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, 1997
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, 1997
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)
September 30, December 31,
ASSETS 1997 1996
Utility Plant in Service $ 139,290 $ 138,661
Less: Accumulated Provision for Depreciation
and Amortization 55,887 51,952
Net Utility Plant in Service 83,403 86,709
Construction Work in Progress 2,806 705
Net Utility Plant 86,209 87,414
Current Assets:
Cash and Temporary Cash Investments 974 798
Accounts Receivable - Associated Companies 776 482
- Other -Net 14,644 14,878
Materials, Supplies and Other Current Assets 1,147 1,290
Total Current Assets 17,541 17,448
Deferred Debits and Other Non-Current Assets 28,882 27,451
Total Assets $ 132,632 $ 132,313
LIABILITIES AND CAPITALIZATION
Capitalization:
Common Stock, $50 Par Value $ 9,203 $ 9,203
Other Paid-In Capital 17,908 17,908
Retained Earnings 10,102 9,121
Total Common Equity 37,213 36,232
Non-Redeemable Preferred Stock 6,130 6,130
Long-Term Debt 33,500 35,000
Total Capitalization 76,843 77,362
Current Liabilities:
Current Maturities 1,500 1,500
Notes Payable 2,750 735
Accounts Payable - Associated Companies 11,079 16,759
- Other 344 509
Taxes Accrued 1,850 1,415
Interest Accrued 1,041 899
Other Current Liabilities 7,971 2,342
Total Current Liabilities 26,535 24,159
Accumulated Deferred Taxes, Deferred Credits
and Other Non-Current Liabilities 29,254 30,792
Total Liabilities and Capitalization $ 132,632 $ 132,313
See accompanying notes to condensed financial statements.
BLACKSTONE VALLEY ELECTRIC COMPANY
CONDENSED STATEMENTS OF INCOME
(In Thousands)
Three Months Ended Nine Months Ended
September 30, September 30,
1997 1996 1997 1996
Operating Revenues $ 37,179 $ 37,015 $ 105,860 $ 102,928
Operating Expenses:
Purchased Power (princ. from an affiliate) 24,836 25,366 69,540 68,634
Other Operation and Maintenance 5,532 5,701 16,014 16,319
Early Retirement Offer 0 0 363
Depreciation 1,442 1,399 4,324 4,196
Taxes Other Than Income 2,141 2,126 6,328 6,464
Income Taxes - Current 1,064 (22) 4,188 2,294
- Deferred (Credit) (32) 601 (1,679) (757)
Total 34,983 35,171 99,078 97,150
Operating Income 2,196 1,844 6,782 5,778
Other Income (Deductions) - Net (7) (7) 151 (59)
Income Before Interest Charges 2,189 1,837 6,933 5,719
Interest Charges:
Interest on Long-Term Debt 787 818 2,408 2,503
Other Interest Expense 311 115 754 404
Allowance for Borrowed Funds Used 0 0
During Construction (Credit) (22) (29) (50) (52)
Net Interest Charges 1,076 904 3,112 2,855
Net Income 1,113 933 3,821 2,864
Preferred Dividend Requirements 73 73 217 217
Net Earnings $ 1,040 $ 860 $ 3,604 $ 2,647
See accompanying notes to condensed financial statements.
BLACKSTONE VALLEY ELECTRIC COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
Nine Months Ended
September 30,
1997 1996
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 3,821 $ 2,864
Adjustments to Reconcile Net Income to Net
Cash Provided from Operating Activities:
Depreciation and Amortization 4,594 4,455
Deferred Taxes (1,658) (757)
Investment Tax Credit, Net (135) (136)
Allowance for Funds Used During Construction 0 (2)
Other - Net (1,682) (1,196)
Change in Operating Assets and Liabilities 444 4,655
Net Cash Provided From Operating Activities 5,384 9,883
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (2,883) (3,411)
Net Cash (Used In) Investing Activities (2,883) (3,411)
CASH FLOW FROM FINANCING ACTIVITIES:
Redemptions:
Long-Term Debt (1,500) (1,500)
Common Stock Dividends Paid to EUA (2,623) (3,422)
Preferred Dividends Paid (217) (217)
Net Increase (Decrease) in Short-Term Debt 2,015 (1,259)
Net Cash (Used In) Financing Activities (2,325) (6,398)
Net Increase in Cash and Temporary Cash Investments 176 74
Cash and Temporary Cash Investments at Beginning of Period 798 753
Cash and Temporary Cash Investments at End of Period $ 974 $ 827
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (Net of Amount Capitalized) $ 2,494 $ 2,391
Income Taxes $ 3,200 $ 2,210
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) 1996 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,
1997.
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, 1997 and December 31, 1996, and the results of
operations for the three and nine months ended September 30, 1997 and
1996 and cash flows for the nine months ended September 30, 1997 and
1996.
In June 1997 the FASB issued Statement No. 130, "Reporting
Comprehensive Income", which establishes standards for reporting
comprehensive income and its components (revenues, expenses, gains,
and losses) in a set of general-purpose financial statements.
This Statement requires that all items that are required to be
recognized under accounting standards as components of comprehensive
income be reported in a financial statement that is displayed with
the same prominence as other financial statements. This Statement
is effective for fiscal years beginning after December 15, 1997, and
the Company will adopt Statement 130 in the first quarter of 1998.
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 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.
Overview
Net Earnings for the three months ended September 30, 1997 were
approximately $1.0 million compared to net earnings of approximately $900,000
for the same period in 1996. For the nine months ended September 30, 1997 net
earnings were approximately $3.6 million, compared to the net earnings of $2.6
million for the same periods in 1996. 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 sales increased by 5.3% in this year's third quarter as
compared the same period of 1996, offsetting decreased sales posted during the
first six months of 1997. Year-to-date sales increased by 1.1%. Sales to
residential customers, increased by 7.3% and 4.6%, in the third quarter
and year-to-date periods, respectively.
Operating Revenues
Operating revenues for the third quarter and nine months ended September
30, 1997 increased by approximately $200,000 and $2.9 million, respectively, as
compared to those of the same periods in 1996. The third quarter increase was
primarily due to a base rate increase effective January 1, 1997 offset by
recoveries of decreased purchased power expense (discussed below). The year-
to-date increase was primarily the result of the base rate increase and
recoveries of increased purchase power expense.
Operating Expenses
Purchased Power expense for the third quarter decreased by approximately
$500,000 or 2.1% as compared to the third quarter of 1996. Purchased power
expense for the nine months ended September 30, 1997 increased approximately
$900,000 or 1.3% as compared to the year-to-date period of 1996. As of August
1, 1997, pursuant to the Rhode Island Utility Restructuring Act (URA)
(discussed below), certain commercial and industrial customers of Blackstone
began to choose alternate electricity suppliers, reducing purchased power
requirements and expense for the third quarter and year-to-date periods as
compared to the same periods of 1996. Offsetting these decreases were
respective period increases of 9.9% and 20.9% in the average cost of fuel of
Montaup, the Company's power supplier. Outages at nuclear units, in which
Montaup has an interest contributed to a greater dependence on higher costing
fossil fuels for its energy requirements.
Other Operation and Maintenance (O&M) expenses for the third quarter and
nine months ended September 30, 1997 decreased approximately $200,000 or 3.0%
and approximately $300,000 or 1.9%, respectively, as compared to the same
periods of 1996. These decreases were primarily due to decreases in customers
accounts expense.
Other Income and (Deductions) - Net
Other Income and (Deductions) - Net was unchanged in this year's third
quarter and increased by approximately $200,000 in the year-to-date period as
compared to the same periods of 1996. This increase is due primarily to
interest income allocated to the Company by EUA Service Corporation related to
the favorable resolution of a Massachusetts corporate income tax dispute in
the first quarter of 1997.
Other Interest Expense
Other Interest expense increased approximately $200,000 in the third
quarter of 1997 and increased approximately $400,000 for the year-to-date
period of 1997, as compared to the same periods of 1996. These increases are
primarily due to interest on increased short-term borrowings and increased
intercompany interest expense.
Effective Income Tax Rate
Blackstone's effective income tax rate for the nine months ended September
30, 1997 increased from approximately 34.8% to 40.7%, when compared with the
same period of a year ago due primarily to decreased consolidated tax benefits.
Liquidity and Sources of Capital
Blackstone's need for permanent capital is primarily related to
investments in facilities required to meet the needs of its existing and future
customers.
Traditionally, construction requirements in excess of internally generated
funds are financed through short-term borrowings which are ultimately funded
with permanent capital. In July 1997, several EUA System companies entered
into a three year revolving credit agreement with various financial
institutions allowing for borrowings in aggregate of up to $75 million.
Blackstone had $2.8 million of short-term debt outstanding at September 30,
1997.
During the first nine months of 1997 Blackstone's internally generated
funds amounted to approximately $3.8 million while cash construction
requirements for the same period amounted to approximately $2.9 million.
Electric Utility Industry Restructuring
On August 7, 1996, the Governor of Rhode Island signed into law the
Utility Restructuring Act of 1996 (URA). The URA provides for customer choice
of electricity supplier to be phased-in commencing July 1, 1997 for large
manufacturing customers, certain new commercial and industrial customers, and
State of Rhode Island accounts. In addition to State of Rhode Island accounts,
11 customers of Blackstone were eligible for choice commencing July 1, 1997 and
as of November 1, 1997, all had exercised their right to choose an alternate
supplier of electricity. By July 1, 1998 or sooner, all customers will have
retail access. Under the URA the local distribution company will retain the
responsibility of providing distribution services to the ultimate electricity
consumer within its franchised service territory. For customers who do not
choose an alternative supplier, the local distribution company will arrange for
supply at a non-discriminatory, "standard offer" price. Distribution companies
will also be providers of last resort, required to arrange for supply at
prevailing market prices for customers who are unable to obtain their own
supply.
Blackstone is currently an all-requirements customer of Montaup for
generation services. This legislation provides for full recovery of prudently
incurred embedded generation costs that may not be recovered in a competitive
electric generation market, commonly referred to as "stranded costs," through a
non-bypassable transition charge initially set at 2.8 cents per kWh through
December 31, 2000. The transition charge recovers, among other things, costs
of depreciated generation net of its market value, regulatory assets, nuclear
decommissioning costs and above-market payments to power suppliers. The costs
of net, above-market generation assets and regulatory assets will be recovered,
with a return, through a fixed component of the transition charge from July 1,
1997 through December 31, 2009. A variable component of the transition charge
will recover, on a reconciling basis, among other things, nuclear
decommissioning and above market purchased power commitments from July 1, 1997
through the life of the respective unit or contract.
The URA also provides for commitments to demand side management
initiatives and renewables, low-income customer protections, divestiture of at
least 15% of owned non-nuclear generating units as a valuation basis for
mitigation of stranded cost recovery, and performance based rate making
standards for electric distribution companies. These performance based
standards provide for a 6% minimum and an approximate 12% maximum allowed
return on equity for Blackstone. In addition, the URA provides for adjustments
to electric distribution companies' base rates using the prior year's Consumer
Price Index and other performance factors. Under this provision of the law,
base rates were increased 1.88% for customers of Blackstone effective January
1, 1997.
In June 1997, legislation was enacted in Rhode Island, which would allow
securitization of utilities' stranded assets, a method of providing savings to
customers.
The implementation of the URA will require approvals from applicable
regulatory agencies, including the Federal Energy Regulatory Commission (FERC),
the Rhode Island Public Utilities Commission (RIPUC), and the Securities and
Exchange Commission (SEC).
In February 1997, Blackstone and Montaup reached settlement in principle
with the Rhode Island Division of Public Utilities and Carriers (RIDIV) and the
Rhode Island Attorney General and filed a Memorandum of Understanding (MOU)
with the RIPUC in March 1997 outlining the terms of the settlement. In
addition to complying with the URA, the settlement provides for an immediate
10% rate reduction and the filing of a plan to divest all of Montaup's
generating assets. Any disposition of generation assets resulting from the URA
would also require the approval of the SEC under the Public Utility Holding
Company Act of 1935.
Upon the commencement of retail choice Montaup's FERC approved, all-
requirements wholesale contract with Blackstone would be terminated. In its
place, Montaup will bill Blackstone a Contract Termination Charge (CTC)
designed to recover Montaup's stranded costs. Blackstone will recover the CTC
through a non-bypassable transition access charge to all of its distribution
customers as previously discussed. The transition access charge would be
reduced by the fair market value of Montaup's generating assets as determined
by selling, spinning off, or otherwise disposing of such generating facilities.
On May 1, 1997, Montaup and Blackstone jointly filed amendments to their
FERC approved all-requirements power contract with FERC. The filing included a
calculation for a CTC to recover stranded costs and a provision for standard
offer service for resale to retail customers who do not choose an alternate
generation supplier. These provisions are intended to ultimately replace the
current services offered by the all-requirements contracts upon full retail
access pursuant to the URA. The filing also includes "hold harmless"
provisions for Montaup's other wholesale customers and for retail customers of
Blackstone, which allow for recovery of any of Montaup's lost revenues
during the initial phases of retail access in Rhode Island. This filing allows
Blackstone to implement on July 1, 1997 the phase-in provisions of the URA and
to avoid any cross-subsidies by retail customers who are excluded from the
groups of customers given retail choice prior to final phase and by Montaup's
other customers.
On October 29, 1997, settlement agreements among Montaup, its affiliated
and non-affiliated customers, the Massachusetts Attorney General, the MADOER,
the RIDIV and RIPUC were submitted for FERC approval. These settlements
represent a comprehensive resolution of federal/wholesale issues of electric
utility industry restructuring based on our settlement agreements in Rhode
Island and Massachusetts.
Negotiations in Rhode Island on final settlement terms regarding retail
issues of electric utility industry restructuring, are nearing completion
subsequent to which formal filings will be made to the RIPUC for approval.
Historically, electric rates have been designed to recover a utility's
full costs of providing electric service including recovery of investment in
plant assets. Also, in a regulated environment, electric utilities are subject
to certain accounting rules that are not applicable to other industries.
These accounting rules allow regulated companies, in appropriate circumstances,
to establish regulatory assets and liabilities, which defer the current
financial impact of certain costs that are expected to be recovered in future
rates. The SEC has raised issues concerning the continued applicability of
these standards with certain other electric utilities, in other states, facing
restructuring. The Company believes that its operations will continue to meet
the criteria established in these accounting standards.
In July 1997, the Emerging Issues Task Force (EITF) reached a consensus
regarding certain issues raised related to the application of Statement of
Financial Accounting Standards No. 71 (FAS71), "Accounting for the Effects of
Certain Types of Regulation". The EITF determined that when sufficient detail
is available for the enterprise to reasonably determine how the transition plan
will affect the separable portion of its business being deregulated, the
enterprise should discontinue the application of FAS71 to that deregulated
portion of its business. In Rhode Island, sufficient detail is deemed to be
available, upon approval by FERC, of those restructuring plans submitted by
the Company in its jurisdiction. The EITF further determined that regulatory
assets and liabilities originating in the separable portion of the business and
no longer subject to rate regulation should be evaluated on the basis of where
regulated cash flows to recover those regulatory assets and liabilities
will be derived. Based on the current settlement agreement submitted by the
Company in Rhode Island, management does not believe the EITF decisions will
have a material effect on the Company.
Other
The Company occasionally makes projections of expected future performance
or statements of its plans, objectives and new business opportunities which are
forward-looking statements under federal securities law. Actual results could
differ materially from those discussed and there can be no assurance that such
estimates of future results will be achieved.
PART II -- OTHER INFORMATION
Item 5. Other Information
On April 24, 1996, the FERC issued orders No. 888 and No. 889 to
encourage competition in the bulk power market by requiring all public
utilities that own, operate or control interstate transmission to file tariffs
that offer others the same transmission services they provide themselves, under
comparable terms and conditions, establishing the right and a mechanism for
recovery of prudently incurred stranded costs and requiring public utilities to
implement standards of conduct and an Open Access Same-time Information System
(OASIS). FERC also issued a Notice of Proposed Rulemaking (NOPR) requesting
comment on replacing the single tariff contained in the final open access rule
with a capacity reservation tariff that would reveal how much transmission is
available at any given time.
Open-access transmission tariffs for point-to-point and local network
service were filed with FERC by Montaup in February 1996 and became effective
April 21, 1996, subject to refund, for a period of at least one year. The
rates in the tariffs were the subject of a settlement agreement which
was filed on July 9, 1996 to modify its terms and conditions in conformance
with FERC's order.
On December 31, 1996, Montaup filed revisions to its Open Access
Transmission tariff necessary to comply with FERC's order on September 11,
1996, which dealt with use rights of High Voltage Direct Current (HVDC)
interconnection transmission facilities with the Hydro Quebec system and on
January 21, 1997, filed additional revisions to coincide with the New England
Power Pool (NEPOOL) Open Access Transmission filing (see below).
On January 3, 1997, as required by FERC in Order No. 889, Montaup filed
its Standards of Conduct Implementation Procedures detailing Montaup's
compliance with the requirements of FERC's standards. Coincident with this
filing, Montaup complied with OASIS's requirements as part of a region wide
OASIS in NEPOOL.
On March 4, 1997, FERC issued Orders 888A and 889A which reaffirms the
legal and policy bases in which Orders 888 and 889 are grounded and addresses
interventions that were filed in response to Orders 888 and 889. As a result,
on July 14, 1997, Montaup filed revisions to its open access transmission
service for compliance with FERC Order 888A. The filing incorporates all of
the tariff amendments to date.
On June 4, 1997, as supplemented on July 14, 1997, Montaup filed with FERC
in Docket No. ER97-3200-000 amendments to its open access transmission tariff
to provide for unbundled retail transmission service. Montaup proposed to
allow retail customers to obtain retail transmission service directly from
Montaup or through Montaup's retail affiliates acting as the retail customers'
agent. Montaup requested FERC to allow the tariff amendments to become
effective for service to retail customers in Blackstone's and Newport's service
areas on July 1, 1997. FERC accepted the amendment to become effective subject
to refund on that date in an order issued September 12, 1997. FERC accepted
the amendment subject to any modification that may be required as a result
of other pending proceedings concerning Montaup's transmission tariff and
ordered Montaup to make a compliance filing changing the amendments in certain
limited respects. The compliance filing was made by Montaup on October 10,
1997.
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 is 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 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.
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 the NEPOOL's bulk power
transmission facilities. The NEPOOL Tariff promotes competition in the New
England power market through its non-pancaked 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.
NEPOOL is in the process of transferring operational control of the New
England bulk power system to the ISO, a newly created non-profit Delaware
corporation. The ISO's primary responsibility is to ensure system reliability,
administer the NEPOOL Tariff, and oversee the efficient and competitive
functioning of the regional power market. The selection of the ISO's Board of
Directors was announced in April 1997.
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, 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 transfer 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. Implementation of the
installed capability market is planned for November 1997, the operable
capability and energy markets are planned for April 1998, and the reserve
markets will follow later in 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, 1997.
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 14, 1997 /s/ Clifford J. Hebert, Jr.
Clifford J. Hebert, Jr., Treasurer
(on behalf of the Registrant and
as Principal Financial Officer)