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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 1-3446
(LOGO) NEW ENGLAND ELECTRIC SYSTEM
(Exact name of registrant as specified in charter)
MASSACHUSETTS 04-1663060
(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 Shares, par value $1 per share, authorized and
outstanding: 64,924,456 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
---------------------------------------------------------
Condition and Results of Operations
-----------------------------------
This section contains management's assessment of New England
Electric System's (NEES) financial condition and the principal
factors having an impact on the results of operations. This
discussion should be read in conjunction with the consolidated
financial statements and footnotes and the 1994 Annual Report on Form
10-K.
Earnings
- --------
Earnings for the third quarter and first nine months of 1995 were
$1.14 per share and $2.39 per share, respectively, compared with $.91
and $2.49 per share earned in the corresponding periods in 1994.
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Increase (Decrease) in Earnings
Period ending September 30,
--------------------------
3 months 9 months
-------- --------
1994 earnings $ .91 $2.49
Sales to ultimate customers .08 (.04)
Purchased power costs excluding fuel (.02) (.21)
Other operation and maintenance
expenses .08 .01
Depreciation and amortization of
utility plant .13 .23
Interest expense, net of allowance for (.02) (.08)
funds used during construction
Other (.02) (.01)
----- -----
1995 earnings $1.14 $2.39
===== =====
Earnings in the third quarter increased as a result of increased
sales to ultimate customers, reflecting warmer weather in the summer
of 1995. During the nine month period, lower sales to residential
customers were offset by higher sales to commercial and industrial
customers.
The increase in purchased power costs for the nine months is
primarily due to overhauls and refueling shutdowns at partially-
owned nuclear power facilities. This increase also reflects costs
to repair the steam generator tubes at the nuclear power plant owned
by Maine Yankee Atomic Power Company (Maine Yankee) in which New
England Power Company (NEP) has a 20 percent interest.
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The reduction in other operation and maintenance expenses in the
third quarter reflects reduced overhaul activity at
wholly-owned generating units.
The decrease in depreciation and amortization reflects reduced
amortization of the Seabrook 1 nuclear unit (Seabrook 1) in
accordance with NEP's 1995 rate agreement (described below), and the
completion, in the second quarter of 1995, of the amortization of the
costs of certain coal conversion facilities. These decreases were
partially offset by the effects of increased depreciation rates
approved in NEP's 1995 rate agreement, increased charges associated
with the dismantlement of a retired generating facility, and
depreciation of new plant expenditures.
The increase in interest expense is primarily due to increased
long-term and short-term debt balances and higher interest rates.
Wholesale Rate Activity
- -----------------------
In February 1995, the Federal Energy Regulatory Commission
(FERC) approved a rate agreement filed by NEP. Under the agreement,
which became effective January 1995, NEP's base rates are frozen
until 1997. Before this rate agreement, NEP's rate structure
contained two surcharges that were recovering the costs of a coal
conversion project and a portion of NEP'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.
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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
addition, the agreement allows NEP 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, NEP 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 NEP's generating units. The
agreement also increases NEP'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.
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
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Administrative Law Judge initial decision is expected in early 1996
(for further discussion see Note B).
Retail Rate Activity
- --------------------
On September 29, 1995, the Massachusetts Department of Public
Utilities (MDPU) approved a $31 million increase to base rates for
Massachusetts Electric Company (Massachusetts Electric) which the
Company began billing effective October 1, 1995. Approximately $5
million of this increase relates to the amortization of previously
deferred PBOP costs. Massachusetts Electric and certain intervenors
to the rate case have each filed motions asking that the MDPU
reconsider certain rulings within its order.
On October 17, 1995, the Rhode Island Public Utilities Commission
(RIPUC) approved a settlement between The Narragansett Electric
Company (Narragansett), the Rhode Island Division of Public
Utilities and Carriers and a group of large commercial and industrial
customers that provides for a base rate increase of $15 million
effective in December 1995. The RIPUC also approved $3 million of
new discounts for manufacturing customers, the costs of which are not
being recovered from other customers.
In June 1995, the RIPUC opened a proceeding to reassess whether
fuel adjustment and purchased power cost adjustment (PPCA)
mechanisms should be continued after 1995 or whether such costs
should be included in base rates. These adjustment mechanisms
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currently allow Narragansett to pass through the costs of fuel and
purchased power and do not require Narragansett to take significant
risk regarding recovery of such costs. The RIPUC has not yet
scheduled hearings in this proceeding.
In July 1995, Granite State Electric Company (Granite State)
filed a $2.6 million rate increase request with the New Hampshire
Public Utilities Commission (NHPUC). On October 31, 1995, Granite
State received approval to collect an interim increase of $0.9
million, effective November 1, 1995, subject to refund or surcharge
pending the final outcome of the full case. A final decision is
expected during the first quarter of 1996.
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Operating Revenue
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The following table summarizes the changes in operating
revenue:
Increase (Decrease) in Operating Revenue
Third Quarter Nine Months
------------- ------------
1995 vs 1994 1995 vs 1994
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(In Millions)
Sales to ultimate customers $ 9 $ (4)
Rate changes 7 17
Fuel recovery (2) 17
Demand Side Management (DSM)
program recovery 5 6
Unbilled revenues recognized under
rate agreements (10) (22)
Oil and gas sales (3) (11)
Other 1 2
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$ 7 $ 5
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For a discussion of sales to ultimate customers, see the
Earnings section.
Rate changes for the three and nine months ended September 30,
1995 reflect the November 1994 expiration of Massachusetts
Electric's temporary rate decrease, partially offset by increased
discounts offered by NEES retail subsidiaries to large customers who
agreed to give a three to five year notice before changing
electricity suppliers.
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For a discussion of fuel recovery see the fuel costs discussion
in the Operating Expenses section.
The decrease in the recognition of unbilled revenues is due to
completion of Massachusetts Electric's recognition of $35 million of
unbilled revenues over a 13 month period that ended December 31,
1994, partially offset by Narragansett's recognition of $14 million
over a 21 month period that will end December 31, 1995. The
recognition of unbilled revenues was in accordance with rate
agreements.
The reduction in oil and gas sales is primarily due to decreased
gas production and lower gas prices.
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Operating Expenses
- ------------------
The following table summarizes the changes in operating
expenses:
Increase (Decrease) in Operating Expenses
Third Quarter Nine Months
------------- ------------
1995 vs 1994 1995 vs 1994
------------- ------------
(In Millions)
Fuel costs $ 1 $ 18
Purchased energy excluding fuel 2 23
Operation and maintenance:
Retail DSM 5 6
Other (8) (1)
Depreciation and amortization (16) (32)
Taxes 6 (10)
---- ----
$(10) $ 4
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Fuel costs represent fuel for generation and the portion of
purchased electric energy permitted to be recovered through NEP's
fuel adjustment clause. The increase in fuel costs for the first
nine months of 1995 reflects increased short-term purchases by NEP
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
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excluding fuel for the first nine months of 1995 is the result of
increased costs associated with scheduled plant overhauls and
refueling shutdowns at partially-owned nuclear power facilities.
This increase also reflects costs to repair the steam generator tubes
at Maine Yankee in which NEP 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. NEP 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, NEP will be reducing
its power purchases which will result in a $19 million reduction in
1996 purchased power expenses.
The decrease in other operation and maintenance expenses for the
third quarter is primarily due to reduced overhaul activity at NEP's
generating plants.
The decrease in depreciation and amortization is due to decreased
amortization of Seabrook 1 in accordance with NEP's 1995 rate
agreement, the completion of the amortization of certain coal
conversion facilities in the second quarter of 1995, and decreased
oil and gas amortization rates due to decreased gas production.
These decreases were partially offset by the effects of increased
depreciation rates approved in NEP's 1995 rate agreement, increased
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charges associated with the dismantlement of a retired generating
facility, 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
- ----------------
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
trends, including surplus generating capacity, increasing electric
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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.
Massachusetts, Rhode Island, and New Hampshire have been
considering various proposals for allowing electric customers
greater choice over their electricity supplier. Massachusetts
Electric and Narragansett proposed to the MDPU and 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. 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
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
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February 1, 1996 on its progress in negotiating a specific plan
consistent with the principles.
In October 1995, the 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, generation
assets would become competitive, while transmission and distribution
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
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.
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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 that, if the measures were
not enacted into law, Narragansett would provide a two year rate
discount to manufacturing customers (see Retail Rate Activity
section). In addition, Narragansett committed 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.
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
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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 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
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 three percent of its peak
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load (four megawatts for 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.
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
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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. NEES believes that the operations of its
utility subsidiaries 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 operations of one or more of its subsidiaries to cease
meeting the criteria of FAS 71. In 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,
NEES had consolidated pre-tax regulatory assets
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(net of regulatory liabilities) of approximately $600 million, of
which about $500 million is related to its subsidiaries' generation
business (including approximately $200 million related to oil and gas
properties regulated as part of the generation business), and about
$100 million is related to its subsidiaries' transmission and
distribution businesses. In addition, 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 C.
Liquidity and Capital Resources
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Plant expenditures in the first nine months of 1995 amounted to
$248 million for the utility subsidiaries, including $93 million
related to the Manchester Street Station repowering project in
Providence, Rhode Island. 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. The approximately 500
megawatt repowering project is estimated to cost approximately $455
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million, excluding transmission facilities. The funds necessary for
utility plant expenditures were primarily provided by net cash from
operating activities, after the payment of dividends, and from
proceeds of long-term debt issues.
The financing activities of NEES subsidiaries for the first nine
months of 1995 are summarized as follows:
Issues Retirements
------ -----------
(In Millions)
Long-term debt
- --------------
Massachusetts Electric $ 88 $ 35
Narragansett 15
New England Power 60 10
Granite State 5 2
Hydro-Transmission Companies 9
NEEI 202 238
---- ----
$370 $294
==== ====
NEP refinanced $10 million of variable rate mortgage bonds in the
first nine months of 1995. Interest rates on the other new long-term
debt issues shown above ranged from 6.69 to 8.46 percent. In October
1995, Narragansett issued $7 million of long-term debt at a rate of
7.50 percent. Narragansett is planning to issue $16 million of first
mortgage bonds during the fourth quarter of 1995, at an interest rate
of 7.30 percent, to refinance outstanding first mortgage bonds.
Narragansett Energy Resources Company is planning to issue $32
million of long-term notes during the fourth quarter of 1995 at an
interest rate of 7.25 percent.
<PAGE>
Net cash from operating activities provided all of the funds
necessary for oil and gas expenditures for the first nine months of
1995. New England Energy Incorporated's (NEEI) capitalized oil and
gas exploration and development costs amounted to $13 million,
including $8 million of capitalized interest costs. In April 1995,
NEEI refinanced its previous credit agreement with a group of banks.
The new agreement provides for borrowings of up to $225 million. The
amount available will decrease annually through 2002. At September
30, 1995, NEES and its consolidated subsidiaries had lines of
credit and standby bond purchase facilities with banks totaling $683
million. These lines and facilities were used for liquidity support
for $193 million of commercial paper borrowings and for $342 million
of NEP mortgage bonds in tax-exempt commercial paper mode. Fees are
paid on the lines and facilities in lieu of compensating balances.
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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 ELECTRIC SYSTEM
s/Alfred D. Houston
Alfred D. Houston
Executive Vice President and
Chief Financial Officer
Date: December 20, 1995
The name "New England Electric System" means the trustee or trustees
for the time being (as trustee or trustees but not personally) under
an agreement and declaration of trust dated January 2, 1926, as
amended, which is hereby referred to, and a copy of which as amended
has been filed with the Secretary of the Commonwealth of
Massachusetts. Any agreement, obligation or liability made, entered
into or incurred by or on behalf of New England Electric System binds
only its trust estate, and no shareholder, director, trustee, officer
or agent thereof assumes or shall be held to any liability therefor.
