 1, 1999. On April 26, 1999, Montaup completed the sale of its 170 mw Somerset Generating Station, located in Somerset, Massachusetts, to Somerset Power, LLC, a direct subsidiary of NRG, Inc., for approximately $55 million. In June of 1999, Montaup completed the sale of its and Newport's combined 2.6% (approximately 16 mw) share of the W.F. Wyman Unit 4 in Yarmouth, Maine to FPL Energy Wyman IV LLC, an indirect subsidiary of the Florida-based FPL Group, Inc for $2.4 million. Also in June of 1999, Blackstone sold its hydroelectric facility in Pawtucket, Rhode Island (approximately 1 mw) to Putnam Hydropower LLC, an affiliate of Pawtucket Hydropower Inc. In July 1999, in connection with Entergy Nuclear Generation Company's acquisition of Pilgrim Station from Boston, Edison, Montaup bought out its power purchase agreement (approximately 73 mw) with Boston Edison. As a condition of the buy-out, Montaup entered into a reduced term power purchase contract for Pilgrim Station power with Entergy Nuclear Generation Company. Montaup also has agreed to sell its ownership interest in the Seabrook Station nuclear power plant to Great Bay Power Corporation, a subsidiary of BayCorp Holdings, Ltd., with an expected closing later in 1999. EUA's remaining generating capacity comprises 58 mw from its ownership shares of the Millstone 3 and Vermont Yankee nuclear facilities. EUA is in negotiations to sell and/or transfer its interests in the Vermont Yankee facility, (see "Note C - -Commitments and Contingencies: Nuclear Ownership Issues") and ultimately intends to sell and/or transfer its interests in Millstone 3 as well. All of the sale and contract transfer agreements are subject to federal and/or state regulatory approvals, including that of the NRC with respect to the sale of nuclear units. The Year 2000 Issues EUA is addressing the Year 2000 issue on an EUA System basis, which includes Blackstone. EUA has reached a notable milestone with its Year 2000 Program (Program). On June 30, 1999, EUA reported to the North American Electric Reliability Council (NERC) that all of its mission critical systems were Year 2000 ready, consistent with the recommended industry schedule published by NERC. The Program addressed the potential impact on computer systems and embedded systems and components resulting from a common software program code convention that utilized two digits instead of four to represent a year. If not addressed, the year 2000 could have been systemically recognized as the year 1900, causing system or equipment failures or malfunctions, and ultimately resulting in disruptions to Company operations. This disclosure constitutes a Year 2000 Statement and Readiness Disclosure. It is subject to the protections afforded it as such by the Year 2000 Information and Readiness Disclosure Act of 1998. EUA's State of Readiness: To address potential Year 2000 issues, EUA divided the focus of its Year 2000 Program into three major categories of business activity: the generation and delivery of electricity to customers, the acquisition of goods and services (including purchased power), and ongoing general and administrative activities related to the corporate infrastructure and support functions, which included among other things, billings and collections. Based on work completed as of December 31, 1998, the following types and quantities of date sensitive IT systems were identified and remediated: > Central Applications: 54 date sensitive items consisting of centralized computing software that addressed major business and operational needs were identified; 67% required repair or replacement. > Server Based Networks: 22 date sensitive items consisting of networked applications, as well as supporting computing and communications equipment were identified; 55% required repair or replacement. > Desktops: 48 categories of items typically consisting of personal computer hardware and software were identified; 52% of such categories required repair or replacement. > Infrastructure: 44 items consisting of components of central IT operations (e.g., the mainframe computer, its operating system and centralized database) were identified; 57% required repair or replacement. > Embedded Systems and Components: 3,977 items were identified; 96.3% were year 2000 ready or inert. 3.7% were tested -- none failed. EUA utilized a four phase approach to address information technology (IT) issues. The four phases were: Analysis, Remediation, Unit Testing and Integration Testing. The Analysis phase consisted of two stages. The first stage consisted of conducting an inventory of all products, applications and systems, department by department. The second stage consisted of an assessment of the risk (potential impact and likelihood of failure) of each item identified in the inventory. Items identified as not being Year 2000 ready were repaired or replaced during the Remediation phase. The Unit Testing phase involved testing at the module, program and application level to assure that each such item functioned properly after repair or replacement. Finally, in the Integration Testing phase, dates were moved ahead, data were aged, and all date conditions pertinent to each application or product were tested "end-to-end" to assure that each item was tested in its final complete environment. As of June 30, 1999, each phase described above was 100% completed and all mission critical systems were Year 2000 ready. All mission critical non-information services systems (i.e., embedded systems and components) were also 100% Year 2000 ready as of that date as well. EUA developed a process to identify and assess the Year 2000 readiness of third parties with which it had a material relationship. First, a list of all vendors utilized over the prior two years was developed from the accounts payable system. Sub-lists were then developed and distributed to departments based on the departmental allocation of charges for goods and services. Departmental managements worked with the purchasing department to rank vendors identified as being critical or important. All vendors, regardless of rank, were contacted in writing requesting information regarding their Year 2000 status. Vendors ranked as critical or important were selected for additional inquiry, in the form of additional written inquiry and telephone inquiries. If available, vendor literature, regulatory filings and web sites were also reviewed. Critical vendors included providers of a variety of goods and services, such as telecommunications, banking and other financial services, computer products and services, equipment, fuel and mail delivery. As a result of this process, the purchasing department and/or the department(s) utilizing the goods or services in question have been able to confirm to their satisfaction that all mission critical vendors and a significant majority of the important vendors have provided adequate evidence of their Year 2000 readiness. All remaining vendors are being monitored as the process of gathering their Year 2000 readiness information continues. This process was essentially complete on June 30, 1999. Contingency plans have been developed for services provided by all mission critical vendors. These plans identify workarounds for any mission critical vendor for which there is not an alternative source. Costs to Address EUA's Year 2000 Issues: Through June 30, 1999, EUA has incurred costs of approximately $6.4 million to address Year 2000 issues, including approximately $3.9 million of non-incremental labor, $1.2 million of capital expenditures and $1.3 million of consulting and other costs. The company estimates it will incur additional costs approximating $3.6 million during the period July 1, 1999 through March 31, 2000, to complete its Year 2000 Program including approximately $2.5 million of non-incremental labor, $500,000 of capital expenditures and $600,000 of consulting and other costs. Risks of EUA's Year 2000 Issues: EUA's first priority continues to be the minimization of any potential disruptions to electric service as a result of the Year 2000. The provision of electric service depends in large part on the viability of the New England power grid which is managed by ISO/NEPOOL. EUA is actively participating on ISO/NEPOOL's Year 2000 operating and oversight committees. EUA's assessment of its own transmission and distribution equipment and facilities indicated that the risk of failure of this equipment does not appear to be significant. However, due to the interconnectivity to the New England power grid, and the reliance on many other entities also connected to the grid, it is not possible to conclude with certainty that there will be no significant interruptions in service. In addition, dependable voice and data telecommunications are critical to EUA's ongoing operations. EUA's internal telecommunication systems were Year 2000 ready as of June 30, 1999. EUA also relies heavily on external telecommunication systems, i.e., the local and regional telephone systems, and has identified these providers as critical vendors. EUA has gathered extensive documentation regarding the Year 2000 efforts and status of the regional telephone companies upon which it relies. In addition, EUA has also had face- to-face meetings with representatives of these companies and attended public conferences sponsored by these companies, at which they have described their Year 2000 process and progress. Each of these companies anticipates being Year 2000 ready and devoid of major system failures. Nevertheless, EUA has provided for several methods for maintaining adequate communications. For example, if the regional, land-line telephone systems were not in service, EUA could rely on mobile or cellular telephones. If those failed, EUA maintains mobile radios. Further, all of EUA's operating locations, including EUA Service Corporation's, are linked through a captive microwave telecommunications system. No other significant reasonably likely failure scenarios stemming solely from problems relating to Year 2000 have been identified thus far. Accordingly, EUA does not currently believe that any Year 2000 related risks in and of themselves constitute reasonably likely worst case scenarios. Rather, EUA's most reasonably likely Year 2000 related worst case scenario would be the occurrence of isolated year 2000 failures such as described above in conjunction with a severe winter storm. However, EUA believes that such year 2000 failures would not likely affect whether the storm event would have a material impact on EUA's business or financial condition. In this context, and based on its communications with key vendors and customers and its long experience with storm events, EUA does not currently anticipate significant adverse effects on its relationships with its customers or vendors, or any resulting material adverse effects on its business or operations. Year 2000 Contingency Plans: Contingency planning teams consisting of managers and employees experienced in system reliability, disaster recovery and risk were established and made responsible for developing contingency plans. The overall strategy was to identify Year 2000 risks, both internal and external to EUA, that could have a material impact on EUA's operations or financial well being. For such risks, formal, written contingency plans were created. Preliminary plans were developed in March, 1999 and final contingency plans were in place and ready to implement as of June 30, 1999. In addition to the contingency plans described above which are designed to ensure a rapid recovery from any Year 2000 related failures, EUA has also developed a formal, written Implementation Plan. The purpose of this plan is to ensure that the activities necessary to maintain a clean systems environment from July 1, 1999 through the transition weekend and into the year 2000 are properly planned for, appropriately communicated throughout the company, and understood by those responsible for performing the various tasks. The Implementation Plan was completed and in place as of June 30, 1999. Summary: The amount of effort and resources necessary to address Year 2000 issues and make EUA Year 2000 ready has been significant. There are currently dedicated teams in place, guided by a formal implementation plan, to ensure EUA remains Year 2000 ready through the remainder of 1999 and into the next century. EUA's Year 2000 program has consistently been on schedule and in accordance with timetables and progress points published by the North American Electric Reliability Council (NERC). This effort culminated with the June 30, 1999 reporting to NERC that EUA had achieved 100% Year 2000 readiness for all mission critical systems and embedded components. EUA has utilized independent, outside technical consultants and other experts to review and assess its Year 2000 efforts and status throughout the project. Their findings have validated the progress and status of the company's Year 2000 project and the achievement of Year 2000 readiness. Management is confident that EUA's Year 2000 project has been, and continues to be, well managed with the appropriate resources and plans in place to ensure the Company remains Year 2000 ready and positioned for a successful transition to the Year 2000. Other Blackstone occasionally makes forward-looking projections of expected future performance or statements of our plans and objectives. These forward- looking statements may be contained in filings with the SEC, press releases and oral statements. This report contains information about the Company's future business prospects including, without limitation, statements about the potential impact of Year 2000 issues on the Company's financial condition or results. These statements are considered "forward-looking" within the meaning of the Private Securities Litigation Reform Act. These statements are based on the Company's current plans and expectations and involve risks and uncertainties that could cause actual future activities and results of operations to be materially different from those set forth in the forward- looking statements. The Company expressly undertakes no duty to update any forward-looking statement. Item 4. Submission of Matters to a Vote of Security Holders. (a) A Consent to Action in Lieu of Annual Meeting of Stockholders (Consent to Action) was executed April 21, 1999 by Eastern Utilities Associates, the holder of the entire issued and outstanding Common Stock of the Company and the only class of stock entitled to vote at the Annual Meeting of Stockholders. (b) The Board of Directors as previously reported to the Securities and Exchange Commission was re-elected in its entirety. (c) The only matter voted on in the Consent to Action was the election of directors. Item 5. Other Information NEPOOL is a voluntary organization open to any person engaged in the electric business such as investor-owned utilities, municipals, cooperative utilities, power marketers, brokers and load aggregators. On December 31, 1996, NEPOOL, on behalf of its participants, filed a restructuring proposal with FERC. The NEPOOL restructuring proposal was the product of over two years of intense discussions, deliberations and negotiations among the over 130 NEPOOL member participants and many non-participants, including New England state regulators. The key elements of the restructuring proposal were the implementation of a regional NEPOOL Open Access Transmission Tariff (NEPOOL Tariff), the creation of an Independent System Operator (ISO), and the restatement of the NEPOOL Agreement to establish a broader governance structure for NEPOOL and to develop a more open competitive market structure. The NEPOOL Tariff, which became effective on March 1, 1997, ensures non- discriminatory open access to the regional transmission network by providing a single rate for all transactions that utilize NEPOOL's bulk power transmission facilities. The NEPOOL Tariff promotes competition in the New England power market through its single transmission rate structure. All regional service within NEPOOL, except for wheeling through or out, is to be provided as a network service. On June 25, 1997, FERC issued an order conditionally authorizing the establishment of an ISO by NEPOOL effective July 1, 1997, affirming that the transfer of control of transmission facilities owned by the public utility members of NEPOOL to the ISO is consistent with the public interest under Section 203 of the Federal Power Act. On April 20, 1998, FERC accepted the NEPOOL Tariff conditional on NEPOOL's compliance with a number of issues raised by FERC. On July 22, 1998, NEPOOL made its compliance filing at FERC. The NEPOOL Tariff changes and amendments to the Restated NEPOOL Agreement included in the filing effected compliance with the Commission's April 20, 1998 Order. While there were a large number of changes in the filing, the principal areas of change relate to the addition in the NEPOOL Tariff of a separately available Internal Point to Point Service, the addition of a mechanism to allocate costs to update the regional transmission system, and the replacement of a Non-Use Charge with an In-Service Charge across interconnections. A settlement agreement was filed on April 7, 1999 and an order accepting the settlement was received on July 30, 1999 with a compliance filing due in sixty days. To give market participants more choice and to foster competition, the restructured NEPOOL proposes the unbundling of electric service in the NEPOOL control area. The restructured NEPOOL calls for the development of competitive wholesale markets for installed capability, operable capability, energy, automatic generation control, and reserves. These wholesale products will be market-priced based on bid clearing pricing rather than the current cost-based pricing. Market participants will be able to meet their responsibility for these products by buying or selling these various services through bilateral transactions or through the regional power exchange that will be administered through the ISO. On October 29, 1997, FERC issued an order permitting implementation of the installed capability market, which occurred in April of 1998. On April 6, 1999, FERC issued an order approving market rules and on May 1, 1999, the remaining markets - operable capability, energy, automatic generation control and the reserve markets - were implemented. In general, the EUA System companies support the changes to NEPOOL because much of the cross-subsidies for sharing costs will be eliminated. These changes will have an impact on the Company's operating revenues and costs as NEPOOL transitions from a cost-based to a bid-based system. See "Note C - Commitments and Contingencies: Environmental Matters" for a discussion of newly identified sites where the Company could be joint and severally responsible for environmental cleanup costs. Item 6. Exhibits and Reports on Form 8-K (a) Exhibits - None (b) Reports on Form 8-K - None SIGNATURES Pursuant to the requirements 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. Blackstone Valley Electric Company (Registrant) Date: August 13, 1999 /s/ Clifford J. Hebert, Jr. Clifford J. Hebert, Jr., Treasurer (on behalf of the Registrant and as Principal Financial Officer) EX-27 2 FDS
OPUR1 1000 6-MOS DEC-31-1999 JUN-30-1999 PER-BOOK 81711 200 17816 24149 7562 131438 9203 17908 14118 41229 0 6130 32000 750 0 0 1500 0 0 0 49829 131438 62199 1568 56509 58077 4122 (80) 4042 1820 2222 145 2077 2507 769 3579 0 0
-----END PRIVACY-ENHANCED MESSAGE-----