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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
AMENDMENT NO. 1
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1995
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-6564
(LOGO) NEW ENGLAND POWER COMPANY
(Exact name of registrant as specified in charter)
MASSACHUSETTS 04-1663070
(State or other (I.R.S. Employer
jurisdiction of Identification No.)
incorporation or
organization)
25 Research Drive, Westborough, Massachusetts 01582
(Address of principal executive offices)
Registrant's telephone number, including area code
(508-389-2000)
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 ( )
Common stock, par value $20 per share, authorized and outstanding:
6,449,896 shares at September 30, 1995.
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The undersigned registrant hereby amends its Quarterly Report on
Form 10-Q for the quarterly period ending September 30, 1995 by
correcting two sentences which were inadvertently mistyped in the
"Competitive Conditions" section of its Management's Discussion and
Analysis of Financial Condition and Results of Operations. The
sentences should read as follows:
"In June 1995, the NHPUC issued an order in the Freedom Energy
docket in which it found that franchise territories in New Hampshire
are not exclusive as a matter of law. The order also stated that
federal law did not preclude the NHPUC from authorizing retail
wheeling."
Part I - Item 2 is restated in its entirety below.
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Item 2. Management's Discussion and Analysis of Financial
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Condition and Results of Operations
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This section contains management's assessment of New England
Power Company's financial condition and the principal factors having
an impact on the results of operations. This discussion should be
read in conjunction with the Company's financial statements and
footnotes and the 1994 Annual Report on Form 10-K.
Earnings
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Net income increased for the third quarter by approximately $12
million compared with the corresponding period in 1994. This
increase reflects sales growth, reduced overhaul activity of wholly-owned
generating units, and lower depreciation and amortization
expense, partially offset by increased interest costs and increased
reimbursements to affiliates for service extension discounts (SEDs)
to customers and affiliate generation and transmission (G&T) costs
incurred for the benefit of the Company. The decrease in
depreciation and amortization is due to reduced amortization of the
Seabrook 1 nuclear unit (Seabrook 1) in accordance with the Company's
1995 rate agreement, and the completion, in the second quarter of
1995, of the amortization of costs of certain coal conversion
facilities. These decreases were partially offset by the effects of
increased depreciation rates approved in the Company's 1995 rate
agreement and depreciation of new plant expenditures.
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Earnings for the first nine months of 1995 decreased
approximately $5 million due to increased purchased power costs
resulting from scheduled plant overhauls and refueling shutdowns at
partially-owned nuclear power suppliers and costs to repair the steam
generator tubes at the nuclear power plant owned by Maine Yankee
Atomic Power Company (Maine Yankee) in which the Company has a 20
percent interest. Also contributing to lower nine month earnings
were increased interest expenses, increased operation and
maintenance costs, and increased reimbursements to affiliates for
SEDs and their G&T costs.
Rate Activity
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In February 1995, the Federal Energy Regulatory Commission
(FERC) approved a rate agreement filed by the Company. Under the
agreement, which became effective January 1995, the Company's base
rates are frozen until 1997. Before this rate agreement, the
Company's rate structure contained two surcharges that were
recovering the costs of a coal conversion project and a portion of
the Company's investment in Seabrook 1. These two surcharges fully
recovered their related costs by mid-1995, however, under the rate
agreement they have been continued as part of base rates.
The agreement also allows for full recovery of costs associated
with the Manchester Street Station repowering project, which is
scheduled for completion during the fourth quarter of 1995. In
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addition, the agreement allows the Company to recover approximately
$50 million of deferred costs associated with terminated purchased
power contracts and postretirement benefits other than pensions
(PBOPs) over seven years. Under the agreement, the Company is fully
recovering currently incurred PBOP costs. The agreement further
provides for the recovery over three years of $27 million of costs
related to the dismantling of a retired generating station in Rhode
Island and the replacement of a turbine rotor at one of the Company's
generating units. The agreement also increases the Company's
recovery of depreciation expense by approximately $8 million
annually to recognize costs that will be incurred upon the eventual
dismantling of its Brayton Point and Salem Harbor generating plants.
Under the agreement, approximately $15 million of the $38 million in
Seabrook 1 costs due to be recovered in 1995 pursuant to a 1988
settlement agreement are being deferred and will be recovered in
1996.
Finally, the agreement provided that the Company would reimburse
its wholesale customers for discounts provided by those wholesale
customers to their retail customers under SED programs. Under these
programs, retail customers are entitled to such discounts only if
they have signed an agreement not to purchase power from another
supplier or generate any additional power themselves for a three to
five year period. Reimbursements in 1995 are expected to total $12
million.
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The FERC's approval of this rate agreement applies to all of
NEP's customers except the Milford Power Limited Partnership (MPLP).
MPLP, which owns a gas-fired power plant in Milford, Massachusetts,
has protested this rate agreement based on issues related to the
Manchester Street Station repowering project. Hearings on this
protest concluded in October 1995 and an Administrative Law Judge
initial decision is expected in early 1996 (for further discussion
see Note C).
Operating Revenue
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The following table summarizes the changes in operating revenue:
Increase (Decrease) in Operating Revenue
Third Quarter Nine Months
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1995 vs 1994 1995 vs 1994
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(In Millions)
Sales increase $ 7 $ 9
Fuel recovery (2) 17
SED reimbursements (3) (9)
Narragansett integrated
facilities credit (2) (6)
Other 2 5
--- ---
$ 2 $16
=== ===
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The increase in sales reflects the effects of an increase in peak
demands in the second and third quarters of 1995. The Company
experienced a decrease in peak demands in the first quarter of the
year.
For a discussion of fuel recovery see the fuel costs discussion
in the Operating Expenses section.
See the Rate Activity section for a discussion of SED
reimbursements.
The entire output of The Narragansett Electric Company's
(Narragansett) generating capacity is made available to the Company.
Narragansett receives a credit on its purchased power bill from the
Company for its fuel costs and other generation and transmission
related costs. The increased credits in 1995 reflect costs
associated with a new transmission line that went into service in
September 1994. In addition, the Company is reimbursing Narragansett
for an increased level of costs being incurred in 1995 associated
with the dismantlement of a previously retired South Street
generating facility. As part of the Company's 1995 rate agreement,
these credits in 1995 are being recovered over a three year period.
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Operating Expenses
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The following table summarizes the changes in operating
expenses:
Increase (Decrease) in Operating Expenses
Third Quarter Nine Months
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1995 vs 1994 1995 vs 1994
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(In Millions)
Fuel costs $ (1) $ 17
Purchased energy excluding fuel 2 23
Operation and maintenance (4) 12
Depreciation and amortization (13) (24)
Taxes 4 (11)
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$(12) $ 17
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Fuel costs represent fuel for generation and the portion of
purchased electric energy permitted to be recovered through the
Company's fuel adjustment clause. The increase in fuel costs in the
first nine months of 1995 reflects increased short-term purchases due
to decreased nuclear generation, decreased hydro production due to
low water levels, and overhauls of fossil fuel generating
facilities.
Purchased energy excluding fuel represents the remainder of
purchased electric energy costs. The increase in purchased energy
excluding fuel for the first nine months of 1995 is the result of
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increased costs associated with scheduled plant overhauls and
refueling shutdowns at partially-owned nuclear power facilities and
costs to repair the steam generator tubes at Maine Yankee in which
the Company has a 20 percent interest. The Maine Yankee nuclear unit
has been shut down since January 1995, but is expected to return to
service by year end. The Company recorded the full estimated
incremental cost of the repairs in the first six months of 1995 as a
charge to purchased power expense. The increase also includes
amortization of previously deferred purchased power contract
termination costs. Under the existing terms of certain purchased
power contracts with other utilities, the Company will be reducing
its power purchases which will result in a $19 million reduction in
1996 purchased power expenses.
The increase in operation and maintenance costs for the nine
months is primarily due to the recognition of currently incurred and
previously deferred PBOP costs in accordance with the Company's 1995
rate agreement, increased transmission system related costs and
increased general and administrative costs, partially offset by a
decrease in generating plant overhaul costs. In the third quarter,
the impact of reduced generating plant overhaul activity more than
offset the increases in costs in other areas.
The decrease in depreciation and amortization is due to decreased
amortization of Seabrook 1 and the completion, in the second quarter
of 1995, of the amortization of certain coal
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conversion facilities, partially offset by the effects of increased
depreciation rates approved in the Company's 1995 rate agreement and
depreciation of new plant expenditures.
The change in taxes for the third quarter and first nine months
of 1995 is primarily due to the change in income for those periods.
Allowance For Funds Used During Construction (AFDC)
- --------------------------------------------------
AFDC increased for the third quarter and first nine months of
1995 due to increased construction work in progress, principally
associated with the Manchester Street Station repowering project.
In September 1995, the first of three generating units began
commercial operation at the power plant. The remaining units are
scheduled to commence commercial operation during the fourth quarter
of this year. AFDC ends for these projects when the units go into
commercial operation.
Interest Expense
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The increase in interest expense is primarily due to increased
long-term and short-term debt balances and higher interest rates.
Competitive Conditions
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The electric utility business is being subjected to rapidly
increasing competitive pressures, stemming from a combination of
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trends, including surplus generating capacity, increasing electric
rates, improved technologies, increasing demand for customer choice,
and new regulations and legislation intended to foster competition.
See the Company's Annual Report on Form 10-K for the year ended
December 31, 1994.
The Company derives over 95 percent of its operating revenue from
sales of electricity to three retail affiliates of the Company.
Massachusetts, Rhode Island, and New Hampshire, the three states
served by these retail affiliates, have been considering various
proposals for allowing electric customers greater choice over their
electricity supplier. Massachusetts Electric Company (Massachusetts
Electric) and Narragansett proposed to the Massachusetts Department
of Public Utilities (MDPU) and the Rhode Island Public Utilities
Commission (RIPUC), respectively, a set of interdependent principles
for industry restructuring which was agreed to by groups representing
environmental protection advocates, governmental agencies, non-utility
generators, investor-owned utilities, and large and small customer interests.
These principles included, among others, provisions for increased
customer choice while allowing utilities the opportunity to recover
the cost of their past commitments (stranded costs). In August 1995,
the MDPU adopted principles similar to those filed by Massachusetts
Electric, including a reasonable opportunity for recovery of
stranded costs over a period not to exceed 10 years.
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The MDPU directed Massachusetts Electric and two other utilities to
file by February 16, 1996, a detailed plan consistent with the MDPU
decision. Also in August 1995, the RIPUC decision adopted the
principles proposed by Narragansett, except for one regarding
temporary support for renewable fuel technologies. The RIPUC ordered
Narragansett to file a report no later than February 1, 1996 on its
progress in negotiating a specific plan consistent with the
principles.
In October 1995, the New England Electric System (NEES) Companies
began discussions with interested parties regarding the plan to be
filed pursuant to the MDPU and RIPUC orders. That plan, to be called
"Choice: New England", will propose that all customers of electric
utilities in the three states served by NEES retail subsidiaries have
the ability to choose their power supplier beginning in 1998. Under
the plan, the Company's generation assets would become competitive,
while its transmission assets would remain regulated. Among other
provisions, the plan would also propose a uniform access charge so
that all regional utilities will have an opportunity to recover the
cost of commitments made under the current regulated system.
NEES believes that its "Choice: New England" proposal meets the
principles for industry restructuring adopted by the MDPU and RIPUC
for increased customer choice while providing utilities with an
opportunity to recover costs which may be stranded by such customer
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choice. However, there can be no assurance that a final plan will
include an access charge which would recover all stranded costs.
Furthermore, market pricing of generation will increase the
volatility of NEES revenues and, because of competitive pressures,
may not result in full cost recovery.
In July 1995, the Governor of Rhode Island vetoed two bills that
would have allowed certain industrial customers to buy power from
alternative suppliers, rather than through the local electric
utility. Narragansett urged the Governor to exercise his veto,
because Narragansett believed the proposed legislation would result
in piecemeal deregulation that would not be fair to customers or
shareholders and would circumvent the comprehensive proceedings
mentioned above. Narragansett committed among other things, that if
the measures were not enacted, Narragansett would submit by July 1,
1996, a specific and detailed proposal to the RIPUC addressing the
issues associated with providing open access to Narragansett's
distribution system for its large commercial and industrial
customers. Among other issues, that filing would address the proper
means for recovering past costs incurred to serve exiting customers
through a compensatory access charge. If the charges were approved
by the RIPUC, the appropriate access tariffs would then be filed with
the FERC. The Rhode Island Legislature may still override the
vetoes.
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In August 1995, the MDPU issued an order in a stranded cost case
involving another utility and one of its customers. This customer,
which previously purchased all of its requirements from the utility,
installed cogenerating equipment and requested that the utility
provide only backup service. In its order, the MDPU required the
customer to pay the utility 75 percent of the net stranded costs
attributable to serving the customer's load. Because, in part,
utilities have always been exposed to the risk of customer
cogeneration, the MDPU indicated that its order, which is under
appeal, did not set precedent for the issue of stranded cost recovery
in the context of utility industry restructuring.
In New Hampshire, the New Hampshire Public Utilities Commission
(NHPUC) has been considering the proposal of a new company, Freedom
Energy Company (Freedom Energy), to sell electricity at retail rates
to large customers of another utility. In June 1995, the NHPUC
issued an order in the Freedom Energy docket in which it found that
franchise territories in New Hampshire are not exclusive as a matter
of law. The order also stated that federal law did not preclude the
NHPUC from authorizing retail wheeling. However, the order makes
clear that Freedom Energy must obtain additional regulatory
approvals at the state and federal level before it could operate as
a public utility in the franchise territory of another utility.
In addition, in June 1995, the Governor of New Hampshire signed
into law a bill which instructs the NHPUC to establish a retail
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competition pilot program open to all classes of customers. NHPUC
guidelines issued in October 1995 provide that each New Hampshire
utility must allow customers representing 3 percent of its peak load
(four megawatts (MW) for Granite State Electric Company (Granite
State)) to have access to alternative suppliers of generation for
three years, starting May 1, 1996. Customers participating in the
pilot would be responsible for paying 50 percent of the utility's
stranded costs, with the balance borne by utility shareholders. In
comments filed on the preliminary guidelines, Granite State
requested that the guidelines be revised to adopt "Choice: New
England" as an alternative approach to the proposed pilot. Granite
State offered to file the plan with the NHPUC in February, consistent
with the filings contemplated in Massachusetts and Rhode Island, so
that the plan could be implemented on a pilot basis by May 1, 1996.
Granite State's comments also challenged the legal basis for the
proposed assignment of stranded costs, arguing that the guidelines
will result in an unconstitutional taking without compensation, are
preempted by federal law, and are inequitable. The June 1995
legislation also established a legislative committee on retail
wheeling and restructuring. The committee is expected to issue an
interim report on its findings in November 1995 and a final report by
March 1, 1996.
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In March 1995, the FERC issued a notice of proposed rule-making
in which it stated that recovery in rates of legitimate and
verifiable stranded costs from departing customers is the
appropriate method for recovery of costs stranded as the result of
wholesale competition. Under the FERC policy proposal, costs
stranded as a result of retail competition would be subject to state
commission review if the state commission has the necessary statutory
authority, and subject to FERC review if the state commission does
not have such authority. A final decision is expected in 1996.
Electric utility rates have historically been based on a
utility's costs. As a result, electric utilities are subject to
certain accounting standards that are not applicable to other
business enterprises in general. Financial Accounting Standard No.
71, Accounting for the Effects of Certain Types of Regulation (FAS
71), requires regulated entities, in appropriate circumstances, to
establish regulatory assets and liabilities, and thereby defer the
income statement impact of certain costs that are expected to be
recovered in future rates. The Company believes that its operations
currently meet the criteria established in FAS 71. However, the
effects of regulatory and/or legislative initiatives, or the NEES
companies' own initiatives, such as "Choice: New England", could, in
the near future, cause all or a portion of the Company's operations
to cease meeting the criteria of FAS 71. In
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that event, the application of FAS 71 to such operations would be
discontinued and a non-cash write-off of previously established
regulatory assets and liabilities related to such operations would
be required. At September 30, 1995, the Company had pre-tax
regulatory assets (net of regulatory liabilities) of approximately
$300 million. In addition, the Company's affiliate, New England
Energy Incorporated has a regulatory asset of approximately $200
million which is recoverable in its entirety from the Company. This
amount would also be included in any write-down of the Company's
regulatory assets. If competitive or regulatory change should cause
a substantial revenue loss or lead to the permanent shutdown of any
generating facilities, a substantial write-down of plant assets
could be required pursuant to Financial Accounting Standard No. 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of (FAS 121). This standard, effective for
fiscal year 1996, clarifies when and how to recognize an impairment
of long-lived assets. For further discussion of FAS 121 see Note D.
Utility Plant Expenditures and Financings
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Cash expenditures for utility plant totaled $125 million for the
first nine months of 1995, including $82 million related to the
Company's 90 percent share of the Manchester Street Station
repowering project in Providence, Rhode Island. In September 1995,
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the first of three generating units began commercial operation at the
power plant. The remaining units are scheduled to commence
commercial operation during the fourth quarter of this year. The
approximately 500 MW repowering project is estimated to cost
approximately $455 million, excluding transmission facilities. The
funds necessary for utility plant expenditures during the period were
provided by net cash from operating activities, after the payment of
dividends, and from proceeds of short-term and long-term debt issues.
In the first nine months of 1995, the Company issued $50 million of
long-term debt at interest rates ranging from 6.69 percent to 7.94
percent. In addition, the Company refinanced $10 million of variable
rate mortgage bonds. The Company does not plan to issue any
additional long-term debt in 1995.
At September 30, 1995, the Company had $167 million of short-term
debt outstanding, including $137 million of commercial paper
borrowings. At September 30, 1995, the Company had lines of credit
and bond purchase facilities with banks totaling $510 million which
are available to provide liquidity support for commercial paper
borrowings and for $342 million of the Company's outstanding variable
rate mortgage bonds in tax-exempt commercial paper mode and for other
corporate purposes. There were no borrowings under these lines of
credit at September 30, 1995.
For the twelve-month period ending September 30, 1995, the ratio
of earnings to fixed charges was 5.14.
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this Amendment No. 1 to Form
10-Q for the quarter ended September 30, 1995 to be signed on its
behalf by the undersigned thereunto duly authorized.
NEW ENGLAND POWER COMPANY
s/ Michael E. Jesanis
Michael E. Jesanis, Treasurer,
Authorized Officer, and
Principal Financial Officer
Date: December 20, 1995
