-----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, F8OQ/QjVCNag6QElNZN5ejXRHLcCS4oSV3XFKpzJZlh5TFraHtCy+iXa3DSmdLS5 +dFuNYE00Csu5+PWZ2ZHbA== 0000012473-98-000003.txt : 19981116 0000012473-98-000003.hdr.sgml : 19981116 ACCESSION NUMBER: 0000012473-98-000003 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19980930 FILED AS OF DATE: 19981113 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: 98748477 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 3RD QUARTER 1998 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 September 30, 1998 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 October 31, 1998 Common Shares, $50 par value 184,062 shares BLACKSTONE VALLEY ELECTRIC COMPANY CONDENSED BALANCE SHEETS (In Thousands)
September 30, December 31, ASSETS 1998 1997 Utility Plant in Service $ 142,289 $ 140,572 Less: Accumulated Provision for Depreciation and Amortization 59,929 55,851 Net Utility Plant in Service 82,360 84,721 Construction Work in Progress 3,023 1,037 Net Utility Plant 85,383 85,758 Current Assets: Cash and Temporary Cash Investments 753 408 Accounts Receivable - Associated Companies 436 513 - Other-Net 18,101 14,609 Materials, Supplies and Other Current Assets 1,098 1,154 Total Current Assets 20,388 16,684 Deferred Debits and Other Non-Current Assets 29,204 28,391 Total Assets $ 134,975 $ 130,833 LIABILITIES AND CAPITALIZATION Capitalization: Common Stock, $50 Par Value $ 9,203 $ 9,203 Other Paid-In Capital 17,908 17,908 Retained Earnings 13,679 10,981 Total Common Equity 40,790 38,092 Non-Redeemable Preferred Stock 6,130 6,130 Long-Term Debt - Net 32,000 33,500 Total Capitalization 78,920 77,722 Current Liabilities: Current Maturities of Long-Term Debt 1,500 1,500 Notes Payable 2,350 1,400 Accounts Payable - Associated Companies 12,570 8,332 - Other 376 960 Taxes Accrued 1,469 2,065 Interest Accrued 1,040 842 Other Current Liabilities 6,102 9,138 Total Current Liabilities 25,407 24,237 Accumulated Deferred Taxes, Deferred Credits and Other Non-Current Liabilities 30,648 28,874 Total Liabilities and Capitalization $ 134,975 $ 130,833 See accompanying notes to condensed financial statements.
BLACKSTONE VALLEY ELECTRIC COMPANY CONDENSED STATEMENTS OF INCOME (In Thousands)
Three Months Ended Nine Months Ended September 30, September 30, 1998 1997 1998 1997 Operating Revenues $ 35,007 $ 37,179 $ 97,153 $105,860 Operating Expenses: Purchased Power (principally from an affiliate) 22,111 24,836 60,726 69,540 Other Operation and Maintenance 5,696 5,532 16,507 16,014 Early Retirement Offer 0 363 Depreciation 1,563 1,442 4,687 4,324 Taxes Other Than Income 2,071 2,141 5,705 6,328 Income Taxes - Current 669 1,064 685 4,188 - Deferred (Credit) 311 (32) 1,888 (1,679) Total 32,421 34,983 90,198 99,078 Operating Income 2,586 2,196 6,955 6,782 Other Income (Deductions) - Net (15) (7) (96) 151 Income Before Interest Charges 2,571 2,189 6,859 6,933 Interest Charges: Interest on Long-Term Debt 749 787 2,295 2,408 Other Interest Expense 232 311 676 754 Allowance for Borrowed Funds Used During Construction (Credit) (27) (22) (77) (50) Net Interest Charges 954 1,076 2,894 3,112 Net Income 1,617 1,113 3,965 3,821 Preferred Dividend Requirements 73 73 217 217 Net Earnings $ 1,544 $ 1,040 $ 3,748 $ 3,604 See accompanying notes to condensed financial statements.
BLACKSTONE VALLEY ELECTRIC COMPANY CONDENSED STATEMENTS OF CASH FLOWS (In Thousands)
Nine Months Ended September 30, 1998 1997 CASH FLOW FROM OPERATING ACTIVITIES: Net Income $ 3,965 $ 3,821 Adjustments to Reconcile Net Income to Net Cash Provided from Operating Activities: Depreciation and Amortization 5,099 4,594 Deferred Taxes 1,888 (1,658) Investment Tax Credit, Net (134) (135) Other - Net (1,436) (1,682) Change in Operating Assets and Liabilities (3,139) 444 Net Cash Provided From Operating Activities 6,243 5,384 CASH FLOW FROM INVESTING ACTIVITIES: Construction Expenditures (4,082) (2,883) Net Cash (Used In) Investing Activities (4,082) (2,883) CASH FLOW FROM FINANCING ACTIVITIES: Redemptions: Long-Term Debt (1,500) (1,500) Common Stock Dividends Paid to EUA (1,049) (2,623) Preferred Dividends Paid (217) (217) Net Increase in Short-Term Debt 950 2,015 Net Cash (Used In) Financing Activities (1,816) (2,325) Net Increase in Cash and Temporary Cash Investments 345 176 Cash and Temporary Cash Investments at Beginning of Period 408 798 Cash and Temporary Cash Investments at End of Period $ 753 $ 974 Supplemental disclosures of cash flow information: Cash paid during the period for: Interest (Net of Amount Capitalized) $ 2,250 $ 2,494 Income Taxes $ 980 $ 3,200 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) 1997 Annual Report on Form 10-K and the Company's Quarterly Report on Form 10-Q for the periods ended March 31, and June 30, 1998. 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 September 30, 1998 and December 31, 1997, and the results of operations for the three and nine months ended September 30, 1998 and 1997 and cash flows for the nine months ended September 30, 1998 and 1997. 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. 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: See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations for a discussion of potential impacts as a result of the Year 2000 issue. 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. Overview Net Earnings for the three months ended September 30, 1998 were approximately $1.5 million compared to net earnings of approximately $1.0 million for the same period in 1997. For the nine months ended September 30, 1998 net earnings were approximately $3.7 million compared to the net earnings of $3.6 million for the same period in 1997. Earnings for the year-to-date period of 1997 include a one-time charge of approximately $260,000, on an after-tax basis, related to the costs of an early retirement offer recorded in June 1997. Kilowatthour (kWh) sales A combination of warmer weather and the continued strength of the regional economy led to kWh sales increases of 3.2% and 1.7% in the three and nine-month periods ending September 30, 1998, respectively. The third quarter increase was led by increases of 7.3% and 3.1% in the residential and commercial customer classes, which are typically more weather sensitive. For the year-to-date period, sales of electricity to residential and commercial customers each increased approximately 1%, and sales to industrial customers increased approximately 3.3% compared to the same period of 1997. Operating Revenues Operating revenues for the third quarter and nine months ended September 30, 1998 decreased by approximately $2.2 or 5.8% and $8.7 million or 8.2%, respectively, as compared to those of the same periods of 1997. These changes were due primarily to recoveries of decreased purchased power expenses (see below) resulting from rate reductions pursuant to electric industry restructuring legislation and approved settlements agreements. Offsetting these decreases was the impact of the above-mentioned increased kWh sales in both the third quarter and year-to-date periods. Also offsetting these decreases somewhat was a 1.3% base rate increase pursuant to the Rhode Island Utility Restructuring Act of 1996 (URA) effective January 1, 1998. Operating Expenses Purchased Power expense for the third quarter and nine months ended September 30, 1998 decreased by approximately $2.7 million or 11.0% and $8.8 million or 12.7%, respectively, as compared to the same periods of 1997. The Company's purchased power expense now reflects the contract termination charge and standard offer billings from Montaup effective January 1, 1998, pursuant to electric industry restructuring legislation and settlement agreements. Other Operation and Maintenance (O&M) expenses for the third quarter increased approximately $200,000 or 3.0% and increased approximately $500,000 or 3.1% for the nine months ended September 30, 1998 as compared to the same periods of 1997. These increases are primarily due to increased conservation and load management (C&LM) expenses and increased customer accounts expense. Other Income and (Deductions) - Net Other Income and (Deductions) - Net was relatively unchanged in this year's third quarter and decreased by approximately $200,000 in the year-to- date period as compared to the same periods of 1997. The year-to-date decrease is due primarily to the absence of interest income allocated to the Company by EUA Service Corporation in the first quarter of 1997 related to the favorable resolution of a Massachusetts corporate income tax dispute. 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 September 30, 1998, 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 September 30, 1998, these unused EUA System short-term lines of credit amounted to approximately $46.3 million. Blackstone had $2.4 million of short-term debt at September 30, 1998. During the first nine months of 1998 Blackstone's internally generated funds amounted to approximately $9.6 million while cash construction requirements for the same period amounted to approximately $4.1 million. Electric Utility Industry Restructuring Rhode Island legislation along with approved electric utility industry restructuring settlement agreements at both the state and federal levels, provided Blackstone's customers with choice of electricity supplier and rate reductions commencing January 1, 1998. Until a customer chooses an alternative supplier, that customer will receive standard offer service. Blackstone is required to arrange for standard offer service through December 31, 2009 and Montaup has guaranteed standard offer supply at a fixed price schedule for the duration of the standard offer period. The guaranteed standard offer price will increase over time to encourage customers to leave standard offer service and enter the competitive power supply market. Under the approved settlement agreements, Blackstone agreed to subject its standard offer requirements to a competitive bidding process in which competitive suppliers would bid against the guaranteed price offered by Montaup. The competitive process was completed in April 1998, and resulted in none of the standard offer requirements being awarded to competitive suppliers. Montaup will therefore continue to provide the unawarded standard offer requirement at the indicated fixed price schedule. This wholesale standard offer service will be assigned to purchasers of Montaup's generating capacity. Provisions of the approved settlement agreements also allowed Montaup to replace its all-requirements wholesale contract with Blackstone with a contract termination charge (CTC) which permits Montaup to recover, among other things, its above market investments and commitments in generation assets. Montaup began billing the CTC to Blackstone coincident with retail access and Blackstone is recovering the CTC through a non-bypassable transition charge to all of its 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, including Blackstone, via a Residual Value Credit (RVC). The RVC will reduce the fixed component of the CTC for the net proceeds, with a return, over the period commencing on the date the RVC is implemented through December 31, 2009. Montaup is committed to implement the RVC within 90 days of closing either the Canal or Somerset sale agreement. See Divestiture below. For a more detailed discussion of electric industry restructuring, refer to Blackstone's 1997 Annual Report on Form 10K. Divestiture On October 15, 1998, EUA announced that Montaup has signed an agreement to sell its 160-mw Somerset (Massachusetts) electric generating station for approximately $55 million to NRG Energy, Inc., a wholly-owned subsidiary of Northern States Power Co. based in Minneapolis, Minnesota. The sale also includes an additional 69 mw of currently deactivated generating capacity, and real estate at the Somerset site, and generating equipment at the 1.2 mw Pawtucket Hydro Station in Pawtucket Rhode Island, which is owned by Blackstone. With the Somerset sale agreement, EUA has now committed to sell all of its non-nuclear power generation assets. EUA had previously entered into agreements to sell: its 50 percent share (280 mw) of Unit 2 of the Canal Generating Station in Sandwich, Massachusetts to Southern Energy for approximately $75 million; its 2.6% (16 mw) share of the W. F. Wyman Unit 4 in Yarmouth, Maine to the Florida based FPL Group for approximately $2.4 million, and; two diesel-powered generating units (totaling approximately 16 mw) owned by Newport to Illinois-based Wabash County Equipment Co. for $1.5 million. In addition, Montaup has agreed to sell its 2.9 percent share (34 mw) of the Seabrook Station nuclear power plant to the Great Bay Power Corporation, a subsidiary of BayCorp Holdings, LTP for $3.2 million and announced the signing of agreements for the transfer of power purchase contracts for approximately 160 mw between Montaup and Ocean State Power. All of the sale and contract transfer agreements are subject to federal and state regulatory approvals, including that of the Nuclear Regulatory Commission with respect to the Seabrook sale. The Canal sale has been approved by both the Massachusetts Department of Telecommunications and Energy (DTE) and FERC. Closing of the non-nuclear sale agreements are anticipated to take place in the first quarter of 1999. The Seabrook sale is expected to take place in the later part of 1999. EUA's remaining generating capacity includes approximately 300 mw of power contracts, a 26 mw entitlement from Hydro Quebec and 58 mw from EUA's ownership shares of the Millstone 3 and Vermont Yankee nuclear facilities. The Year 2000 Issue The Year 2000 issue exists because some computer programs and embedded systems and components may not properly recognize a year that begins with "20" instead of "19," and therefore may fail or create erroneous results. The Company became aware of and started addressing Year 2000 issues in 1993 when certain forward looking computer programs experienced date related problems. Since that time, the Company has continued to broaden its efforts to address Year 2000 issues. The Company's State of Readiness: The transition to the Year 2000 presents potential challenges to the Company from three perspectives: the acquisition of products and services (including purchased power); the generation and delivery of electricity to customers; and, the ongoing general company activities related to the corporate infrastructure and support functions. These challenges emanate from sources both internal and external to the Company. By October 31, 1998, EUA had completed a comprehensive inventory and assessment of its systems and equipment that could potentially be affected by the Year 2000. All computer software and hardware as well as all office and field machinery, equipment and facilities were included. The results indicate that approximately 75% of the Year 2000 issues reside in the Company's computer systems and 25% reside in its embedded systems and components. The Company expects to complete its assessment of the Year 2000 compliance status of its material relationships with third parties, either as a customer or a vendor, during the first half of 1999. EUA has adopted a four phase approach in addressing information technology (IT) issues. As of September 30, 1998, each phase was at the following percentage of completion: analysis - 70%; remediation - 32%; unit testing - 25%; and integrated testing - 6%. Based on the current schedule, the Company estimates that 99% of all projects, and 100% of mission critical projects, will be completed and Year 2000 ready by June 30, 1999. For non-I/T Year 2000 issues, the Company has completed its inventory and assessment of embedded systems and components. The results of the assessment indicate that in excess of 90% of the items listed are either Year 2000 compliant or not affected by the Year 2000. The remaining items are scheduled to be analyzed, remediated where necessary, tested, and returned to service by May 31, 1999. Management does not believe these items represent significant costs or risks to the Company. Costs to Address the Company's Year 2000 Issues: Through September 30, 1998, EUA has incurred costs of approximately $2.3 million to address Year 2000 issues, including approximately $0.9 million of non-incremental internal labor costs, $1.1 million of capital expenditures and $0.3 of consulting costs. EUA estimates it will incur additional costs approximating $7.7 million during the period October 1, 1998 through March 31, 2000, to complete its resolution of Year 2000 issues including approximately $6.0 million of non- incremental internal labor, $0.5 million of capital expenditures and $1.2 million of consulting and other costs. Because 70% of the total estimated costs associated with the Year 2000 issue relate to non-incremental internal labor, management continues to believe that the Year 2000 will not present a material incremental impact to future operating results or financial condition. Risks of the Company's Year 2000 Issues: The Company's first priority is to minimize any potential disruptions to electric service as a result of the Year 2000. The Company's ability to maintain service depends in large part on the viability of the New England Power Grid which is managed by ISO/NEPOOL. The Company is participating extensively with ISO/NEPOOL Year 2000 operating and oversight committees. ISO/NEPOOL currently does not expect that large-scale power interruptions on the regional power grid external to the Company's service territory are likely. The Company's assessment of its own transmission and distribution (T&D) equipment and facilities indicated that the risk of failure of this equipment does not appear to be significant. However, while management believes that a significant disruption to the Company's T&D system caused by a Year 2000 problem is not reasonably likely, due to the interconnectivity to the New England power grid and the reliance on many other entities also connected to the grid, it is impossible to conclude with certainty that there will be no significant interruptions in service. In addition, dependable voice and data telecommunications are critical to the Company's ongoing operations. The Company's internal telecommunication systems are either Year 2000 compliant now, or on schedule to become compliant by mid-1999. The Company 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 made direct contact with representatives of the telephone companies on which the Company depends, each of which anticipates being Year 2000 ready and devoid of major system failures. No other significant reasonably likely failure scenarios stemming solely from Year 2000 related problems have been identified thus far through the risk inventory and assessment process. Accordingly, the Company does not currently believe that any Year 2000 related risks in and of themselves constitute reasonably likely worst case scenarios. Rather, the Company'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, the Company believes that such year 2000 failures would not likely affect whether the storm event would have a material impact on the Company's business or financial condition. Year 2000 Contingency Plans: The Company is in the process of developing contingency plans for any potential Year 2000 exposure that could have a material impact on its operations or financial well being. It is expected that a preliminary contingency plan will be developed during the first quarter of 1999. A final contingency plan should be completed by June 1999. 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 on Form 10-Q 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 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 key elements of the restructuring proposal are 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. 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. 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. The remaining markets - operable capability, energy, automatic generation control and the reserve markets are expected to start on January 1, 1999. If the January date is to be achieved, a favorable FERC order needs to be received on or before December 15, 1998. 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. Item 6. Exhibits and Reports on Form 8-K (a)Exhibits - None. (b)Reports on Form 8-K - None filed in the quarter ended September 30, 1998. 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: November 13, 1998 /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 9-MOS DEC-31-1998 SEP-30-1998 PER-BOOK 85383 44 20388 21834 7326 134975 9203 17908 13679 40790 0 6130 32000 2350 0 0 1500 0 0 0 52205 134975 97153 2573 87625 90198 6955 (96) 6859 2894 3965 217 3748 1500 2295 6243 0 0
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