SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1996
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: 64,893,481 shares at September 30, 1996.
PART I FINANCIAL STATEMENTS
Item 1. Financial Statements
- ----------------------------
NEW ENGLAND ELECTRIC SYSTEM AND SUBSIDIARIES
Statements of Consolidated Income
Periods Ended September 30
(Unaudited)
Quarter Nine Months
------- -----------
1996 1995 1996 1995
---- ---- ---- ----
(In Thousands)
Operating revenue $616,857 $599,126 $1,754,187 $1,690,989
-------- -------- ---------- ----------
Operating expenses:
Fuel for generation 92,771 64,176 239,503 171,603
Purchased electric energy 126,300 133,757 376,883 419,542
Other operation 126,475 130,050 368,071 361,183
Maintenance 31,564 27,069 98,485 102,195
Depreciation and amortization 64,477 63,610 195,383 204,435
Taxes, other than income taxes 36,146 31,944 110,767 99,503
Income taxes 41,740 46,199 103,623 96,941
-------- -------- ---------- ----------
Total operating expenses 519,473 496,805 1,492,715 1,455,402
-------- -------- ---------- ----------
Operating income 97,384 102,321 261,472 235,587
Other income:
Allowance for equity funds used during
construction 2,361 7,742
Equity in income of generating companies 2,565 2,566 8,052 7,895
Other income (expense), net (150) (771) (641) (278)
-------- -------- ---------- ----------
Operating and other income 99,799 106,477 268,883 250,946
-------- -------- ---------- ----------
Interest:
Interest on long-term debt 27,477 27,509 82,599 80,653
Other interest 4,872 5,410 15,445 13,761
Allowance for borrowed funds used during
construction (501) (4,339) (1,459) (10,935)
-------- -------- ---------- ----------
Total interest 31,848 28,580 96,585 83,479
-------- -------- ---------- ----------
Income after interest 67,951 77,897 172,298 167,467
Preferred dividends of subsidiaries 1,833 2,172 5,998 6,517
Minority interests 1,743 1,905 5,428 5,937
-------- -------- ---------- ----------
Net income $ 64,375 $ 73,820 $ 160,872 $ 155,013
======== ======== ========== ==========
Average common shares 64,894,972 64,924,456 64,890,539 64,950,977
Net income per average common share $.99 $1.14 $2.48 $2.390
Dividends declared per share $.59 $ .59 $1.77 $1.755
Statements of Consolidated Retained Earnings
Retained earnings at beginning of period $850,939 $784,549 $ 831,529 $ 779,045
Net income 64,375 73,820 160,872 155,013
Dividends declared on common shares (38,249) (38,279) (114,886) (113,968)
Other (450)
-------- -------- --------- ---------
Retained earnings at end of period $877,065 $820,090 $ 877,065 $ 820,090
======== ======== ========= =========
The accompanying notes are an integral part of these financial statements.
NEW ENGLAND ELECTRIC SYSTEM AND SUBSIDIARIES
Statements of Consolidated Income
Twelve Months Ended September 30
(Unaudited)
1996 1995
---- ----
(In Thousands)
Operating revenue $2,334,910 $2,248,401
---------- ----------
Operating expenses:
Fuel for generation 305,398 221,209
Purchased electric energy 505,711 554,381
Other operation 507,609 506,576
Maintenance 132,348 154,850
Depreciation and amortization 255,614 269,265
Taxes, other than income taxes 143,895 126,299
Income taxes 135,022 117,670
---------- ----------
Total operating expenses 1,985,597 1,950,250
---------- ----------
Operating income 349,313 298,151
Other income:
Allowance for equity funds used during construction 110 10,690
Equity in income of generating companies 10,709 9,728
Other income (expense), net (6,669) (2,666)
---------- ----------
Operating and other income 353,463 315,903
---------- ----------
Interest:
Interest on long-term debt 110,311 105,284
Other interest 21,510 14,961
Allowance for borrowed funds used during construction (4,540) (13,494)
---------- ----------
Total interest 127,281 106,751
---------- ----------
Income after interest 226,182 209,152
Preferred dividends of subsidiaries 8,171 8,689
Minority interests 7,396 7,732
---------- ----------
Net income $ 210,615 $ 192,731
========== ==========
Average common shares 64,898,858 64,955,646
Net income per average common share $3.25 $2.97
Dividends declared per share $2.36 $2.33
Statements of Consolidated Retained Earnings
Retained earnings at beginning of period $ 820,090 $ 778,685
Net income 210,615 192,731
Dividends declared on common shares (153,190) (151,326)
Other (450)
--------- ---------
Retained earnings at end of period $ 877,065 $ 820,090
========= =========
The accompanying notes are an integral part of these financial statements.
NEW ENGLAND ELECTRIC SYSTEM AND SUBSIDIARIES
Consolidated Balance Sheets
(Unaudited)
September 30, December 31,
ASSETS 1996 1995
------ ---- ----
(In Thousands)
Utility plant, at original cost $5,628,819 $5,480,001
Less accumulated provisions for depreciation
and amortization 1,816,833 1,710,991
---------- ----------
3,811,986 3,769,010
Net investment in Seabrook 1 under rate settlement 3,803 15,210
Construction work in progress 85,051 71,682
---------- ----------
Net utility plant 3,900,840 3,855,902
---------- ----------
Oil and gas properties, at full cost 1,279,057 1,266,290
Less accumulated provision for amortization 1,077,540 1,032,777
---------- ----------
Net oil and gas properties 201,517 233,513
---------- ----------
Investments:
Nuclear power companies, at equity 48,147 47,056
Other subsidiaries, at equity 37,866 40,259
Other investments 91,020 87,992
---------- ----------
Total investments 177,033 175,307
---------- ----------
Current assets:
Cash 5,186 7,064
Accounts receivable, less reserves of $20,176,000 and
$18,308,000 253,249 284,033
Unbilled revenues 58,003 66,300
Fuel, materials and supplies, at average cost 83,732 73,724
Prepaid and other current assets 91,835 77,673
---------- ----------
Total current assets 492,005 508,794
---------- ----------
Deferred charges and other assets 371,556 417,360
---------- ----------
$5,142,951 $5,190,876
========== ==========
CAPITALIZATION AND LIABILITIES
------------------------------
Capitalization:
Common share equity:
Common shares, par value $1 per share:
Authorized - 150,000,000 shares
Issued - 64,969,652 shares
Outstanding - 64,893,481 shares and 64,923,721
shares $ 64,970 $ 64,970
Paid-in capital 738,591 736,823
Retained earnings 877,065 831,529
Treasury stock - 76,171 shares and 45,931 shares (2,585) (1,543)
---------- ----------
Total common share equity 1,678,041 1,631,779
Minority interests in consolidated subsidiaries 48,005 48,912
Cumulative preferred stock of subsidiaries 126,166 147,016
Long-term debt 1,608,386 1,675,170
---------- ----------
Total capitalization 3,460,598 3,502,877
---------- ----------
Current liabilities:
Long-term debt due within one year 76,885 23,960
Short-term debt 152,875 203,250
Accounts payable 135,691 157,486
Accrued taxes 34,197 15,894
Accrued interest 22,662 27,455
Dividends payable 35,679 38,683
Other current liabilities 114,325 73,104
---------- ----------
Total current liabilities 572,314 539,832
---------- ----------
Deferred federal and state income taxes 750,136 780,451
Unamortized investment tax credits 92,048 93,408
Other reserves and deferred credits 267,855 274,308
---------- ----------
$5,142,951 $5,190,876
========== ==========
The accompanying notes are an integral part of these financial statements.
NEW ENGLAND ELECTRIC SYSTEM AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Nine Months Ended September 30
(Unaudited)
1996 1995
---- ----
(In Thousands)
Operating Activities:
Net income $ 160,872 $ 155,013
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 198,599 208,879
Deferred income taxes and investment tax credits, net (32,290) 9,573
Allowance for funds used during construction (1,459) (18,677)
Amortization of unbilled revenues (6,156)
Minority interests 5,428 5,937
Decrease (increase) in accounts receivable, net
and unbilled revenues 40,714 35,679
Decrease (increase) in fuel, materials, and supplies (9,495) (4,838)
Decrease (increase) in prepaid and other current assets(13,948) (1,789)
Increase (decrease) in accounts payable (22,469) (27,523)
Increase (decrease) in other current liabilities 53,196 18,472
Other, net 30,491 (17,616)
--------- ---------
Net cash provided by operating activities $ 409,639 $ 356,954
--------- ---------
Investing Activities:
Plant expenditures, excluding allowance for
funds used during construction $(180,685) $(248,283)
Oil and gas exploration and development (12,767) (12,584)
Other investing activities (2,196) (1,169)
--------- ---------
Net cash used in investing activities $(195,648) $(262,036)
--------- ---------
Financing Activities:
Dividends paid to minority interests $ (8,827) $ (8,897)
Dividends paid on NEES common shares (115,343) (112,983)
Changes in short-term debt (52,037) (41,370)
Long-term debt - issues 69,850 370,000
Long-term debt - retirements (87,570) (294,040)
Redemption of preferred stock (20,900)
Return of capital to minority interests
including related premium (1,364)
Repurchase of common shares (1,042) (1,516)
--------- ---------
Net cash used in financing activities $(215,869) $ (90,170)
--------- ---------
Net increase (decrease) in cash and cash equivalents $ (1,878) $ 4,748
Cash and cash equivalents at beginning of period 7,064 3,047
--------- ---------
Cash and cash equivalents at end of period $ 5,186 $ 7,795
========= =========
Changes in assets and liabilities shown above, other than cash, exclude the effects from
the purchase of Nantucket Electric Company on March 26, 1996.
The accompanying notes are an integral part of these financial statements.
Note A - Hazardous Waste
- ------------------------
The Federal Comprehensive Environmental Response, Compensation
and Liability Act, more commonly known as the "Superfund" law,
imposes strict, joint and several liability, regardless of fault,
for remediation of property contaminated with hazardous substances.
A number of states, including Massachusetts, have enacted similar
laws.
The electric utility industry typically utilizes and/or
generates in its operations a range of potentially hazardous
products and by-products. New England Electric System (NEES)
subsidiaries currently have in place an internal environmental
audit program and an external waste disposal vendor audit and
qualification program intended to enhance compliance with existing
federal, state, and local requirements regarding the handling of
potentially hazardous products and by-products.
NEES and/or its subsidiaries have been named as potentially
responsible parties (PRPs) by either the U.S. Environmental
Protection Agency (EPA) or the Massachusetts Department of
Environmental Protection for 23 sites at which hazardous waste is
alleged to have been disposed. Private parties have also contacted
or initiated legal proceedings against NEES and certain
subsidiaries regarding hazardous waste cleanup. The most prevalent
types of hazardous waste sites with which NEES and its subsidiaries
have been associated are manufactured gas locations. (Until the
early 1970's, NEES was a combined electric and gas holding company
system.) NEES is aware of approximately 40 such locations
(including nine of the 23 locations for which NEES companies are
PRPs) mostly located in Massachusetts. NEES and its subsidiaries
are currently aware of other sites, and may in the future become
aware of additional sites, that they may be held responsible for
remediating.
NEES has been notified by the EPA that it is one of several
PRPs for cleanup of the Pine Street Canal Superfund site in
Burlington, Vermont, where coal tar and other materials were
deposited. Between 1931 and 1951, NEES and its predecessor owned
all of the common stock of Green Mountain Power Corporation (GMP).
Prior to, during, and after that time, gas was manufactured at the
Pine Street Canal site by GMP. In 1989, NEES was one of 14 parties
required to pay the EPA's past response costs related to this site.
NEES remains a PRP for ongoing and future response costs. In
November 1992, the EPA proposed a cleanup plan estimated by the EPA
to cost $50 million. In June 1993, the EPA withdrew this cleanup
plan in response to public concern about the plan and its cost.
The cost of any cleanup plan is uncertain at this time. NEES
signed a settlement agreement in March 1996 establishing NEES's
apportionment percentage of these costs. NEES believes it has
adequate reserves for this site.
Note A - Hazardous Waste - Continued
- ------------------------
In 1993, the Massachusetts Department of Public Utilities
approved a Massachusetts Electric Company (Massachusetts Electric)
rate agreement that allows for remediation costs of former
manufactured gas sites and certain other hazardous waste sites
located in Massachusetts to be met from a non-rate-recoverable,
interest-bearing fund of $30 million established on Massachusetts
Electric's books in 1993. Rate-recoverable contributions of $3
million, adjusted for inflation, are added to the fund annually in
accordance with the agreement. Any shortfalls in the fund would be
paid by Massachusetts Electric and be recovered through rates over
seven years.
Predicting the potential costs to investigate and remediate
hazardous waste sites continues to be difficult. There are also
significant uncertainties as to the portion, if any, of the
investigation and remediation costs of any particular hazardous
waste site that may ultimately be borne by NEES or its
subsidiaries. Where appropriate, the NEES companies intend to seek
recovery from their insurers and from other PRPs, but it is
uncertain whether, and to what extent, such efforts will be
successful. At September 30, 1996, NEES had total reserves for
environmental response costs of $50 million and a related
regulatory asset of $20 million. NEES believes that hazardous
waste liabilities for all sites of which it is aware, and which are
not covered by a rate agreement, are not material to its financial
position.
Note B - Investments in Nuclear Units
- -------------------------------------
Connecticut Yankee
New England Power Company (NEP) has a 15 percent equity
ownership interest in Connecticut Yankee Atomic Power Company
(Connecticut Yankee) which owns a 580 megawatt (MW) nuclear
generating plant. At September 30, 1996, NEP's net investment in
Connecticut Yankee was $16 million. Subsidiaries of Northeast
Utilities (NU) own 49 percent of Connecticut Yankee. The
Connecticut Yankee station has been shut down since July 22, 1996,
after a potential problem with its cooling system was identified.
Since that time, the Nuclear Regulatory Commission (NRC) has
identified additional weaknesses and deficiencies which have to be
addressed before the plant can restart. On September 3, 1996, the
NRC sent an inspection team to Connecticut Yankee to investigate
two unrelated events occurring at the plant while it was shut down.
On October 9, 1996, the owners of Connecticut Yankee announced that
permanent shutdown of the plant was likely. The announcement was
Note B - Investments in Nuclear Units - Continued
- -------------------------------------
made based on an economic analysis comparing the incremental costs
associated with operating and maintaining the plant with the
expected value of the plant's output. A final decision by the
Connecticut Yankee board of directors is expected in the near
future. In the event the plant is permanently shut down,
Connecticut Yankee's estimated billings to NEP, including
decommissioning of the plant, is currently estimated to be
approximately $120 million and is subject to Federal Energy
Regulatory Commission approval. These costs would be recorded as
an accrued liability with an offsetting regulatory asset in the
expectation that the costs would be recoverable from customers. In
the event of restart, costs in the range of at least $40 million
would be required to address corrective actions at Connecticut
Yankee. NEP's share of these costs would be at least $6 million.
Millstone 3
NEP is a 12 percent joint owner of the Millstone 3 nuclear
generating unit (Millstone 3), a 1,150 MW unit. Millstone 3 is
operated by a subsidiary of NU. In March 1996, the Millstone 3
unit was shut down as a result of an internal safety review. In
April 1996, the NRC ordered Millstone 3 to remain shut down pending
verification that the unit's operations are in accordance with NRC
regulations and the unit's operating license. NEP is not a joint
owner of the Millstone 1 and 2 nuclear generating units, which are
also shut down under NRC orders.
The NRC has classified the Millstone units as Category 3
facilities on the NRC "watch list". The NRC deems Category 3 plants
as having significant weaknesses that require them to remain shut
down until it is demonstrated that adequate programs have been
established and implemented to ensure substantial improvement. On
August 6, 1996, the NRC Chairman described problems at the
Millstone units as pervasive and indicated that a culture change is
required. The NRC Chairman has also announced that independent
verification of corrective actions taken at the units will be
required prior to restart. On October 18, 1996, the NRC
established a Special Projects Office to oversee inspection and
licensing activities at Millstone. The NRC expects the office to
be in operation for 18 to 24 months. A vote of the NRC
Commissioners is required prior to restart of the units. NEP
cannot predict when Millstone 3 will be allowed by the NRC to
restart, but believes that the unit will remain shut down for a
very protracted period.
Note B - Investments in Nuclear Units - Continued
- -------------------------------------
NEP has an accrued liability of approximately $7 million at the
end of the third quarter of 1996 for its share of the currently
estimated future incremental operation and maintenance costs
related to corrective actions at the Millstone 3 unit. Additional
costs may be incurred beyond those already recognized. During the
outage, NEP is incurring approximately $1.5 million per month in
replacement power costs, which it has been recovering from
customers through its fuel clause.
Maine Yankee
NEP has a 20 percent equity ownership interest in Maine Yankee
Atomic Power Company (Maine Yankee) which owns an 880 MW nuclear
generating station. Maine Yankee is currently operating at 90
percent power until the NRC authorizes operation at a higher level.
As previously reported, the NRC is investigating allegations that
inadequate analyses of the plant's emergency core cooling system
were performed. In September 1996, the NRC asked the Department of
Justice to review an NRC investigatory report on the allegations.
Maine Yankee was also subject to an NRC independent safety
assessment. On October 7, 1996, the NRC staff issued its report,
which concluded that overall performance at Maine Yankee was
considered adequate for operation. However, the report identified
a number of weaknesses and deficiencies. Maine Yankee must respond
by December 10, 1996 to the report with its plans for resolving the
deficiencies. It is not known when, or if, the Maine Yankee plant
will be allowed to return to maximum capacity or how much of an
investment might be required to correct the deficiencies.
General
On October 9, 1996, the NRC issued letters to all nuclear power
plants requiring them to submit documentation showing that the
plants are operated and maintained within their design basis, and
any deviations are reconciled in a timely manner. The Seabrook 1,
Maine Yankee, and Vermont Yankee nuclear power plants, in which NEP
owns 10 percent, 20 percent, and 20 percent interests,
respectively, will all be required to respond to the NRC letters by
February 1997.
In general, it is unknown what the total ultimate impact of the
increased NRC scrutiny on the nuclear plants mentioned above will
have on NEP's operations and costs.
Note C - Brayton Point
- ----------------------
On October 22, 1996, the EPA announced it was beginning a
process to revoke NEP's water discharge permit for its Brayton
Point 1,538 MW power plant (Brayton Point). This action comes two
years before the permit expiration date. The EPA expects to work
with NEP and other interested parties, including the states of
Rhode Island and Massachusetts, to recommend new permit
requirements within 60 days. Brayton Point will continue to
operate under the terms of its existing permit until permit
modifications are made or a revised permit is issued. The EPA
stated it took the action in response to environmental concerns
regarding the plant's thermal discharges. NEP cannot predict at
this time what permit changes will be required or the impact on
plant operations and economics.
Note D
- ------
In the opinion of the Company, these statements reflect all
adjustments (which include normal recurring adjustments) necessary
for a fair statement of the results of its operations for the
periods presented and should be considered in conjunction with the
notes to the consolidated financial statements in the Company's
1995 Annual Report.
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 1995 Annual Report on
Form 10-K. This section contains forward-looking statements as
defined under the securities laws. Actual results could differ
materially from those projected. This section, particularly under
"Competitive Conditions - Risk Factors", lists some of the reasons
why results could differ materially from those projected.
Earnings
- --------
Earnings for the third quarter and first nine months of 1996
were $.99 per share and $2.48 per share compared with $1.14 per
share and $2.39 per share for the corresponding periods in 1995.
The table below details the primary factors affecting consolidated
earnings:
Period ending September 30,
------------------------
3 Months 9 Months
-------- --------
1995 earnings $1.14 $2.39
Increased revenues .02 .27
Decreased purchased power costs,
excluding fuel .03 .27
Seabrook 1 and Oil Conservation
Adjustment (OCA) amortization - .15
Increased depreciation, including
Manchester Street (.04) (.12)
Allowance for funds used during
construction (AFDC) (.07) (.21)
Operation and maintenance expenses (.05) (.07)
Taxes, other than income taxes (.04) (.11)
Interest expense - (.04)
Other - (.05)
----- -----
1996 earnings $ .99 $2.48
===== =====
The increases in revenues reflect retail rate increases and
changes in kilowatt-hour (kWh) sales to ultimate customers. KWh
sales to ultimate customers decreased in the third quarter by 1.3
percent reflecting a cooler summer in 1996, partially offset by an
improving regional economy. KWh sales to ultimate customers
increased for the nine month period by 1.8 percent also reflecting
an improving regional economy. For a discussion of other items
affecting earnings, see the "Operating Revenue" and "Operating
Expenses" sections.
Competitive Conditions
- ----------------------
The electric utility business is being subjected to rapidly
increasing competitive pressures, stemming from a combination of
trends, including the presence of surplus generating capacity, a
disparity in electric rates among regions of the country,
improvements in generation efficiency, 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, 1995.
In states across the country, including the New England states,
there have been an increasing number of proposals to allow retail
customers to choose their electricity supplier, with incumbent
utilities required to deliver that electricity over their
transmission and distribution systems (also known as "retail
wheeling"). In these competitive circumstances, utilities across
the country that operate generation plants, such as New England
Power Company (NEP), face the risk that market prices may not be
sufficient to recover the costs of the commitments incurred to
supply customers under a regulated industry structure. The amount
by which costs exceed market prices is commonly referred to as
"stranded costs".
Massachusetts Settlement Agreement
In May 1996, the Massachusetts Department of Public Utilities
(MDPU) issued a set of proposed rules and regulations governing the
implementation of retail choice in Massachusetts. The proposed
rules would allow all customers of Massachusetts investor-owned
utilities to choose their electricity supplier beginning in 1998
and would establish a price cap system for regulating the rates for
distribution service that would continue to be provided by local
utilities. The MDPU proposed rules affirm the principle of
stranded cost recovery for utilities over ten years, but create
uncertainties concerning the extent of actual stranded cost
recovery. While the MDPU did not order mandatory divestiture of
generating assets, it stated that it might provide utilities
financial incentives to divest. The MDPU has stated that it will
issue final regulations by year-end 1996 and issue orders on
individual utility plans in 1997.
On October 1, 1996, Massachusetts Electric Company
(Massachusetts Electric) and NEP, together with the Massachusetts
Attorney General, the Massachusetts Division of Energy Resources
and other parties, filed a comprehensive settlement agreement with
the MDPU. The settlement agreement provides for the commencement
of retail choice on January 1, 1998 (contingent on choice being
available to the customers of all Massachusetts investor-owned
utilities), full compensation for potential stranded costs, and the
full divestiture of the NEES companies' fossil and hydroelectric
generating business. Under the settlement agreement, customers who
do not choose an alternative supplier would receive "Standard Offer"
service, which would be priced to guarantee customers at least a 10
percent savings in 1998 from current electricity prices, therefore
resulting in revenue losses for Massachusetts Electric.
Under the settlement agreement, NEP's wholesale contract with
Massachusetts Electric would be terminated. In return, the cost of
NEP's past generation commitments to serve Massachusetts Electric's
customers (estimated at approximately $3 billion) would be
recovered through a transition access charge on retail distribution
rates. Those commitments consist of (i) generating plant
commitments, (ii) regulatory assets, (iii) the above-market
component of purchased power contracts, and (iv) the operating cost
of nuclear plants which cannot be mitigated by shutting down the
plants, including nuclear decommissioning.
Sunk costs associated with generating plants and regulatory
assets would be recovered over a period of 12 years, based on an
initial return on equity of 9.4 percent. As the transition access
charge declines, NEP would earn mitigation incentives which would
supplement its return on equity on sunk costs above the initial 9.4
percent during the 12 year transition period. The incentives are
designed such that NEP believes it could earn a return on equity on
sunk costs of 11 percent. The above-market component of purchased
power contracts and nuclear decommissioning costs would be
recovered as incurred over the life of those obligations, a period
expected to extend beyond 12 years. The transition access charge
would be reduced to reflect the net proceeds from the sale of the
NEES companies' generating assets. The initial transition access
charge, before the application of those proceeds, would be set at
2.8 cents per kWh through December 31, 2000, and is expected to
decline thereafter.
The settlement agreement requires the NEES companies to file
a divestiture plan for the generating business with the MDPU by
July 1, 1997. The NEES companies must complete the divestiture of
its generating business within six months of the later of the
commencement of retail access in Massachusetts or the receipt of
all necessary regulatory approvals. In addition to NEP's fossil
and hydroelectric generation operations, the properties to be
divested include oil and gas properties owned by New England Energy
Inc. (NEEI), and The Narragansett Electric Company's (Narragansett)
ownership interest in the Manchester Street Station.
As part of the divestiture plan, NEP would endeavor to sell or
otherwise transfer its minority interest in four nuclear power
plants to nonaffiliates. NEP may retain responsibility for
decommissioning and related expenses if necessary. To the extent
that the NEES companies are unable to divest their nuclear
generating interests, the settlement agreement provides for an 80
percent/20 percent sharing between customers and shareholders of
the revenues associated with the nuclear interests and the costs
not otherwise reflected in the transition access charge.
The settlement agreement also establishes performance-based
rates for Massachusetts Electric. Under the plan, Massachusetts
Electric's non-fuel rates would be frozen at current levels until
the commencement of retail choice. Upon commencement of retail
choice, Massachusetts Electric would receive an approximately $45
million increase in its distribution rates, with such rates then
frozen through the year 2000. Massachusetts Electric's return on
equity would be subject to a floor of 6 percent and a ceiling of 11
percent, effective upon commencement of retail choice. Earnings
over the ceiling would be shared equally between customers and
shareholders up to an absolute cap of 12.5 percent. To the extent
that earnings fall below the floor, Massachusetts Electric would be
authorized to surcharge customers for the shortfall. In addition,
the settlement agreement provides for changes to the distribution
cost of service that become effective on the retail access date.
These changes include: an $11 million increase in annual
depreciation expense, a $3 million annual contribution to a storm
fund, and increased amortization of unfunded deferred income taxes
of $1 million over six years.
The settlement agreement, when approved, would also eliminate
Massachusetts Electric's purchased power cost adjustment mechanism
(PPCA) as of July 31, 1996. This mechanism allows Massachusetts
Electric to recover purchased power rate changes from NEP and the
effects of NEP's seasonal rates. The agreement also stipulates
that Massachusetts Electric's $18 million PPCA refund liability
balance at July 31, 1996 will be used to create a $3 million storm
contingency fund with the remainder being used to offset regulatory
assets for hazardous waste costs.
The MDPU, with the agreement of the parties, has set a
procedural schedule under which it will issue a decision on the
settlement agreement by January 10, 1997. The settlement agreement
is also subject to approval by the Federal Energy Regulatory
Commission (FERC). Additional governmental approvals would be
required for the divestiture of the generating business. In
addition, the implementation of retail choice in Massachusetts may
be the subject of legislation from the Massachusetts legislature.
Rhode Island Legislation
On August 7, 1996, the Governor of Rhode Island signed into law
legislation that will restructure the electric utility industry in
Rhode Island. Rhode Island is the first state to pass
comprehensive legislation providing retail customers with access to
alternative suppliers and providing utilities with recovery of
their stranded investments. The NEES companies supported this
legislation which affects NEP and Narragansett.
The legislation allows all customers of electric utilities to
choose their power supplier under a phased-in approach, while
transmission and distribution rates will remain regulated. This
phase-in will begin on July 1, 1997 for customers representing
approximately 10 percent of Narragansett's load, followed by
another 10 percent on January 1, 1998, and the balance of customers
on July 1, 1998. All Rhode Island customers would have choice of
supplier beginning January 1, 1998 if retail access is available to
40 percent or more of the kWh sales in New England by that date.
Rhode Island customers will likely receive substantial savings in
a competitive market, which will therefore result in revenue losses
for Narragansett.
Under the new law, NEP's wholesale contract with Narragansett
will be terminated. In return, the cost of NEP's past generation
commitments to serve Narragansett's customers (estimated at
approximately $1 billion) will be recovered through a transition
access charge on retail distribution rates similar to that
contained in the Massachusetts settlement agreement. Under the
Rhode Island legislation, the return on equity is initially set at
one percentage point over the interest rate on long-term "BBB" rated
utility bonds. Once the transition access charge is adjusted to
reflect the market valuation of the non-nuclear generating plants,
the return on equity will be retroactively increased to 11 percent.
The legislation also establishes performance-based rates for
distribution utilities, such as Narragansett. Under the
legislation, Narragansett will be entitled to increase its
distribution rates by approximately $10 million in 1997 and another
$10 million in 1998. In addition, in 1996 and 1997, Narragansett's
return on equity from distribution operations will be subject to a
floor of 6 percent and a ceiling of 11 percent. Earnings over the
ceiling will be shared equally between customers and shareholders
up to an absolute cap on return on equity from distribution
operations of 12.5 percent. To the extent that earnings fall below
the floor, Narragansett will be authorized to surcharge customers
for the shortfall.
Implementation of various aspects of the Rhode Island
legislation is subject to Rhode Island Public Utilities Commission
and FERC approval.
New Hampshire Proceedings
In September 1996, the New Hampshire Public Utilities
Commission issued a preliminary restructuring plan for the electric
utility industry in New Hampshire. The stated goals of the
preliminary plan include encouraging the divestiture of generation
assets and the recovery of some stranded costs through an interim
non-bypassable transition charge. Recoverable stranded costs would
be determined on a utility specific basis. The amount of recovery
could be tied to the amount by which a utility's rates exceed the
regional average electricity rate. Utilities with rates at or
below the regional average could be entitled to greater recovery of
stranded costs. Utility-specific interim stranded cost recovery
hearings are scheduled for December 1996. A final plan is expected
to be issued in February 1997.
FERC Order
In April 1996, the FERC issued Order No. 888 addressing open
access transmission and required those utilities that own
transmission facilities to file open access tariffs to make
available transmission service to affiliates and nonaffiliates at
fair non-discriminatory rates. Order No. 888 also stated that
public utilities will be allowed to seek recovery of legitimate and
verifiable stranded costs from departing customers as a result of
wholesale competition. The FERC indicated that it will provide for
the recovery of retail stranded costs only if state regulators lack
the legal authority to address those costs at the time retail
wheeling is required. The FERC also stated that it would permit
stranded cost recovery under wholesale requirements contracts, such
as the contracts between NEP and its retail affiliates.
On July 9, 1996, NEP filed a transmission tariff with the FERC
that conforms with the requirements of Order No. 888. This tariff
became effective immediately upon filing, subject to refund. The
implementation of the tariff is not expected to have a significant
impact on NEP's revenues.
Accounting Implications
Historically, electric utility rates have 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 Standards
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 NEES companies
believe that, if approved by regulators, the Massachusetts
settlement agreement and the Rhode Island legislation would meet
the criteria for continued application of FAS 71 to NEES's
remaining regulated utility operations, including the recovery of
stranded costs. As a result, no write-off of existing regulatory
assets is expected and any loss from the divestiture of NEES's
generating business would be recorded as a regulatory asset.
Risk Factors
For a discussion of risk factors in the event that the
Massachusetts settlement agreement is not approved and FERC
approval of implementation of the Rhode Island legislation does not
occur, see "Risk Factors" in the Company's Form 10-Q for the quarter
ended June 30, 1996.
Investments in Nuclear Units
- ----------------------------
Connecticut Yankee
NEP has a 15 percent equity ownership interest in Connecticut
Yankee Atomic Power Company (Connecticut Yankee) which owns a 580
megawatt (MW) nuclear generating plant. At September 30, 1996,
NEP's net investment in Connecticut Yankee was $16 million.
Subsidiaries of Northeast Utilities (NU) own 49 percent of
Connecticut Yankee. The Connecticut Yankee station has been shut
down since July 22, 1996, after a potential problem with its
cooling system was identified. Since that time, the Nuclear
Regulatory Commission (NRC) has identified additional weaknesses
and deficiencies which have to be addressed before the plant can
restart. On September 3, 1996, the NRC sent an inspection team to
Connecticut Yankee to investigate two unrelated events occurring at
the plant while it was shut down. On October 9, 1996, the owners
of Connecticut Yankee announced that permanent shutdown of the
plant was likely. The announcement was made based on an economic
analysis comparing the incremental costs associated with operating
and maintaining the plant with the expected value of the plant's
output. A final decision by the Connecticut Yankee board of
directors is expected in the near future. In the event the plant
is permanently shut down, Connecticut Yankee's estimated billings
to NEP, including decommissioning of the plant, is currently
estimated to be approximately $120 million and is subject to FERC
approval. These costs would be recorded as an accrued liability
with an offsetting regulatory asset in the expectation that the
costs would be recoverable from customers. (See "Competitive
Conditions" section.) In the event of restart, costs in the range
of at least $40 million would be required to address corrective
actions at Connecticut Yankee. NEP's share of these costs would be
at least $6 million.
Millstone 3
NEP is a 12 percent joint owner of the Millstone 3 nuclear
generating unit (Millstone 3), a 1,150 MW unit. Millstone 3 is
operated by a subsidiary of NU. In March 1996, the Millstone 3
unit was shut down as a result of an internal safety review. In
April 1996, the NRC ordered Millstone 3 to remain shut down pending
verification that the unit's operations are in accordance with NRC
regulations and the unit's operating license. NEP is not a joint
owner of the Millstone 1 and 2 nuclear generating units, which are
also shut down under NRC orders.
The NRC has classified the Millstone units as Category 3
facilities on the NRC "watch list". The NRC deems Category 3 plants
as having significant weaknesses that require them to remain shut
down until it is demonstrated that adequate programs have been
established and implemented to ensure substantial improvement. On
August 6, 1996, the NRC Chairman described problems at the
Millstone units as pervasive and indicated that a culture change is
required. The NRC Chairman has also announced that independent
verification of corrective actions taken at the units will be
required prior to restart. On October 18, 1996, the NRC
established a Special Projects Office to oversee inspection and
licensing activities at Millstone. The NRC expects the office to
be in operation for 18 to 24 months. A vote of the NRC
Commissioners is required prior to restart of the units. NEP
cannot predict when Millstone 3 will be allowed by the NRC to
restart, but believes that the unit will remain shut down for a
very protracted period.
NEP has an accrued liability of approximately $7 million at the
end of the third quarter of 1996 for its share of the currently
estimated future incremental operation and maintenance costs
related to corrective actions at the Millstone 3 unit. Additional
costs may be incurred beyond those already recognized. During the
outage, NEP is incurring approximately $1.5 million per month in
replacement power costs, which it has been recovering from
customers through its fuel clause.
Maine Yankee
NEP has a 20 percent equity ownership interest in Maine Yankee
Atomic Power Company (Maine Yankee) which owns an 880 MW nuclear
generating station. Maine Yankee is currently operating at 90
percent power until the NRC authorizes operation at a higher level.
As previously reported, the NRC is investigating allegations that
inadequate analyses of the plant's emergency core cooling system
were performed. In September 1996, the NRC asked the Department of
Justice to review an NRC investigatory report on the allegations.
Maine Yankee was also subject to an NRC independent safety
assessment. On October 7, 1996, the NRC staff issued its report,
which concluded that overall performance at Maine Yankee was
considered adequate for operation. However, the report identified
a number of weaknesses and deficiencies. Maine Yankee must respond
by December 10, 1996 to the report with its plans for resolving the
deficiencies. It is not known when, or if, the Maine Yankee plant
will be allowed to return to maximum capacity or how much of an
investment might be required to correct the deficiencies.
General
On October 9, 1996, the NRC issued letters to all nuclear power
plants requiring them to submit documentation showing that the
plants are operated and maintained within their design basis, and
any deviations are reconciled in a timely manner. The Seabrook 1,
Maine Yankee, and Vermont Yankee nuclear power plants, in which NEP
owns 10 percent, 20 percent, and 20 percent interests,
respectively, will all be required to respond to the NRC letters by
February 1997.
In general, it is unknown what the total ultimate impact of the
increased NRC scrutiny on the nuclear plants mentioned above will
have on NEP's operations and costs.
Brayton Point
- -------------
On October 22, 1996, the Environmental Protection Agency (EPA)
announced it was beginning a process to revoke NEP's water
discharge permit for its Brayton Point 1,538 MW power plant
(Brayton Point). This action comes two years before the permit
expiration date. The EPA expects to work with NEP and other
interested parties, including the states of Rhode Island and
Massachusetts, to recommend new permit requirements within 60 days.
Brayton Point will continue to operate under the terms of its
existing permit until permit modifications are made or a revised
permit is issued. The EPA stated it took the action in response to
environmental concerns regarding the plant's thermal discharges.
NEP cannot predict at this time what permit changes will be
required or the impact on plant operations and economics.
Operating Revenue
- -----------------
The following table summarizes the changes in operating
revenue:
Increase (Decrease) in Operating Revenue
Third Quarter Nine Months
------------- ------------
1996 vs 1995 1996 vs 1995
------------- ------------
(In Millions)
Sales growth $(6) $ 18
Retail rate increases 11 33
Rate adjustment mechanisms (4) (18)
Fuel recovery 24 50
Accrued NEEI revenues (4) (14)
Demand side management (DSM)
program recovery (4) (5)
Other 1 (1)
--- ----
$18 $ 63
=== ====
For a discussion of kWh sales to ultimate customers, see the
"Earnings" section.
Retail rate increases for the third quarter and nine months
ended September 30, 1996 reflect a Massachusetts Electric $31
million base rate increase effective in October 1995, a
Narragansett $12 million base rate increase effective in December
1995, and a Granite State Electric Company $1 million increase
effective in November 1995. Rate adjustment mechanisms include
true-ups for the pass-through of purchased power billings between
NEP and the retail companies as well as certain rate-related
adjustments recorded by NEP.
For a discussion of fuel recovery see the fuel costs discussion
in the "Operating Expenses" section.
Accrued NEEI fuel revenues reflect losses incurred by NEEI on
its rate-regulated oil and gas operations. These revenues are
accrued in the year of loss, but are billed to customers through
NEP's fuel adjustment clause in the following year. The decrease
in NEEI losses in the quarter and nine months is principally due to
increased gas prices as well as a reduced level of production.
Operating Expenses
- ------------------
The following table summarizes the changes in operating
expenses:
Increase (Decrease) in Operating Expenses
Third Quarter Nine Months
------------- ------------
1996 vs 1995 1996 vs 1995
------------- ------------
(In Millions)
Fuel costs $24 $ 54
Purchased energy, excluding fuel (3) (29)
Operation and maintenance
Retail DSM (4) (4)
Other 5 7
Depreciation and amortization:
Seabrook 1 and OCA amortization - (12)
Depreciation, including
Manchester Street 4 13
Oil and gas properties (3) (10)
Taxes, other than income taxes 4 11
Income taxes (4) 7
--- ----
$23 $ 37
=== ====
Fuel costs represent fuel for generation and the portion of
purchased electric energy permitted to be recovered through NEP's
fuel adjustment clause. The increases in fuel costs in the third
quarter and first nine months of 1996 primarily reflect additional
fixed pipeline demand charges due to the completion of the
Manchester Street repowering project in the second half of 1995,
the amortization of pipeline demand charges deferred during the
project's construction period, and increased generation supplied to
other utilities. In addition, the nine-month period reflects
increased kWh sales.
The portion of purchased electric energy costs not recovered
through NEP's fuel clause is shown as purchased energy, excluding
fuel. The decrease in purchased power costs, excluding fuel, for
the third quarter and nine-month period reflects reductions in
purchases under certain long-term power contracts. Purchased power
costs in the first six months of 1995 also included NEP's portion
of the incremental costs to repair steam generator tubes at Maine
Yankee. Purchased power costs from other power suppliers also
decreased in the first six months but increased in the third
quarter primarily due to the timing of overhauls and refueling
shutdowns.
The increase in operation and maintenance expenses for the
third quarter and nine-month periods include costs associated with
NEP's joint ownership interest in the Millstone 3 nuclear
generating unit. These costs reflect NEP's portion of currently
estimated incremental costs to correct deficiencies at the unit.
The increase also reflects higher customer service expenses for
both periods. Partially offsetting the increase in operation and
maintenance expenses was decreased overhaul activity at NEP's
fossil and hydroelectric generating units in the first nine months
of 1996.
The decrease in Seabrook 1 and OCA amortization reflects the
completion in mid-1995 of the amortization of a portion of Seabrook
1 costs and certain coal conversion costs. These decreases were
partially offset by increased depreciation of other utility plant,
including the Manchester Street Station.
The increase in taxes, other than income taxes in 1996 is due
to increased property taxes, including taxes on the Manchester
Street Station.
Allowance For Funds Used During Construction
- --------------------------------------------
AFDC decreased for the third quarter and first nine months of
1996 due to the completion of the Manchester Street Station
repowering project in 1995.
Liquidity and Capital Resources
- -------------------------------
Plant expenditures in the first nine months of 1996 amounted to
$181 million for the utility subsidiaries. The funds necessary for
utility plant expenditures were provided by net cash from operating
activities, after the payment of dividends.
The financing activities of NEES subsidiaries for the first
nine months of 1996 are summarized as follows:
Issues Retirements
------ -----------
(In Millions)
Long-term debt
- --------------
Nantucket Electric Company (Nantucket) $28
NEP 40 $50
Narragansett 2 2
Hydro-Transmission Companies 9
Narragansett Energy Resources
Company 1
NEEI 26
--- ---
$70 $88
=== ===
In July 1996, Nantucket issued $28 million of long-term
tax-exempt debt at rates ranging from 4.10 percent to 6.75 percent
to fund construction of an undersea cable. Massachusetts Electric
guaranteed the debt on behalf of Nantucket. NEP refinanced $40
million of variable rate mortgage bonds and Narragansett refinanced
$2 million of long-term debt at an interest rate of 7.24 percent in
the first nine months of 1996. The retail subsidiaries plan to
issue an additional $30 million of long-term debt by the end of
1996. In addition, NEP plans to refinance $8 million of variable
rate debt in the fourth quarter of 1996.
In August 1996, NEP repurchased $6 million of its 4.64 percent
series of cumulative preferred stock. In May 1996, NEP redeemed
all ($15 million) of its 7.24 percent series of cumulative
preferred stock.
NEP has approximately $740 million of mortgage bonds
outstanding. The bond indenture terms restrict the sale of the
trust property in its entirety or substantially in its entirety.
Therefore, the proposed sale of NEP's generating business would
likely require that NEP either amend the bond indenture terms or
defease the indenture and the bonds in connection with the proposed
sale. Any defeasance of bonds is expected to be either to maturity
or at general redemption prices. See "Competitive Conditions"
section.
Net cash from operating activities provided all of the funds
for oil and gas expenditures for the first nine months of 1996.
NEEI capitalized oil and gas exploration and development costs of
$13 million in the first nine months of 1996 which includes
approximately $5 million of capitalized interest costs.
At September 30, 1996, NEES and its consolidated subsidiaries
had available lines of credit and standby bond purchase facilities
with banks totaling $715 million. These lines and facilities were
used for liquidity support for $153 million of commercial paper
borrowings and for $372 million of NEP mortgage bonds in tax-exempt
commercial paper mode. Fees are paid on the lines and facilities
in lieu of compensating balances.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
- --------------------------
Information concerning restructuring dockets before state and
federal regulatory agencies, discussed in Part I of this report in
Management's Discussion and Analysis of Financial Condition and
Results of Operations, is incorporated herein by reference and made
a part hereof.
On July 11, 1996, various New England utilities that are
members of NEPOOL, including New England Power Company (NEP),
submitted a dispute to arbitration regarding their Firm Energy
Purchased Power Contract with Hydro-Quebec. The dispute concerns
the components of a pricing formula. Based on NEP's interpretation
of Hydro-Quebec's claims, NEP's share of additional billings owed
to Hydro-Quebec would be approximately $3.5 million on a
retroactive basis and an estimated $3.8 million per year on a
prospective basis through 2001. On October 18, 1996, NEP and other
New England utilities who are parties to the Firm Energy Contract
filed a motion to dismiss Hydro-Quebec's claims. A decision on the
motion is expected by December of this year.
Item 6. Exhibits and Reports on Form 8-K
- -----------------------------------------
The Company filed reports on Form 8-K dated September 12,
1996, September 18, 1996, and October 1, 1996, all containing Item
5, Other Events.
The Company is filing Financial Data Schedules.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report on Form 10-Q for
the quarter ended September 30, 1996 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: November 8, 1996
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.