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
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PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
BLACKSTONE VALLEY ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(In Thousands)
<CAPTION>
June 30, December 31,
ASSETS 1999 1998
<S> <C> <C>
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.
</TABLE>
<TABLE>
BLACKSTONE VALLEY ELECTRIC COMPANY
CONDENSED STATEMENTS OF INCOME
(In Thousands)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
<S> <C> <C> <C> <C>
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.
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<TABLE>
BLACKSTONE VALLEY ELECTRIC COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
<CAPTION>
Six Months Ended
June 30,
<S> <C> <C>
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.
</TABLE>
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)
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