UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period _________________ to ___________________
Commission File Number 0-2602
BLACKSTONE VALLEY ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
Rhode Island 05-0108587
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
750 W. Center Street, West Bridgewater, Massachusetts
(Address of principal executive offices)
02379
(Zip Code)
(508) 559-1000
(Registrant's telephone number including area code)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports), and (2)
has been subject to such filing requirements for the past 90 days.
Yes....X......No..........
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practical date.
Class Outstanding at October 31, 1998
Common Shares, $50 par value 184,062 shares
<TABLE>
BLACKSTONE VALLEY ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(In Thousands)
<CAPTION>
September 30, December 31,
ASSETS 1998 1997
<S> <C> <C>
Utility Plant in Service $ 142,289 $ 140,572
Less: Accumulated Provision for Depreciation
and Amortization 59,929 55,851
Net Utility Plant in Service 82,360 84,721
Construction Work in Progress 3,023 1,037
Net Utility Plant 85,383 85,758
Current Assets:
Cash and Temporary Cash Investments 753 408
Accounts Receivable - Associated Companies 436 513
- Other-Net 18,101 14,609
Materials, Supplies and Other Current Assets 1,098 1,154
Total Current Assets 20,388 16,684
Deferred Debits and Other Non-Current Assets 29,204 28,391
Total Assets $ 134,975 $ 130,833
LIABILITIES AND CAPITALIZATION
Capitalization:
Common Stock, $50 Par Value $ 9,203 $ 9,203
Other Paid-In Capital 17,908 17,908
Retained Earnings 13,679 10,981
Total Common Equity 40,790 38,092
Non-Redeemable Preferred Stock 6,130 6,130
Long-Term Debt - Net 32,000 33,500
Total Capitalization 78,920 77,722
Current Liabilities:
Current Maturities of Long-Term Debt 1,500 1,500
Notes Payable 2,350 1,400
Accounts Payable - Associated Companies 12,570 8,332
- Other 376 960
Taxes Accrued 1,469 2,065
Interest Accrued 1,040 842
Other Current Liabilities 6,102 9,138
Total Current Liabilities 25,407 24,237
Accumulated Deferred Taxes, Deferred Credits
and Other Non-Current Liabilities 30,648 28,874
Total Liabilities and Capitalization $ 134,975 $ 130,833
See accompanying notes to condensed financial statements.
</TABLE>
<TABLE>
BLACKSTONE VALLEY ELECTRIC COMPANY
CONDENSED STATEMENTS OF INCOME
(In Thousands)
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
<S> <C> <C> <C> <C>
Operating Revenues $ 35,007 $ 37,179 $ 97,153 $105,860
Operating Expenses:
Purchased Power (principally from an
affiliate) 22,111 24,836 60,726 69,540
Other Operation and Maintenance 5,696 5,532 16,507 16,014
Early Retirement Offer 0 363
Depreciation 1,563 1,442 4,687 4,324
Taxes Other Than Income 2,071 2,141 5,705 6,328
Income Taxes - Current 669 1,064 685 4,188
- Deferred (Credit) 311 (32) 1,888 (1,679)
Total 32,421 34,983 90,198 99,078
Operating Income 2,586 2,196 6,955 6,782
Other Income (Deductions) - Net (15) (7) (96) 151
Income Before Interest Charges 2,571 2,189 6,859 6,933
Interest Charges:
Interest on Long-Term Debt 749 787 2,295 2,408
Other Interest Expense 232 311 676 754
Allowance for Borrowed Funds Used
During Construction (Credit) (27) (22) (77) (50)
Net Interest Charges 954 1,076 2,894 3,112
Net Income 1,617 1,113 3,965 3,821
Preferred Dividend Requirements 73 73 217 217
Net Earnings $ 1,544 $ 1,040 $ 3,748 $ 3,604
See accompanying notes to condensed financial statements.
</TABLE>
<TABLE>
BLACKSTONE VALLEY ELECTRIC COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
<CAPTION>
Nine Months Ended
September 30,
<S> <C> <C>
1998 1997
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 3,965 $ 3,821
Adjustments to Reconcile Net Income to Net
Cash Provided from Operating Activities:
Depreciation and Amortization 5,099 4,594
Deferred Taxes 1,888 (1,658)
Investment Tax Credit, Net (134) (135)
Other - Net (1,436) (1,682)
Change in Operating Assets and Liabilities (3,139) 444
Net Cash Provided From Operating Activities 6,243 5,384
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (4,082) (2,883)
Net Cash (Used In) Investing Activities (4,082) (2,883)
CASH FLOW FROM FINANCING ACTIVITIES:
Redemptions:
Long-Term Debt (1,500) (1,500)
Common Stock Dividends Paid to EUA (1,049) (2,623)
Preferred Dividends Paid (217) (217)
Net Increase in Short-Term Debt 950 2,015
Net Cash (Used In) Financing Activities (1,816) (2,325)
Net Increase in Cash and Temporary Cash Investments 345 176
Cash and Temporary Cash Investments at Beginning of Period 408 798
Cash and Temporary Cash Investments at End of Period $ 753 $ 974
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (Net of Amount Capitalized) $ 2,250 $ 2,494
Income Taxes $ 980 $ 3,200
See accompanying notes to condensed financial statements.
</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) 1997 Annual Report on Form 10-K and the Company's
Quarterly Report on Form 10-Q for the periods ended March 31, and June 30,
1998.
Note A - In the opinion of the Company, the accompanying unaudited condensed
financial statements contain all normal and recurring adjustments
necessary to present fairly the financial position of the Company as
of September 30, 1998 and December 31, 1997, and the results of
operations for the three and nine months ended September 30, 1998 and
1997 and cash flows for the nine months ended September 30, 1998 and
1997. The year-end condensed balance sheet data was derived from
audited financial statements but does not include all disclosures
required under generally accepted accounting principles.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results
could differ from those estimates.
Note B - Results shown for the respective interim periods being reported
herein are not necessarily indicative of results to be expected for
the fiscal years due to seasonal factors which are inherent in
electric utilities in New England. A greater proportionate amount of
revenues is earned in the first and fourth quarters (winter season)
of each year because more electricity is sold due to weather
conditions, fewer daylight hours, etc.
Note C - Commitments and Contingencies:
See Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations for a discussion of potential impacts as a result of
the Year 2000 issue.
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
The following is Management's discussion and analysis of certain
significant factors affecting the Company's earnings and financial condition
for the interim periods presented in this Form 10-Q.
Overview
Net Earnings for the three months ended September 30, 1998 were
approximately $1.5 million compared to net earnings of approximately $1.0
million for the same period in 1997. For the nine months ended September 30,
1998 net earnings were approximately $3.7 million compared to the net earnings
of $3.6 million for the same period in 1997. Earnings for the year-to-date
period of 1997 include a one-time charge of approximately $260,000, on an
after-tax basis, related to the costs of an early retirement offer recorded in
June 1997.
Kilowatthour (kWh) sales
A combination of warmer weather and the continued strength of the
regional economy led to kWh sales increases of 3.2% and 1.7% in the three and
nine-month periods ending September 30, 1998, respectively. The third quarter
increase was led by increases of 7.3% and 3.1% in the residential and
commercial customer classes, which are typically more weather sensitive. For
the year-to-date period, sales of electricity to residential and commercial
customers each increased approximately 1%, and sales to industrial customers
increased approximately 3.3% compared to the same period of 1997.
Operating Revenues
Operating revenues for the third quarter and nine months ended September
30, 1998 decreased by approximately $2.2 or 5.8% and $8.7 million or 8.2%,
respectively, as compared to those of the same periods of 1997. These changes
were due primarily to recoveries of decreased purchased power expenses (see
below) resulting from rate reductions pursuant to electric industry
restructuring legislation and approved settlements agreements. Offsetting
these decreases was the impact of the above-mentioned increased kWh sales in
both the third quarter and year-to-date periods. Also offsetting these
decreases somewhat was a 1.3% base rate increase pursuant to the Rhode Island
Utility Restructuring Act of 1996 (URA) effective January 1, 1998.
Operating Expenses
Purchased Power expense for the third quarter and nine months ended
September 30, 1998 decreased by approximately $2.7 million or 11.0% and $8.8
million or 12.7%, respectively, as compared to the same periods of 1997. The
Company's purchased power expense now reflects the contract termination charge
and standard offer billings from Montaup effective January 1, 1998, pursuant
to electric industry restructuring legislation and settlement agreements.
Other Operation and Maintenance (O&M) expenses for the third quarter
increased approximately $200,000 or 3.0% and increased approximately $500,000
or 3.1% for the nine months ended September 30, 1998 as compared to the same
periods of 1997. These increases are primarily due to increased conservation
and load management (C&LM) expenses and increased customer accounts expense.
Other Income and (Deductions) - Net
Other Income and (Deductions) - Net was relatively unchanged in this
year's third quarter and decreased by approximately $200,000 in the year-to-
date period as compared to the same periods of 1997. The year-to-date decrease
is due primarily to the absence of interest income allocated to the Company by
EUA Service Corporation in the first quarter of 1997 related to the favorable
resolution of a Massachusetts corporate income tax dispute.
Liquidity and Sources of Capital
Blackstone's need for permanent capital is primarily related to
investments in facilities required to meet the needs of its existing and
future customers.
Traditionally, construction requirements in excess of internally
generated funds are financed through short-term borrowings which are
ultimately funded with permanent capital. In July 1997, several EUA System
companies, including Blackstone, entered into a three-year revolving credit
agreement allowing for borrowings in aggregate of up to $145 million from all
sources of short-term credit. As of September 30, 1998, various financial
institutions have committed up to $75 million under the revolving credit
facility. In addition to the $75 million available under the revolving credit
facility, EUA System companies maintain short-term lines of credit with
various banks totaling $90 million for an aggregate amount available of $165
million. At September 30, 1998, these unused EUA System short-term lines of
credit amounted to approximately $46.3 million. Blackstone had $2.4 million
of short-term debt at September 30, 1998.
During the first nine months of 1998 Blackstone's internally generated
funds amounted to approximately $9.6 million while cash construction
requirements for the same period amounted to approximately $4.1 million.
Electric Utility Industry Restructuring
Rhode Island legislation along with approved electric utility industry
restructuring settlement agreements at both the state and federal levels,
provided Blackstone's customers with choice of electricity supplier and rate
reductions commencing January 1, 1998. Until a customer chooses an
alternative supplier, that customer will receive standard offer service.
Blackstone is required to arrange for standard offer service through December
31, 2009 and Montaup has guaranteed standard offer supply at a fixed price
schedule for the duration of the standard offer period. The guaranteed
standard offer price will increase over time to encourage customers to leave
standard offer service and enter the competitive power supply market. Under
the approved settlement agreements, Blackstone agreed to subject its standard
offer requirements to a competitive bidding process in which competitive
suppliers would bid against the guaranteed price offered by Montaup. The
competitive process was completed in April 1998, and resulted in none of the
standard offer requirements being awarded to competitive suppliers. Montaup
will therefore continue to provide the unawarded standard offer requirement at
the indicated fixed price schedule. This wholesale standard offer service
will be assigned to purchasers of Montaup's generating capacity.
Provisions of the approved settlement agreements also allowed Montaup to
replace its all-requirements wholesale contract with Blackstone with a
contract termination charge (CTC) which permits Montaup to recover, among
other things, its above market investments and commitments in generation
assets. Montaup began billing the CTC to Blackstone coincident with retail
access and Blackstone is recovering the CTC through a non-bypassable
transition charge to all of its distribution customers.
As part of the approved settlement agreements, Montaup agreed to divest
its entire generation portfolio. The net proceeds of the sale, as defined in
the settlement agreements, will be used to mitigate Montaup's CTC to its
retail affiliates, including Blackstone, via a Residual Value Credit (RVC).
The RVC will reduce the fixed component of the CTC for the net proceeds, with
a return, over the period commencing on the date the RVC is implemented
through December 31, 2009. Montaup is committed to implement the RVC within
90 days of closing either the Canal or Somerset sale agreement. See
Divestiture below.
For a more detailed discussion of electric industry restructuring, refer
to Blackstone's 1997 Annual Report on Form 10K.
Divestiture
On October 15, 1998, EUA announced that Montaup has signed an agreement
to sell its 160-mw Somerset (Massachusetts) electric generating station for
approximately $55 million to NRG Energy, Inc., a wholly-owned subsidiary of
Northern States Power Co. based in Minneapolis, Minnesota. The sale also
includes an additional 69 mw of currently deactivated generating capacity, and
real estate at the Somerset site, and generating equipment at the 1.2 mw
Pawtucket Hydro Station in Pawtucket Rhode Island, which is owned by
Blackstone. With the Somerset sale agreement, EUA has now committed to sell
all of its non-nuclear power generation assets.
EUA had previously entered into agreements to sell: its 50 percent share
(280 mw) of Unit 2 of the Canal Generating Station in Sandwich, Massachusetts
to Southern Energy for approximately $75 million; its 2.6% (16 mw) share of
the W. F. Wyman Unit 4 in Yarmouth, Maine to the Florida based FPL Group for
approximately $2.4 million, and; two diesel-powered generating units (totaling
approximately 16 mw) owned by Newport to Illinois-based Wabash County
Equipment Co. for $1.5 million.
In addition, Montaup has agreed to sell its 2.9 percent share (34 mw) of
the Seabrook Station nuclear power plant to the Great Bay Power Corporation, a
subsidiary of BayCorp Holdings, LTP for $3.2 million and announced the signing
of agreements for the transfer of power purchase contracts for approximately
160 mw between Montaup and Ocean State Power.
All of the sale and contract transfer agreements are subject to federal
and state regulatory approvals, including that of the Nuclear Regulatory
Commission with respect to the Seabrook sale. The Canal sale has been approved
by both the Massachusetts Department of Telecommunications and Energy (DTE)
and FERC. Closing of the non-nuclear sale agreements are anticipated to take
place in the first quarter of 1999. The Seabrook sale is expected to take
place in the later part of 1999.
EUA's remaining generating capacity includes approximately 300 mw of
power contracts, a 26 mw entitlement from Hydro Quebec and 58 mw from EUA's
ownership shares of the Millstone 3 and Vermont Yankee nuclear facilities.
The Year 2000 Issue
The Year 2000 issue exists because some computer programs and embedded
systems and components may not properly recognize a year that begins with "20"
instead of "19," and therefore may fail or create erroneous results. The
Company became aware of and started addressing Year 2000 issues in 1993 when
certain forward looking computer programs experienced date related problems.
Since that time, the Company has continued to broaden its efforts to address
Year 2000 issues.
The Company's State of Readiness:
The transition to the Year 2000 presents potential challenges to the
Company from three perspectives: the acquisition of products and services
(including purchased power); the generation and delivery of electricity to
customers; and, the ongoing general company activities related to the
corporate infrastructure and support functions. These challenges emanate from
sources both internal and external to the Company. By October 31, 1998, EUA
had completed a comprehensive inventory and assessment of its systems and
equipment that could potentially be affected by the Year 2000. All computer
software and hardware as well as all office and field machinery, equipment and
facilities were included. The results indicate that approximately 75% of the
Year 2000 issues reside in the Company's computer systems and 25% reside in
its embedded systems and components. The Company expects to complete its
assessment of the Year 2000 compliance status of its material relationships
with third parties, either as a customer or a vendor, during the first half of
1999.
EUA has adopted a four phase approach in addressing information
technology (IT) issues. As of September 30, 1998, each phase was at the
following percentage of completion: analysis - 70%; remediation - 32%; unit
testing - 25%; and integrated testing - 6%. Based on the current schedule,
the Company estimates that 99% of all projects, and 100% of mission critical
projects, will be completed and Year 2000 ready by June 30, 1999. For non-I/T
Year 2000 issues, the Company has completed its inventory and assessment of
embedded systems and components. The results of the assessment indicate that
in excess of 90% of the items listed are either Year 2000 compliant or not
affected by the Year 2000. The remaining items are scheduled to be analyzed,
remediated where necessary, tested, and returned to service by May 31, 1999.
Management does not believe these items represent significant costs or risks
to the Company.
Costs to Address the Company's Year 2000 Issues:
Through September 30, 1998, EUA has incurred costs of approximately $2.3
million to address Year 2000 issues, including approximately $0.9 million of
non-incremental internal labor costs, $1.1 million of capital expenditures and
$0.3 of consulting costs.
EUA estimates it will incur additional costs approximating $7.7 million
during the period October 1, 1998 through March 31, 2000, to complete its
resolution of Year 2000 issues including approximately $6.0 million of non-
incremental internal labor, $0.5 million of capital expenditures and $1.2
million of consulting and other costs.
Because 70% of the total estimated costs associated with the Year 2000
issue relate to non-incremental internal labor, management continues to
believe that the Year 2000 will not present a material incremental impact to
future operating results or financial condition.
Risks of the Company's Year 2000 Issues:
The Company's first priority is to minimize any potential disruptions to
electric service as a result of the Year 2000. The Company's ability to
maintain service depends in large part on the viability of the New England
Power Grid which is managed by ISO/NEPOOL. The Company is participating
extensively with ISO/NEPOOL Year 2000 operating and oversight committees.
ISO/NEPOOL currently does not expect that large-scale power interruptions on
the regional power grid external to the Company's service territory are
likely. The Company's assessment of its own transmission and distribution
(T&D) equipment and facilities indicated that the risk of failure of this
equipment does not appear to be significant. However, while management
believes that a significant disruption to the Company's T&D system caused by a
Year 2000 problem is not reasonably likely, due to the interconnectivity to
the New England power grid and the reliance on many other entities also
connected to the grid, it is impossible to conclude with certainty that there
will be no significant interruptions in service.
In addition, dependable voice and data telecommunications are critical to
the Company's ongoing operations. The Company's internal telecommunication
systems are either Year 2000 compliant now, or on schedule to become compliant
by mid-1999. The Company also relies heavily on external telecommunication
systems, i.e., the local and regional telephone systems, and has identified
these providers as critical vendors. EUA has made direct contact with
representatives of the telephone companies on which the Company depends, each
of which anticipates being Year 2000 ready and devoid of major system
failures.
No other significant reasonably likely failure scenarios stemming solely
from Year 2000 related problems have been identified thus far through the risk
inventory and assessment process. Accordingly, the Company does not currently
believe that any Year 2000 related risks in and of themselves constitute
reasonably likely worst case scenarios. Rather, the Company's most reasonably
likely Year 2000 related worst case scenario would be the occurrence of
isolated year 2000 failures such as described above in conjunction with a
severe winter storm. However, the Company believes that such year 2000
failures would not likely affect whether the storm event would have a material
impact on the Company's business or financial condition.
Year 2000 Contingency Plans:
The Company is in the process of developing contingency plans for any
potential Year 2000 exposure that could have a material impact on its
operations or financial well being. It is expected that a preliminary
contingency plan will be developed during the first quarter of 1999. A final
contingency plan should be completed by June 1999.
Other
Blackstone occasionally makes forward-looking projections of expected
future performance or statements of our plans and objectives. These forward-
looking statements may be contained in filings with the SEC, press releases and
oral statements. This report on Form 10-Q contains information about the
Company's future business prospects including, without limitation, statements
about the potential impact of Year 2000 issues on the Company's financial
condition or results. These statements are considered "forward-looking" within
the meaning of the Private Securities Litigation Reform Act. These statements
are based on the Company's current plans and expectations and involve risks and
uncertainties that could cause actual future activities and results of
operations to be materially different from those set forth in the forward-
looking statements. The Company expressly undertakes no duty to update any
forward-looking statement.
Item 5. Other Information
NEPOOL is a voluntary organization open to any person engaged in the
electric business such as investor-owned utilities, municipals, cooperative
utilities, power marketers, brokers and load aggregators. On December 31,
1996, NEPOOL, on behalf of its participants, filed a restructuring proposal
with FERC. The key elements of the restructuring proposal are the
implementation of a regional NEPOOL Open Access Transmission Tariff (NEPOOL
Tariff), the creation of an Independent System Operator (ISO), and the
restatement of the NEPOOL Agreement to establish a broader governance
structure for NEPOOL and to develop a more open competitive market structure.
On June 25, 1997, FERC issued an order conditionally authorizing the
establishment of an ISO by NEPOOL effective July 1, 1997, affirming that the
transfer of control of transmission facilities owned by the public utility
members of NEPOOL to the ISO is consistent with the public interest under
Section 203 of the Federal Power Act.
On April 20, 1998, FERC accepted the NEPOOL Tariff conditional on
NEPOOL's compliance with a number of issues raised by FERC. On July 22, 1998,
NEPOOL made its compliance filing at FERC. The NEPOOL Tariff changes and
amendments to the Restated NEPOOL Agreement included in the filing effected
compliance with the Commission's April 20, 1998 Order. While there were a
large number of changes in the filing, the principal areas of change relate to
the addition in the NEPOOL Tariff of a separately available Internal Point to
Point Service, the addition of a mechanism to allocate costs to update the
regional transmission system, and the replacement of a Non-Use Charge with an
In-Service Charge across interconnections.
To give market participants more choice and to foster competition, the
restructured NEPOOL proposes the unbundling of electric service in the NEPOOL
control area. The restructured NEPOOL calls for the development of competitive
wholesale markets for installed capability, operable capability, energy,
automatic generation control, and reserves. These wholesale products will be
market-priced based on bid clearing pricing rather than the current cost-based
pricing. Market participants will be able to meet their responsibility for
these products by buying or selling these various services through bilateral
transactions or through the regional power exchange that will be administered
through the ISO. On October 29, 1997, FERC issued an order permitting
implementation of the installed capability market, which occurred in April of
1998. The remaining markets - operable capability, energy, automatic
generation control and the reserve markets are expected to start on January 1,
1999. If the January date is to be achieved, a favorable FERC order needs to
be received on or before December 15, 1998.
In general, the EUA System companies support the changes to NEPOOL because
much of the cross-subsidies for sharing costs will be eliminated. These
changes will have an impact on the Company's operating revenues and
costs as NEPOOL transitions from a cost based to a bid based system.
Item 6. Exhibits and Reports on Form 8-K
(a)Exhibits - None.
(b)Reports on Form 8-K
- None filed in the quarter ended September 30, 1998.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Blackstone Valley Electric Company
(Registrant)
Date: November 13, 1998 /s/ Clifford J. Hebert, Jr.
Clifford J. Hebert, Jr., Treasurer
(on behalf of the Registrant and
as Principal Financial Officer)
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