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 June 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.)
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 July 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)
June 30, December 31,
ASSETS 1997 1996
Utility Plant in Service $ 139,036 $ 138,661
Less: Accumulated Provision for Depreciation
and Amortization 54,627 51,952
Net Utility Plant in Service 84,409 86,709
Construction Work in Progress 2,259 705
Net Utility Plant 86,668 87,414
Current Assets:
Cash and Temporary Cash Investments 795 798
Accounts Receivable - Other - Net 15,245 14,878
- Associated Companies 494 482
Materials, Supplies and Other Current Assets 1,271 1,290
Total Current Assets 17,805 17,448
Deferred Debits and Other Non-Current Assets 28,657 27,451
Total Assets $ 133,130 $ 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 9,936 9,121
Total Common Equity 37,047 36,232
Non-Redeemable Preferred Stock 6,130 6,130
Long-Term Debt 35,000 35,000
Total Capitalization 78,177 77,362
Current Liabilities:
Current Maturities 1,500 1,500
Notes Payable 5,170 735
Accounts Payable - Associated Companies 9,828 16,759
- Other 470 509
Taxes Accrued 1,430 1,415
Interest Accrued 863 899
Other Current Liabilities 6,445 2,342
Total Current Liabilities 25,706 24,159
Accumulated Deferred Taxes, Deferred Credits
and Other Non-Current Liabilities 29,247 30,792
Total Liabilities and Cap. $ 133,130 $ 132,313
See accompanying notes to condensed financial statements.
BLACKSTONE VALLEY ELECTRIC COMPANY
CONDENSED STATEMENTS OF INCOME
(In Thousands)
Three Months Ended Six Months Ended
June 30, June 30,
1997 1996 1997 1996
Operating Revenues $ 34,150 $ 32,477 $ 68,681 $ 65,913
Operating Expenses:
Pur. Power (princ. from an affil.) 22,286 21,713 44,704 43,268
Other Operation and Maintenance 5,327 5,283 10,482 10,618
Early Retirement Offer 363 363
Depreciation 1,441 1,398 2,882 2,797
Taxes Other Than Income 2,028 2,061 4,187 4,338
Income Taxes - Current 560 375 3,124 2,316
- Deferred (Credit) 71 (14) (1,647) (1,358)
Total 32,076 30,816 64,095 61,979
Operating Income 2,074 1,661 4,586 3,934
Other (Deductions) Income - Net (15) (28) 158 (52)
Income Before Interest Charges 2,059 1,633 4,744 3,882
Interest Charges:
Interest on Long-Term Debt 816 846 1,621 1,685
Other Interest Expense 254 145 443 289
Allowance for Borrowed Funds Used
During Construction (Credit) (22) (15) (28) (23)
Net Interest Charges 1,048 976 2,036 1,951
Net Income 1,011 657 2,708 1,931
Preferred Dividend Requirements 72 72 144 144
Net Earnings $ 939 $ 585 $ 2,564 $ 1,787
See accompanying notes to condensed financial statements.
BLACKSTONE VALLEY ELECTRIC COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
Six Months Ended
June 30,
1997 1996
CASH FLOW FROM OPERATING ACTIVITIES:
Net Income $ 2,708 $ 1,931
Adjustments to Reconcile Net Income to Net
Cash Provided from Operating Activities:
Depreciation and Amortization 3,032 2,932
Deferred Taxes (1,627) (1,358)
Investment Tax Credit, Net (90) (91)
Other - Net (1,341) (836)
Change in Operating Assets and Liabilities (3,248) 2,675
Net Cash (Used In) Provided From Op. Act. (566) 5,253
CASH FLOW FROM INVESTING ACTIVITIES:
Construction Expenditures (1,979) (2,276)
Net Cash Used In Investing Activities (1,979) (2,276)
CASH FLOW FROM FINANCING ACTIVITIES:
Common Stock Dividends Paid to EUA (1,749) (2,255)
Preferred Dividends Paid (144) (144)
Net Increase (Decrease) in Short-Term Debt 4,435 (1,259)
Net Cash Provided From (Used In) Fin. Act. 2,542 (3,658)
Net Decrease in Cash and Temporary Cash Inv. (3) (681)
Cash and Temporary Cash Inv. at Beginning of Period 798 753
Cash and Temporary Cash Investments at End of Period $ 795 $ 72
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest (Net of Amount Capitalized) $ 1,766 $ 1,704
Income Taxes $ 2,850 $ 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 period ended March 31, 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 June 30, 1997 and December 31, 1996, and the results of operations
for the three and six months ended June 30, 1997 and 1996 and cash
flows for the six months ended June 30, 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.
Early Retirement Offer
In June of 1997, an early retirement offer was accepted by a group of
employees who were eligible but not offered the Voluntary Retirement Incentive
Offer in 1995, resulting in a charge of approximately $400,000 (approximately
$260,000 after-tax) recorded in the second quarter of 1997.
Overview
Net Earnings for the three months ended June 30, 1997 were $939,000
compared to $585,000 for the same period in 1996. Net earnings for the six
months ended June 30, 1997 were $2.6 million versus $1.8 million for the six
months ended June 30, 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). Both second quarter and year-to-date 1997 earnings include the
impacts of the June 1997 early retirement offer (discussed above).
Operating Revenues
Operating Revenues for the three and six months ended June 30, 1997
increased by approximately $1.7 million or 5.2% and approximately $2.8 million
or 4.2%, respectively, as compared to the same periods in 1996. These changes
were due primarily to recoveries of increased purchased power expenses and a
base rate increase effective January 1, 1997.
Operating Expenses
Purchased Power expense for the quarter and six months ended June 30, 1997
increased approximately $600,000 or 2.6% and $1.4 million or 3.3%,
respectively, as compared to the same periods of 1996. Outages of nuclear
units in both the second quarter and year-to-date periods of 1997 contributed
to a greater dependance on higher cost fossil fuels for energy requirements,
resulting in increases in average fuel costs of 28.3% and 27.8% for the
respective periods.
Other Operation and Maintenance (O&M) expenses were relatively unchanged
in the second quarter of 1997 as compared to the same quarter of 1996. For the
year-to-date period, O&M expenses decreased approximately $100,000 or 1.3% due
to a decrease in uncollectible accounts expenses slightly offset by increased
C&LM expense.
Effective Income Tax Rate
Blackstone's effective income tax rate for the six months ended June 30,
1997 increased from approximately 33.0% to 37.0%, when compared with the same
periods 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. At June 30, 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 June 30,
1997, these unused EUA System short-term lines of credit amounted to
approximately $83.9 million. Blackstone had $5.2 million of short-term debt at
June 30, 1997.
During the first six months of 1997 Blackstone's internally generated
funds available after the payment of dividends amounted to approximately $2.1
million, while cash construction requirements for the same period amounted to
approximately $2.0 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.
As of August 1, 1997, two customers 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 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. EUA intends to amend this filing once settlement
negotiations in Rhode Island, currently in progress, have concluded. 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 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 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.
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.
PART II -- OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders.
(a) A Consent to Action in Lieu of Annual Meeting of Stockholders
(Consent to Action) was executed April 16, 1997 by Eastern
Utilities Associates, the holder of the entire issued and
outstanding Common Stock of the Company and the only class of
stock entitled to vote at the Annual Meeting of Stockholders.
(b) The Board of Directors as previously reported to the Securities
and Exchange Commission was re-elected, with the exception of
David H. Gulvin, who upon retirement was replaced by Clifford
J. Hebert, Jr..
(c) The only matter voted on in the Consent to Action was the
election of directors.
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,
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.
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 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
No reports on Form 8-K were filed by the Registrant
during the three months ended June 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: August 14, 1997 /s/ Clifford J. Hebert, Jr.
Clifford J. Hebert, Jr., Treasurer
(on behalf of the Registrant and
as Principal Financial Officer)