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 March 31, 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 April 30, 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)
March 31, December 31,
ASSETS 1999 1998
Utility Plant in Service $ 144,245 $ 144,120
Less: Accumulated Provision for Depreciation
and Amortization 61,868 60,534
Net Utility Plant in Service 82,377 83,586
Construction Work in Progress 2,771 2,065
Net Utility Plant 85,148 85,651
Current Assets:
Cash and Temporary Cash Investments 2,109 178
Accounts Receivable - Associated Companies 361 169
- Other - Net 17,786 17,498
Materials, Supplies and Other Current Assets 1,280 1,286
Total Current Assets 21,536 19,131
Deferred Debits and Other Non-Current Assets 29,607 29,363
Total Assets $ 136,291 $ 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 14,285 14,547
Total Common Equity 41,396 41,658
Non-Redeemable Preferred Stock 6,130 6,130
Long-Term Debt - Net 32,000 32,000
Total Capitalization 79,526 79,788
Current Liabilities:
Current Maturities of Long-Term Debt 1,500 1,500
Accounts Payable - Associated Companies 16,541 13,642
- Other - Net 421 684
Taxes Accrued 1,526 1,493
Interest Accrued 940 779
Other Current Liabilities 4,585 5,276
Total Current Liabilities 25,513 23,374
Accumulated Deferred Taxes, Deferred Credits
and Other Non-Current Liabilities 31,252 30,983
Total Liabilities and Capitalization $ 136,291 $ 134,145
See accompanying notes to condensed financial statements.
BLACKSTONE VALLEY ELECTRIC COMPANY
CONDENSED STATEMENTS OF INCOME
(In Thousands)
Three Months Ended
March 31,
1999 1998
Operating Revenues $ 33,234 $ 31,181
Operating Expenses:
Purchased Power (principally from an affiliate) 20,937 19,064
Other Operation and Maintenance 5,793 5,316
Depreciation 1,642 1,539
Taxes - Other Than Income 2,073 1,814
Income Taxes - Current 477 (386)
- Deferred (Credit) 296 1,372
Total 31,218 28,719
Operating Income 2,016 2,462
Other Income (Deductions) - Net (49) (43)
Income Before Interest Charges 1,967 2,419
Interest Charges:
Interest on Long-Term Debt 726 769
Other Interest Expense 206 229
Allowance for Borrowed Funds Used
During Construction (Credit) (28) (20)
Net Interest Charges 904 978
Net Income 1,063 1,441
Preferred Dividend Requirements 72 72
Net Earnings $ 991 $ 1,369
See accompanying notes to condensed financial statements.
BLACKSTONE VALLEY ELECTRIC COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
Three Months Ended
March 31,
1999 1998
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 1,063 $ 1,441
Adjustments to Reconcile Net Income to Net
Cash Provided from Operating Activities:
Depreciation and Amortization 1,715 1,639
Deferred Taxes 295 1,372
Investment Tax Credit, Net (44) (45)
Other - Net (393) (461)
Change in Operating Assets and Liabilities 1,665 (4,371)
Net Cash Provided From (Used in) Operating Activities 4,301 (425)
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (1,045) (1,216)
Net Cash (Used In) Investing Activities (1,045) (1,216)
CASH FLOW FROM FINANCING ACTIVITIES:
Common Stock Dividends Paid to EUA (1,253) (349)
Preferred Dividends Paid (72) (72)
Net Increase in Short-Term Debt 0 1,810
Net Cash Provided From Financing Activities (1,325) 1,389
Net Increase in Cash and Temporary Cash Investments 1,931 (252)
Cash and Temporary Cash Investments at Beginning of Period 178 408
Cash and Temporary Cash Investments at End of Period $ 2,109 $ 156
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (Net of Amount Capitalized) $ $ 558
Income Taxes $ 472 $ 720
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 the Blackstone Valley Electric Company's
(Blackstone or the Company) 1998 Annual Report on Form 10-K.
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 March 31, 1999 and the results of operations and cash flows for
the three months ended March 31, 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 March 1998, The Accounting Standards Executive Committee of the
American Institute of Certified Public Accountants (AICPA) issued
Statement of Position 98-1, Accounting for the Costs of Computer
Software Developed or Obtained for Internal Use (SOP 98-1), effective
in 1999. SOP 98-1 provides specific guidance on whether to
capitalize or expense costs within its scope.
In June 1998, the Financial Accounting Standards Board issued FAS133,
"Accounting for Derivative Instruments and Hedging Activities," which
is effective in fiscal 2000. 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 is currently evaluating the
impact FAS133 will have on its financial position or results of
operations.
Note B - Results shown above for the respective interim periods 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.
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, expected by early 2000.
Proxy statements which include details of the merger have been distributed
along with voting instructions. Approval of the merger requires a two-thirds
shareholder vote. EUA's Annual Meeting of Shareholders is scheduled for May
17, 1999.
On April 30, EUA and NEES jointly filed with the Massachusetts Department
of Telecommunications and Energy a rate plan reflecting consolidated rates
following the merger for each company's Massachusetts subsidiaries. A similar
filing for EUA's and NEES's Rhode Island companies before the Rhode Island
Public Utilities Commission is expected in the near future.
On April 30, the EUA and NEES merger plan received clearance under the
federal Hart-Scott-Rodino Act. Under the Act, EUA and NEES had to file certain
information with the Federal Trade Commission and the Department of Justice.
Those agencies have reviewed the filings and have determined that the merger
will not violate anti-trust laws.
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.
Overview
Net Earnings were approximately $1.0 million for the three month period
ended March 31, 1999 as compared to $1.4 million for the same period in 1998.
Kilowatthour Sales
Kilowatthour (kWh) sales increased by 4.9% in the first quarter of 1999 as
a compared to the first quarter of 1998, largely due to cooler weather. Sales
to residential customers increased 11.2%, and sales to commercial customers
increased 8.5%.
Operating Revenues
Operating Revenues for the quarter ended March 31, 1999 increased
approximately $2.1 million or 6.6% as compared to the same period in 1998. The
increase was primarily due to increased recoveries of purchased power expenses
(see below) resulting from increased kWh sales and rate changes pursuant to
restructuring settlement agreements.
Operating Expenses
Purchased Power expense for the first quarter of 1999 increased by
approximately $1.9 million, or 9.8%. This increase was due to increased kWh
sales and increased generation-related revenues as a result of an increase in
the standard offer rate, effective January 1, 1999, pursuant to restructuring
settlement agreements.
Other Operation and Maintenance (O&M) expenses during the quarter ended
March 31, 1999 increased by approximately $500,000 or 9.0% when compared to the
same period in the previous year due primarily to employee incentive plan true-
ups in the first quarter of 1999.
Taxes Other Than Income increased approximately $300,000 or 14.3%, largely
due to increased Rhode Island Gross Receipts taxes as a result of increased
revenues in the first quarter of 1999 compared to the same period of 1998.
Income Taxes
Blackstone's effective income tax rate for the quarter ended March 31, 1999
was approximately 41.8% compared to 40.5% for the same period of a year ago.
This increase reflects the impact of accelerated reversal of timing differences
pursuant to restructuring settlement agreements along with lower taxable income
in the first quarter of 1999.
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.
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
December 31, 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 March 31, 1998, under the
revolving credit agreement, the EUA System had unused short-term
lines of credit of approximately $120 million. Blackstone had zero short-term
borrowings outstanding at March 31, 1999. During the first three months of
1999, internally generated funds amounted to approximately $1.7 million while
cash construction requirements for the same period amounted to approximately
$1.0 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 to purchasers of its generating assets. 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
On April 26, 1999, Montaup completed the sale of its 170 mw Somerset
Generating Station, located in Somerset, Massachusetts, to NRG Energy Inc.
(NRG), a subsidiary of Northern States Power Company, for approximately $55
million. Closing of the transaction, originally announced in October 1998,
culminates 75 years of power plant operation by Montaup.
The sale of Montaup's 50% share (280 mw) of Unit 2 of the Canal generating
station in Sandwich, Massachusetts to Southern Energy for $75 million, which
was announced in May 1998, was completed on December 30, 1998, and the sale of
two diesel-powered generating units (totaling approximately 16 mw) owned by
Newport to Illinois-based Wabash Power Equipment Co. for $1.5 million closed on
October 1, 1998.
Montaup's agreements to transfer purchase power contracts totalling
approximately 177 mw to Constellation, to sell 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 for the transfer of its power purchase contracts
with Ocean State Power (170 mw) to TransCanada are anticipated to occur in
the second quarter of 1999. The sale of Montaup's 2.9% share (34 mw) of the
Seabrook Station nuclear power plant to the Great Bay Power Corporation and the
renegotiation of its 11% (73 mw) power entitlement from the Pilgrim Nuclear
Power Station in Plymouth, Massachusetts are expected to take place later in
1999. All of the sale and contract transfer agreements are subject to federal
and/or state regulatory approvals, including that of the Nuclear Regulatory
Commission with respect to the Seabrook sale.
Montaup's remaining generating capacity includes approximately 46 mw from
its 4.0% joint ownership share of Millstone 3 nuclear unit and 12 mw from its
2.25% equity ownership of the Vermont Yankee nuclear facility.
Year 2000 Issue
EUA is addressing the Year 2000 issue on an EUA System basis, which
includes Blackstone. EUA's Year 2000 Program (Program) continues to proceed on
schedule toward its goal of achieving Year 2000 readiness on or before June 30,
1999. The Program is addressing the potential impact on computer systems and
embedded systems and components resulting from a common software program code
convention that utilizes two digits instead of four to represent a year. If
not addressed, the year 2000 may be systemically recognized as the year 1900,
which could cause system or equipment failures or malfunctions, and ultimately
result 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 has 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 relating to the corporate infrastructure and support
functions, which include among other things, billings and collections.
Based on work completed as of December 31, 1998, the following date
sensitive IT systems and remediation needs were identified:
> Central Applications: 54 date sensitive items consisting of centralized
computing software that addresses 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% are
Year 2000 ready or inert. 3.7% must be tested - any that fail will be
replaced.
EUA utilizes a four phase approach in addressing information technology
(IT) issues. The four phases are: 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 are
repaired or replaced during the Remediation phase. The Unit Testing phase
involves testing at the module, program and application level to assure that
each such item still functions properly after repair or replacement. Finally,
in the Integration Testing phase, dates are moved ahead, data are aged, and all
date conditions pertinent to each application or product are tested "end-to-
end" to assure that each item is tested in its final complete environment. For
mission critical systems, as of March 31, 1999, the phases described above were
at the following percentages of completion: Analysis - 100%; Remediation -
100%; Unit Testing - 100%. The most recent information regarding Integration
Testing is as of April 26, 1999. At that date, Integration Testing was 85%
complete. EUA is on schedule to achieve Year 2000 readiness for 100% of
mission critical projects by June 30, 1999. For non-I/T projects, as of the
end of April 1999, approximately 99% are either Year 2000 ready or not affected
by the Year 2000. The remaining items are in the process of being remediated
and tested and are scheduled to be Year 2000 ready by June 30, 1999.
EUA has an ongoing process to identify and assess the Year 2000 readiness
of third parties with which it has 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 a significant majority of
the 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. Where necessary, contingency plans
will be developed. This process is on schedule to be completed by June 30,
1999. All critical vendors except one are Year 2000 ready or on schedule to be
ready by December 31, 1999. The single exception is the municipality which
provides infrastructure services to EUA Service Corporation. Contingency plans
are in the process of being developed for services provided by this
municipality, as well as for all other critical vendors. Such plans will
identify workarounds for any critical vendor for which there is not an
alternative source.
Costs to Address EUA's Year 2000 Issues:
Through March 31, 1999, EUA has incurred costs of approximately $4.7
million to address Year 2000 issues, including approximately $2.6 million of
non-incremental labor, $1.2 million of capital expenditures and $900,000 of
consulting and other costs. Due to their nature, the capital expenditures and
the consulting and other costs are not allocable to the various phases of EUA's
Year 2000 Program identified above; however, the $2.6 million in non-
incremental labor costs can be assigned to particular phases of the Company's
Year 2000 project, in the following amounts: Analysis - $600,000; Remediation -
$550,000; Unit Testing - $550,000; and Integration Testing - $900,000. EUA
estimates it will incur additional costs approximating $5.3 million during the
period January 1, 1999 through March 31, 2000, to complete its resolution of
Year 2000 issues including approximately $3.8 million of non-incremental labor,
$500,000 of capital expenditures and $1.0 million of consulting and other
costs. Again, due to the nature of the capital, consulting and other costs,
they are generally not allocable to particular phases of EUA's Year 2000
Program; however, certain non-incremental labor costs may be assigned as
follows: Integration Testing - $2.6 million. In addition, EUA estimates it will
incur approximately $1.2 million in non-incremental labor costs during the
period July 1, 1999 through March 31, 2000 for Year 2000 related activities
such as: retesting, documentation review, communications outreach and customer
and vendor awareness programs, training, maintaining a "clean room"
environment, transition weekend preparations, transition weekend activities,
and post-transition weekend problem resolution. 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 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 are either
Year 2000 ready now, or on schedule to become Year 2000 ready, by 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 have been
established and are responsible for developing contingency plans. The overall
strategy will be 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. Preliminary plans were developed by March 31, 1999. Final plans are
scheduled to be in place and ready to implement, if necessary, by June 30,
1999.
Summary:
The amount of effort and resources necessary to address Year 2000 issues
and make EUA Year 2000 ready is significant. There are dedicated teams in place
to ensure EUA's transition into the next century occurs with minimal
disruption. By the end of December 1998, EUA had the equivalent of twenty full
time employees working on its Year 2000 project. Beginning in 1999, during
peak times, up to 7 contract programmers have been added to help EUA's
permanent IT staff deal with internal Year 2000 activities. Also, more than 12
vendor-provided IT professionals have been used to help with various short
duration Year 2000 projects specifically targeting that vendor's products.
EUA's Year 2000 program is on schedule and in accordance with timetables and
progress points published by the North American Electric Reliability Council.
In addition, EUA is utilizing outside technical consultants and other experts
to help ensure that its Year 2000 program remains on schedule and effective and
that risk and resource issues are appropriately assessed and addressed.
Management believes EUA's Year 2000 project is well managed and has the
appropriate resources and plans in place to ensure the Company is 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.
PART II - OTHER INFORMATION
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.
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.
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: May 14, 1999 /s/ Clifford J. Hebert, Jr.
Clifford J. Hebert, Jr., Treasurer
(on behalf of the Registrant and
as Principal Financial Officer)