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, 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 October 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>
September 30, December 31,
ASSETS 1999 1998
<S> <C> <C>
Utility Plant in Service $ 141,550 $ 144,120
Less: Accumulated Provision for Depreciation
and Amortization 63,136 60,534
Net Utility Plant in Service 78,414 83,586
Construction Work in Progress 3,180 2,065
Net Utility Plant 81,594 85,651
Current Assets:
Cash and Temporary Cash Investments 66 178
Accounts Receivable - Associated Companies 286 169
- Other - Net 15,717 17,498
Materials, Supplies and Other Current Assets 1,355 1,286
Total Current Assets 17,424 19,131
Deferred Debits and Other Non-Current Assets 52,973 29,363
Total Assets $ 151,991 $ 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 16,292 14,547
Total Common Equity 43,403 41,658
Non-Redeemable Preferred Stock 6,130 6,130
Long-Term Debt - Net 30,500 32,000
Total Capitalization 80,033 79,788
Current Liabilities:
Current Maturities of Long-Term Debt 1,500 1,500
Accounts Payable - Associated Companies 4,970 13,642
- Other 4,169 684
Taxes Accrued 2,551 1,493
Interest Accrued 974 779
Other Current Liabilities 4,918 5,276
Total Current Liabilities 19,082 23,374
Accumulated Deferred Taxes, Deferred Credits
and Other Non-Current Liabilities 52,876 30,983
Total Liabilities and Capitalization $ 151,991 $ 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 Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
<S> <C> <C> <C> <C>
Operating Revenues $ 34,992 $ 35,007 $ 97,191 $ 97,153
Operating Expenses:
Purchased Power (principally from an affiliate) 21,126 22,111 58,761 60,726
Other Operation and Maintenance 5,741 5,696 17,422 16,507
Depreciation 1,647 1,563 4,954 4,687
Taxes Other Than Income 2,121 2,071 6,007 5,705
Income Taxes - Current 1,033 669 2,715 685
- Deferred 279 311 165 1,888
Total 31,947 32,421 90,024 90,198
Operating Income 3,045 2,586 7,167 6,955
Other Income (Deductions) - Net 63 (15) (17) (96)
Income Before Interest Charges 3,108 2,571 7,150 6,859
Interest Charges:
Interest on Long-Term Debt 710 749 2,170 2,295
Other Interest Expense 156 232 563 676
Allowance for Borrowed Funds Used
During Construction (Credit) (4) (27) (51) (77)
Net Interest Charges 862 954 2,682 2,894
Net Income 2,246 1,617 4,468 3,965
Preferred Dividend Requirements 72 73 217 217
Net Earnings $ 2,174 $ 1,544 $ 4,251 $ 3,748
See accompanying notes to condensed financial statements.
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<TABLE>
BLACKSTONE VALLEY ELECTRIC COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
<CAPTION>
Nine Months Ended
September 30,
1999 1998
<S> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 4,468 $ 3,965
Adjustments to Reconcile Net Income to Net
Cash Provided from Operating Activities:
Depreciation and Amortization 5,233 5,099
Deferred Taxes 160 1,888
Investment Tax Credit, Net (132) (134)
Other - Net (211) (1,436)
Change in Operating Assets and Liabilities (2,697) (3,139)
Net Cash Provided From Operating Activities 6,821 6,243
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (2,959) (4,082)
Proceeds from Divestiture of Generation Assets 250
Net Cash (Used In) Investing Activities (2,709) (4,082)
CASH FLOW FROM FINANCING ACTIVITIES:
Redemptions of Long-Term Debt (1,500) (1,500)
Common Stock Dividends Paid to EUA (2,507) (1,049)
Preferred Dividends Paid (217) (217)
Net Increase in Short-Term Debt 950
Net Cash Provided From Financing Activities (4,224) (1,816)
Net (Decrease) Increase in Cash and Temporary Cash Investments (112) 345
Cash and Temporary Cash Investments at Beginning of Period 178 408
Cash and Temporary Cash Investments at End of Period $ 66 $ 753
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (Net of Amount Capitalized) $ 1,954 $ 2,250
Income Taxes $ 580 $ 980
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 periods ended March 31, and June 30,
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 September 30, 1999 and December 31, 1998, and the results of
operations for the three and nine months ended September 30, 1999 and
1998 and cash flows for the nine months ended September 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 (FASB) issued
SFAS 133, Accounting for Derivative Instruments and Hedging
Activities, which is effective for fiscal years beginning after June
15, 1999. In June 1999, the FASB issued SFAS 137, Accounting for
Derivative Instruments and Hedging Activities - Deferral of the
Effective Date, which amends SFAS 133 to be effective for all fiscal
quarters of all fiscal years beginning after June 15, 2000 (that is,
January 1, 2001 for companies with calendar-year fiscal years). SFAS
133 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 SFAS 133 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
During the second quarter of 1999, Blackstone identified three new
sites related to the production of manufactured gas at which certain
environmental conditions may exist. Blackstone has conducted a
preliminary assessment of the potential cost of remediation at
these sites. An engineering model was recently obtained by the
Company to provide the estimated potential costs. Since site specific
studies have not yet been performed, Blackstone has recorded a minimum
liability based on this engineering model for each of these sites to
recognize risk assessment, monitoring, and legal and administrative
costs.
In addition, Blackstone has recorded estimated environmental
remediation liabilities for two previously-identified manufactured
gas plant sites. The sites are the Tidewater site, the location of a
former electric generating station and manufactured gas plant in
Pawtucket, Rhode Island, and the Hamlet Avenue site, a former
manufactured gas plant site located in Woonsocket, Rhode Island.
Estimates were not previously recorded for these locations because
site-specific studies had not been performed and a reliable
engineering model deemed essential to develop a reasonable estimate
was not previously available.
With respect to the Tidewater site, Blackstone completed its site
investigation study in the third quarter of 1999 to determine the
nature and extent of contamination and has affirmed that extensive
elevated levels of hazardous substances are present in the surface
and subsurface. The Hamlet Street site assessment has not yet been
finalized. However, the assessment conducted to date has determined
that varying degrees of hazardous substance are present at that site.
In the third quarter of 1999, a total estimated remediation liability
of $21.1 million was recorded as a long-term liability with a
corresponding charge to a regulatory asset on the Balance Sheet.
Blackstone is currently recovering certain environmental cleanup costs
in rates. In addition, Blackstone will seek recovery of certain costs
from its insurance carriers and other possible responsible parties.
The Company expects, based on prior regulatory approvals, to recover
such costs in future rates. As a result, the Company does not believe
that the ultimate impact of the cleanup costs associated with these
sites will be material to the results of its operations 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 various regulatory agencies, values EUA's equity 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.
The closing of the merger is expected to occur by early 2000. The merger
agreement contains an upward price adjustment in the event the merger does not
close within six months from May 17,1999, the date EUA shareholders approved
the merger plan. Therefore, after November 17, 1999, NEES will pay an
additional $0.003 per day per share for EUA's outstanding common stock until
the merger closes, up to a maximum price of $31.495 per share.
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. With its
approval on September 29, 1999, FERC concluded that the proposed merger will
not adversely affect competition, rates or regulation, and that the merger is
in the public's best interest.
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. Hearings are scheduled to start
in December 1999. 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. A
settlement agreement on the Massachusetts filing is expected shortly.
On July 19, 1999, a Voluntary Early Retirement Program (VERP) was offered
to certain of EUA's and NEES's employees who will be at least fifty-five years
of age by December 31, 2000. The VERP offer was accepted by 82% of eligible
employees. On October 12, 1999, details of a Severance Plan were distributed.
The Severance Plan will provide benefits and provisions for eligible non-union
employees who are involuntarily terminated due to the merger. At the same
time, the Company also offered a Limited Hardship Early Decision Severance Plan
(LHEDO) to designated non-union employees who choose to terminate their
employment with EUA rather than be considered for a position in the merged
company. Employees who were offered the LHEDO must decide if they will accept
the offer by November 29, 1999. Under the LHEDO, employees will receive an
additional eight weeks of severance pay for accepting the offer. At this time,
the Company cannot reasonably estimate the participation in the LHEDO.
Therefore, expenses related to this plan have not yet been recorded.
Overview
Net Earnings for the three months ended September 30, 1999 were
approximately $2.2 million compared to net earnings of approximately $1.5
million for the same period in 1998. For the nine months ended September 30,
1999 net earnings were approximately $4.3 million compared to the net earnings
of $3.7 million for the same period in 1998.
Kilowatthour (kWh) sales
A combination of warmer weather and the continued strength of the regional
economy led to kWh sales increases of 5.3% and 3.9% in the three and nine-month
periods ending September 30, 1999, respectively. The third quarter increase
was led by increases of 9.6% and 4.1% 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 8.2% and 5.7%, respectively, compared to the same
periods of 1998.
Operating Revenues
Operating revenues were relatively unchanged in the third quarter and nine
months ended September 30, 1999 as compared to the same periods of 1998. The
impacts of increased kWh sales and increased standard offer rates, effective
April 1, 1999 and January 1, 1999 respectively, pursuant to restructuring
settlement agreements were offset by reductions in wholesale contract
termination charge rates.
Operating Expenses
Purchased Power expense for the third quarter and nine months ended
September 30, 1999 decreased by approximately $1.0 million or 4.5% and $2.0
million or 3.2%, respectively, as compared to the same periods of 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 for the third quarter was
relatively unchanged and increased approximately $900,000 or 5.5% for the nine
months ended September 30, 1999 as compared to the same periods of 1998. The
year-to-date increase is primarily due to adjustments to 1998 incentive plan
accruals recorded in the first quarter of 1999 and the allocation of increased
expenses from EUA's Service Corporation.
Net Interest Charges
Net Interest charges decreased by approximately $100,000 in the third
quarter and $200,000 in the year-to-date period, as result of normal cash
sinking fund payments and decreased short-term debt balances.
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, 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 September 30,
1999, these unused EUA System short-term lines of credit amounted to
approximately $27.5 million. Blackstone had no short-term debt at September
30, 1999.
During the first nine months of 1999 Blackstone's internally generated
funds amounted to approximately $7.3 million while cash construction
requirements for the same period amounted to approximately $3.0 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. A majority of this standard offer assignment became effective
January 1, 1999; the remainder became effective on September 1, 1999 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 from 3.04 cents per kWh to 2.10 cents per kWh for Eastern Edison and
from 3.0 cents per kWh to 2.04 cents per kWh and 2.06 cents per kWh in the
case of Blackstone and Newport, respectively. Retail transition charge
decreases to reflect these changes were authorized by respective state
regulatory bodies effective April 1, 1999 for Eastern Edison and May 1, 1999
for Blackstone and Newport.
Effective January 1, 1999 the standard offer service rate for Blackstone
and Newport 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 and Newport's retail transition charge, the standard
offer rate was changed to a flat rate of 3.5 cents per kilowatthour for
all customer classes.
The standard offer service rate for Eastern Edison customers was increased
to a flat rate of 3.1 cents per kilowatthour effective January 1, 1999. This
rate was further increased to 3.5 cents per kilowatthour coincident with the
Eastern Edison retail transition charge decrease effective April 1, 1999.
Generation Divestiture
By the end of 1998, pursuant to settlement agreements approved by federal
and state regulators, Montaup 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 for approximately $1.4 million
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
became 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
(Entergy) acquisition of Pilgrim Station from Boston Edison, Montaup agreed to
buy 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.
In October 1999, Vermont Yankee agreed to the sell the 540-mw nuclear unit
to AmerGen Energy Company for approximately $23.5 million. Montaup has a 2.5%
(12 mw) equity ownership interest in the unit. As part of the agreement,
Vermont Yankee will make a one-time payment to the unit's decommissioning fund
and AmerGen will assume responsibility for all future operating costs and costs
to decommission the plant at the end of its operating license in 2012. Vermont
Yankee expects to complete this sale by mid-2000.
Montaup also has agreed to sell its ownership interest in the Seabrook
Station nuclear power plant to Little Bay Power Corporation, a subsidiary of
BayCorp Holdings, Ltd.. Montaup has received all federal and state regulatory
approvals regarding Seabrook and expects to close on this sale later in 1999.
EUA's only remaining generating capacity is approximately 58 mw from its
ownership share of the Millstone 3 nuclear facility. EUA ultimately intends to
sell and/or transfer its interest in Millstone 3. 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 Issue
EUA is addressing the Year 2000 issue on an EUA System basis, which
includes Blackstone. 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 EUA Year 2000 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 information technology (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 Y2K ready or inert. 3.7% were tested -- none failed.
EUA utilized a four phase approach to address 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 levels 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 September 30, 1999, EUA has incurred costs of approximately $6.9
million to address Year 2000 issues, including approximately $4.3 million of
non-incremental labor, $1.2 million of capital expenditures and $1.4 million of
consulting and other costs. The company estimates it will incur additional
costs approximating $1.1 million during the period October 1, 1999 through
March 31, 2000, to complete its Year 2000 Program including approximately
$700,000 of non-incremental labor and $400,000 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 of 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. This plan
includes provisions for additional staffing during the transition weekend to
monitor mission critical systems and to resolve any Year 2000 issues which
might arise. The Implementation Plan was 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 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 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 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. An order accepting the settlement was received on July 30, 1999 and a
compliance filing was made on September 28, 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.
A Notice of Proposed Rulemaking by the FERC dated May 13, 1999 is
proposing to amend its regulations under the Federal Power Act (FPA) to
facilitate the formation of Regional Transmission Organizations (RTO's). FERC
proposes to require that each public utility that owns, operates, or controls
facilities for the transmission of electric energy in interstate commerce make
certain filings with respect to forming and participating in an RTO.
See "Note C - Commitments and Contingencies: Environmental Matters" for a
discussion of newly identified sites where Blackstone 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 filed in the quarter ended September 30, 1999.
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 15, 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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