UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 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.)
Washington Highway, Lincoln, Rhode Island
(Address of principal executive offices)
02865
(Zip Code)
(401)333-1400
(Registrant's telephone number including area code)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports), and (2)
has been subject to such filing requirements for the past 90 days.
Yes....X......No..........
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practical date.
Class Outstanding at April 30, 1997
Common Shares, $50 par value 184,062 shares
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements
<TABLE>
BLACKSTONE VALLEY ELECTRIC COMPANY
CONDENSED BALANCE SHEETS
(In Thousands)
<CAPTION>
March 31, December 31,
ASSETS 1997 1996
<S> <C> <C>
Utility Plant in Service $ 138,779 $ 138,661
Less: Accumulated Provision for Depreciation
and Amortization 53,432 51,952
Net Utility Plant in Service 85,347 86,709
Construction Work in Progress 1,573 705
Net Utility Plant 86,920 87,414
Current Assets:
Cash and Temporary Cash Investments 1,336 798
Accounts Receivable - Ass. Companies 457 482
- Other 13,309 14,878
Materials, Supplies and Other Current Assets 1,238 1,290
Total Current Assets 16,340 17,448
Deferred Debits and Other Non-Current Assets 27,722 27,451
Total Assets $ 130,982 $ 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 9,872 9,121
Total Common Equity 36,983 36,232
Non-Redeemable Preferred Stock 6,130 6,130
Long-Term Debt 35,000 35,000
Total Capitalization 78,113 77,362
Current Liabilities:
Current Maturities 1,500 1,500
Notes Payable 3,500 735
Accounts Payable - Associated Companies 8,727 16,759
- Other 337 509
Taxes Accrued 2,166 1,415
Interest Accrued 1,014 899
Other Current Liabilities 6,474 2,342
Total Current Liabilities 23,718 24,159
Accumulated Deferred Taxes, Deferred Credits
and Other Non-Current Liabilities 29,151 30,792
Total Liabilities and Cap. $ 130,982 $ 132,313
See accompanying notes to condensed financial statements.
</TABLE>
<TABLE>
BLACKSTONE VALLEY ELECTRIC COMPANY
CONDENSED STATEMENTS OF INCOME
(In Thousands)
<CAPTION>
Three Months Ended
March 31,
<S> <C> <C>
1997 1996
Operating Revenues $ 34,531 $ 33,436
Operating Expenses:
Purchased Power (principally from an affiliate) 22,418 21,555
Other Operation and Maintenance 5,155 5,335
Depreciation 1,441 1,399
Taxes Other Than Income 2,159 2,277
Income Taxes - Current 2,564 1,941
- Deferred (Credit) (1,718) (1,344)
Total 32,019 31,163
Operating Income 2,512 2,273
Allowance for Borrowed Funds Used
During Construction 0 0
Other Income (Deductions) - Net 173 (24)
Income Before Interest Charges 2,685 2,249
Interest Charges:
Interest on Long-Term Debt 805 839
Other Interest Expense 189 144
Allowance for Borrowed Funds Used
During Construction (Credit) (6) (8)
Net Interest Charges 988 975
Net Income 1,697 1,274
Preferred Dividend Requirements 72 72
Net Earnings $ 1,625 $ 1,202
See accompanying notes to condensed financial statements.
</TABLE>
<TABLE>
BLACKSTONE VALLEY ELECTRIC COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
<CAPTION>
Three Months Ended
March 31,
1997 1996
<S> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 1,697 $ 1,274
Adjustments to Reconcile Net Income to Net
Cash Provided from Operating Activities:
Depreciation and Amortization 1,502 1,458
Deferred Taxes (1,718) (1,344)
Investment Tax Credit, Net (45) (46)
Allowance for Funds Used During Construction (5) 0
Other - Net (289) (268)
Change in Operating Assets and Liabilities (1,560) 2,386
Net Cash (Used In) Provided From Operating Activities (418) 3,460
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (863) (594)
Net Cash (Used In) Investing Activities (863) (594)
CASH FLOW FROM FINANCING ACTIVITIES:
Common Stock Dividends Paid to EUA (874) (1,088)
Preferred Dividends Paid (72) (72)
Net Increase (Decrease) in Short-Term Debt 2,765 (1,259)
Net Cash Provided From (Used In) Financing Activities 1,819 (2,419)
Net Increase in Cash and Temporary Cash Investments 538 447
Cash and Temporary Cash Investments at Beginning of Period 798 753
Cash and Temporary Cash Investments at End of Period $ 1,336 $ 1,200
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (Net of Amount Capitalized) $ 696 $ 713
Income Taxes $ 1,470 $ -
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 the Blackstone Valley Electric Company's
(Blackstone or the Company) 1996 Annual Report on Form 10-K.
Note A - In the opinion of the Company, the accompanying unaudited condensed
financial statements contain all normal and recurring adjustments
necessary to present fairly the financial position of the Company as
of March 31, 1997 and the results of operations and cash flows for
the three months ended March 31, 1997 and 1996. 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 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 were $1.6 million for the three month period ended March 31,
1997 as compared to $1.2 million for the same period in 1996. The Company
implemented a 1.88% base rate increase on January 1, 1997 pursuant to the Rhode
Island Utility Restructuring Act of 1996 (URA). Kilowatthour sales decreased
by 1.7% in the first quarter of 1997 as a compared the first quarter of 1996,
due to milder weather.
Operating Revenues
Operating Revenues for the quarter ended March 31, 1997 increased
approximately $1.1 million or 3.3% as compared to the same period in 1996. The
increase was primarily due to recoveries of increased purchased power expense
of approximately $900,000 (see below) and a base rate increase effective
January 1, 1997, offset somewhat by lower kilowatthour sales in the period.
Operating Expenses
Purchased Power expense for the first quarter of 1997 increased by
approximately $900,000 or 4.0%. Outages of nuclear units in this year's first
quarter contributed to a greater dependance on higher cost fossil fuels for
energy requirements, resulting in a 27.7% increase in average fuel costs.
Other Operation and Maintenance (O&M) expenses during the quarter ended
March 31, 1997 decreased by approximately $200,000 or 3.4% when compared to the
same period in the previous year due to decreases in employee benefits expenses
and uncollectible accounts expense.
Income Taxes
Blackstone's effective income tax rate for the quarter ended March 31,
1997 was approximately 35.8% compared to 31.8% for the same period of a year
ago. This increase is the result of decreased allocated consolidated tax
benefits and decreased state tax benefits.
Other Income and (Deductions) - Net
Other Income and (Deductions) - Net increased by approximately $200,000 in
this year's first quarter. 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.
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. At March 31, 1997 EUA System companies, including
Blackstone, maintained short-term lines of credit with various banks
aggregating approximately $140 million. These credit lines are available to
other affiliated companies under joint credit line arrangements. At March 31,
1997, these unused EUA System short-term lines of credit amounted to
approximately $93 million. Blackstone had $3.5 million of short-term debt
outstanding at March 31, 1997 During the first three months of 1997
internally generated funds amounted to approximately $500,000 while cash
construction requirements for the same period amounted to approximately
$900,000.
Electric Utility Industry Restructuring
On August 7, 1996 the Governor of Rhode Island signed into law the 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. 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 choose not to choose, the
local distribution company would be allowed to 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 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.
The transition charge recovers, among other things, costs of depreciated
generation net of its market value, regulatory assets, nuclear decommissioning
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 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 12.2% maximum allowed
return on equity for Blackstone and Newport. 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.
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 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 a commitment by Montaup to file a plan by July 1, 1997 to divest
all of its 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 the 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. EUA intends to amend this filing once
settlement negotiations have concluded in Rhode Island and Massachusetts. 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.
Negotiations in both Massachusetts and Rhode Island on final settlement
terms regarding electric utility industry restructuring, including the CTC, are
continuing, subsequent to which formal filings will be made to the MDPU and
RIPUC for approval. It is EUA's intent to file both Massachusetts and Rhode
Island settlements with FERC for approval of amendments to the all-requirements
wholesale contracts contained in the respective settlements.
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.
However, the potential exists that the final outcome of state and federal
agency determinations could result in the Company no longer meeting the
criteria of certain accounting standards which could trigger the discontinuance
of Statement of Financial Accounting Standards No. 71, "Accounting for the
Effects of Certain Types of Regulation" (FAS71). Should it be required to
discontinue the application of FAS71, the Company would be required to take an
immediate write down of the affected assets in accordance with FAS101,
"Accounting for the Discontinuation of Application of FAS71."
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.
Item 5. Other Information
On April 24, 1996, FERC issued orders on its March 24, 1995 Notice of
Proposed Rulemaking (NOPR). FERC's purpose in proposing the new rules was to
encourage competition in the bulk power market. FERC's April 24th actions
include:
- order No. 888, a final rule requiring open access transmission and
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.
Utilities must take transmission service for their own wholesale
transactions under the terms and conditions of the tariff;
- establishing the right and a mechanism for recovery of prudently
incurred stranded costs by public utilities and transmitting utilities;
which arise as a result of wholesale open access;
- order No. 889, a final rule requiring public utilities to implement
standards of conduct and an Open Access Same-time Information System
(OASIS). Utilities must obtain information about their transmission the
same way as their competitors through the OASIS;
- a 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 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 June 14,
1996. Montaup amended its filing on July 9, 1996 to modify its terms and
conditions in conformance with FERC's order. These tariffs are in compliance
with FERC's April 24th rulings.
On November 13, 1996, FERC issued a final order on the non-rate terms and
conditions of Montaup's open access transmission tariff. Montaup was required
to provide a more detailed description of the method used to compute available
transmission capability. FERC has not taken any action on the rates portion of
the tariff.
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. On
January 21,1997, Montaup filed revisions to its Open Access Transmission tariff
to coincide with the New England Power Pool (NEPOOL) Open Access Transmission
tariff filed on December 31, 1996 (see below) which became effective March 1,
1997, subject to refund and the issuance of further orders. On April 2, 1997,
Montaup filed additional revised tariff sheets to update the filing's formula
rate for local network service.
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 regionwide
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,
compliance tariffs must be filed by July 14, 1997.
In addition to the above transmission tariffs filings, the EUA System
companies have been actively involved in the restructuring of NEPOOL. 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 the 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.
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.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Blackstone Valley Electric Company
(Registrant)
Date: May 14, 1997 /s/Richard M. Burns
Richard M. Burns, Vice President
(on behalf of the Registrant and
as Chief Accounting Officer)
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