<PAGE> 1
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[ x ] Quarterly report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the quarterly period ended September 30, 1999
or
[ ] Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from __________ to __________
Commission file number 1-14768
NSTAR
(Exact name of registrant as specified in its charter)
Massachusetts 04-3466300
- ------------- ----------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
800 Boylston Street, Boston, Massachusetts 02199
- ------------------------------------------ -----
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 617-424-2000
------------
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
----- -----
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding at November 8, 1999
- ----- -------------------------------
Common Shares, $1 par value 60,142,371 shares
<PAGE> 2
Part I - Financial Information
Item 1. Financial Statements
- -----------------------------
<TABLE>
NSTAR
Consolidated Statements of Income
(Unaudited)
(in thousands, except per share amounts)
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
1999 1998 1999 1998
-------- -------- ---------- ----------
<S> <C> <C> <C> <C>
Operating revenues $517,151 $479,897 $1,268,311 $1,259,363
-------- -------- ---------- ----------
Operating expenses:
Fuel, purchased power and
cost of gas sold 213,223 154,784 510,920 424,914
Operations and maintenance 93,050 90,868 243,999 276,533
Depreciation and amortization 56,609 47,280 151,797 147,392
Demand side management and
renewable energy programs 15,507 20,002 42,208 37,044
Taxes - property and other 17,228 18,063 57,176 70,938
Income taxes 36,512 48,596 74,791 87,904
-------- -------- ---------- ----------
Total operating expenses 432,129 379,593 1,080,891 1,044,725
-------- -------- ---------- ----------
Operating income 85,022 100,304 187,420 214,638
Other income (expense), net 17,012 (4,995) 13,643 (10,959)
-------- -------- ---------- ----------
Operating and other income 102,034 95,309 201,063 203,679
-------- -------- ---------- ----------
Interest charges:
Transition property
securitization bonds 8,439 0 8,439 0
Long-term debt 19,693 19,457 58,594 63,489
Other 6,091 772 11,324 8,494
Allowance for borrowed funds
used during construction (449) (410) (1,368) (975)
-------- -------- ---------- ----------
Total interest charges 33,774 19,819 76,989 71,008
-------- -------- ---------- ----------
Net income 68,260 75,490 124,074 132,671
Preferred stock dividends of
subsidiary 1,490 1,486 4,470 7,275
-------- -------- ---------- ----------
Earnings available for common
shareholders $ 66,770 $ 74,004 $ 119,604 $ 125,396
======== ======== ========== ==========
Weighted average common shares
outstanding:
Basic 50,674 47,691 47,811 48,239
====== ====== ====== ======
Diluted 50,922 47,859 47,963 48,387
====== ====== ====== ======
Earnings per common share:
Basic $1.32 $1.55 $2.50 $2.60
===== ===== ===== =====
Diluted $1.31 $1.55 $2.49 $2.59
===== ===== ===== =====
Dividends declared per common
share $0.485 $0.47 $1.455 $1.41
====== ===== ====== =====
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
<PAGE> 3
<TABLE>
Consolidated Statements of Comprehensive Income
(Unaudited)
(in thousands)
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
1999 1998 1999 1998
-------- -------- ---------- ----------
<S> <C> <C> <C> <C>
Net income $ 68,260 $ 75,490 $ 124,074 $ 132,671
Other comprehensive income, net:
Unrealized gain (loss) on
investments (1,704) 0 15,229 0
-------- -------- ---------- ----------
Comprehensive income $ 66,556 $ 75,490 $ 139,303 $ 132,671
======== ======== ========== ==========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
<PAGE> 4
<TABLE>
NSTAR
Consolidated Balance Sheets
(Unaudited)
(in thousands)
<CAPTION>
September 30, December 31,
1999 1998
------------- ------------
<S> <C> <C>
Assets
- ------
Utility plant in service, at original cost $3,774,346 $2,720,681
Less: accumulated depreciation 1,288,132 926,020
---------- ----------
2,486,214 1,794,661
Construction work in progress 53,581 40,965
---------- ----------
Net utility plant 2,539,795 1,835,626
Nonutility property 105,958 21,565
Goodwill 476,950 0
Nuclear decommissioning trust 0 172,908
Equity investments 166,099 84,770
Other investments 59,526 30,206
Restricted cash long-term 119,724 0
Current assets:
Cash and cash equivalents 81,923 89,126
Restricted cash 53,389 0
Accounts receivable 460,710 202,275
Accrued unbilled revenues 25,640 14,322
Fuel, materials and supplies, at average cost 48,212 10,731
Prepaid expenses and other 144,459 102,448
---------- ----------
Total current assets 814,333 418,902
---------- ----------
Regulatory assets:
Generation-related regulatory asset, net 626,813 477,317
Power contracts 100,365 58,415
Income taxes, net 81,877 52,168
Merger costs 77,602 0
Redemption premiums 17,515 23,419
Postretirement benefits costs 80,156 0
Other 95,316 1,825
---------- ----------
Total regulatory assets 1,079,644 613,144
Other deferred debits 84,069 26,915
---------- ----------
Total assets $5,446,098 $3,204,036
========== ==========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
<PAGE> 5
<TABLE>
NSTAR
Consolidated Balance Sheets
(Unaudited)
(in thousands)
<CAPTION>
September 30, December 31,
1999 1998
------------- ------------
<S> <C> <C>
Capitalization and Liabilities
- ------------------------------
Common equity:
Common shares, par value $1 per share
(61,164,479 and 47,184,073 shares issued
and outstanding) $ 61,164 $ 47,184
Premium on common stock 1,193,019 644,205
Retained earnings 403,203 360,509
Accumulated other comprehensive income, net 15,229 0
---------- ----------
Total common equity 1,672,615 1,051,898
---------- ----------
Cumulative preferred stock of subsidiary:
Nonmandatory redeemable series 43,000 43,000
Mandatory redeemable series 49,220 49,040
---------- ----------
Total preferred stock 92,220 92,040
---------- ----------
Transition property securitization bonds 646,558 0
Long-term debt 980,930 955,563
---------- ----------
Total capitalization 3,392,323 2,099,501
---------- ----------
Current liabilities:
Transition property securitization bonds
due within one year 68,561 0
Long-term debt due within one year 181,639 667
Notes payable 233,175 78,000
Accounts payable 179,537 100,331
Accrued interest 22,659 20,516
Dividends payable 30,237 23,878
Other 292,764 183,664
---------- ----------
Total current liabilities 1,008,572 407,056
---------- ----------
Deferred credits:
Accumulated deferred income taxes 578,870 348,557
Accumulated deferred investment tax credits 42,278 45,930
Nuclear decommissioning liability 0 176,578
Power contracts 100,365 58,415
Other 323,690 67,999
---------- ----------
Total deferred credits 1,045,203 697,479
Commitments and contingencies __________ __________
Total capitalization and liabilities $5,446,098 $3,204,036
========== ==========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
<PAGE> 6
<TABLE>
NSTAR
Consolidated Statements of Cash Flows
(Unaudited)
(in thousands)
<CAPTION>
Nine Months Ended September 30,
1999 1998
--------- ---------
<S> <C> <C>
Operating activities:
Net income $ 124,074 $ 132,671
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization 152,104 180,409
Deferred income taxes and investment tax credits 46,980 (149,710)
Allowance for borrowed funds used during
construction (1,420) (976)
Power contract buyout (65,781) 0
Changes (net of effect of acquisition) in:
Accounts receivable and accrued unbilled revenues (164,062) (42,365)
Fuel, materials and supplies (1,665) 27,819
Accounts payable 14,793 48,096
Other current assets and liabilities (52,364) 9,906
Other, net 76,257 36,126
--------- ---------
Net cash provided by operating activities 128,916 241,976
--------- ---------
Investing activities:
Plant expenditures (excluding AFUDC) (94,914) (78,890)
Costs of nuclear divestiture, net (127,061) 0
Proceeds from sale of fossil generating assets 0 533,633
Nuclear fuel expenditures (16,117) (11,141)
Investments (77,219) (62,876)
Payment for acquisition, net of cash acquired (295,535) 0
--------- ---------
Net cash (used in) provided by investing activities (610,846) 380,726
--------- ---------
Financing activities:
Proceeds from transition property securitization 725,000 0
Common share repurchases (68,698) (124,804)
Long-term debt redemptions (225,376) (201,600)
Net change in notes payable 115,725 (77,013)
Dividends paid (71,924) (76,580)
--------- ---------
Net cash provided by (used in) financing activities 474,727 (479,997)
--------- ---------
Net (decrease) increase in cash and cash equivalents (7,203) 142,705
Cash and cash equivalents at beginning of year 89,126 4,140
--------- ---------
Cash and cash equivalents at end of period $ 81,923 $ 146,845
========= =========
Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest, net of amounts capitalized $ 80,580 $ 79,660
========= =========
Income taxes $ 16,722 $ 182,258
========= =========
Supplemental noncash investing activity:
Issuance of common shares for business acquired 20,251 0
========= =========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
<PAGE> 7
Notes to Unaudited Consolidated Financial Statements
- ----------------------------------------------------
A) Merger of BEC Energy and Commonwealth Energy System
---------------------------------------------------
On August 25, 1999, BEC Energy (BEC) and Commonwealth Energy System
(COM/Energy) completed a merger transaction to create a new holding company,
NSTAR, an energy delivery company serving approximately 1.3 million customers
in Massachusetts including more than one million electric customers in 81
communities and 240,000 gas customers in 51 communities. NSTAR is an exempt
public utility holding company under the provisions of the Public Utility
Holding Company Act of 1935. NSTAR's utility subsidiaries include Boston
Edison Company, Commonwealth Electric Company, Cambridge Electric Light
Company, Canal Electric Company and Commonwealth Gas Company. NSTAR's
nonutility operations include telecommunications, district heating and cooling
operations, liquefied natural gas services and five real estate trusts.
The merger is being accounted for as an acquisition of COM/Energy by BEC using
the purchase method of accounting. Under this method, the accompanying
unaudited consolidated financial statements of NSTAR include results of BEC
for the entire period presented consolidated with those of COM/Energy from the
date of the merger. Goodwill amounted to approximately $478 million while the
original estimate of costs to achieve the merger was $111 million. The annual
amortization of goodwill will be approximately $11.9 million while the cost to
achieve amortization will initially be approximately $11.1 million annually.
The ultimate amortization of the cost to achieve will reflect the total actual
costs.
Based on unaudited data, the following pro forma summary presents the
consolidated results of operations for the nine months ended September 30,
1999 and the year ended December 31, 1998 as if the merger had occurred at the
beginning of the years presented. These results do not reflect future cost
savings or avoidances expected from the merger.
<TABLE>
(in thousands, except per share amounts)
<CAPTION>
Nine Months Twelve Months
Ended September 30, Ended December 31,
1999 1998
------------------- ------------------
<S> <C> <C>
Revenues $1,842,767 $2,537,903
Earnings available for
common shareholders $110,888 $166,535
Weighted average common shares
Basic 61,800 63,689
Diluted 61,933 63,763
Earnings per common share
Basic $1.79 $2.61
Diluted $1.79 $2.61
</TABLE>
The pro forma results do not purport to be indicative of the results of
operations that actually would have resulted had the merger occurred at the
beginning of the year presented, or of results that may occur in the future.
<PAGE> 8
B) Basis of Presentation
---------------------
In May 1998, Boston Edison completed its reorganization plan to form a holding
company, BEC Energy (BEC), with Boston Edison becoming a wholly owned
subsidiary of BEC. Under the holding company structure the owners of Boston
Edison's common stock became BEC common shareholders. Existing debt and
preferred stock of Boston Edison remained obligations of Boston Edison.
Effective June 25, 1998, Boston Energy Technology Group (BETG) ceased being a
subsidiary of Boston Edison and became a wholly owned subsidiary of BEC.
Therefore, the 1998 consolidated financial statements reflect the results of
operations and cash flows of Boston Edison prior to the reorganization.
The accompanying unaudited consolidated financial statements should be read in
conjunction with the BEC 1998 Annual Report on Form 10-K/A and quarterly
reports on Form 10-Q for the periods ended March 31, 1999 and June 30, 1999.
The financial information presented as of and for the periods ended
September 30 has been prepared from NSTAR's books and records without audit by
independent accountants. Financial information as of December 31 has been
derived from the audited financial statements of BEC, but does not include all
disclosures required by generally accepted accounting principles (GAAP). In
the opinion of NSTAR's management, all adjustments (which are of a normal
recurring nature) necessary for a fair presentation of the financial
information for the periods indicated have been included. Certain
reclassifications have been made to the prior year data to conform with the
current presentation.
The preparation of financial statements in conformity with GAAP requires NSTAR
and its subsidiaries to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosures of contingent
assets and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting period. Actual
results could differ from these estimates.
The results of operations for the three-month and nine-month periods ended
September 30, 1999 and 1998 are not indicative of the results which may be
expected for an entire year. Kilowatt-hour sales and revenues are typically
higher in the winter and summer than in the spring and fall as sales tend to
vary with weather conditions. Gas sales and revenues are typically higher in
the winter months than during other periods of the year.
C) Pilgrim Nuclear Power Station
-----------------------------
Under Boston Edison's approved restructuring settlement agreement
approximately 75% of the net assets of Pilgrim Nuclear Power Station (Pilgrim)
are recoverable through a non-bypassable transition charge of the utility's
distribution business. All Boston Edison distribution customers must pay a
transition charge as a component of distribution electric rates. The purpose
of the transition charge is to allow Boston Edison to collect costs from
customers that would not be collected in the competitive energy supply market.
The distribution and transmission businesses continue to be subject to rate-
regulation. This Pilgrim regulatory asset is included in the generation-
related regulatory asset-net on the consolidated balance sheet.
<PAGE> 9
On July 13, 1999, Boston Edison completed the sale of Pilgrim Nuclear
Generating Station to Entergy Nuclear Generating Company, a subsidiary of
Entergy Corporation, for $81 million. In addition to the amount received from
Entergy, Boston Edison will also receive a total of approximately $243 million
from the wholesale contract customers (including $105 million received from
Commonwealth Electric Company, an affiliate of Boston Edison) to terminate
their contracts and to release them from all future liabilities. As part of
the sale, Boston Edison transferred its decommissioning trust fund to Entergy,
and was released from all future liability related to the ultimate
decommissioning of the plant. In order to provide Entergy with a fully funded
decommissioning trust fund, Boston Edison contributed approximately $271
million to the fund at the time of the sale. As a result of a favorable IRS
tax ruling, Boston Edison received $43 million from Entergy reflecting a
reduction in the required decommissioning funding in the fourth quarter. The
difference between the total proceeds received and the net book value of the
Pilgrim assets sold plus the net amount to fully fund the decommissioning
trust will be included in the balance of generation-related regulatory asset-
net on the consolidated balance sheet as such amounts are being collected from
customers under Boston Edison's settlement agreement. The final amounts to be
collected from customers related to Pilgrim are subject to regulatory review.
Three municipal light departments had previously filed for separate claims
alleging that the sale of Pilgrim constituted a breach of their respective
power sale agreements. Boston Edison has reached a settlement in principle
with all fourteen municipal customers of Pilgrim. This settlement, subject to
Federal Energy Regulatory Commission (FERC) approval, will terminate the
purchase power agreements between Boston Edison and the municipal light
departments and dispose of all disputes, including previously filed
arbitration claims, regarding the sale of Pilgrim to Entergy and the power
sale agreements.
D) Securitization
--------------
On July 29, 1999, a wholly owned special purpose subsidiary (SPS) of Boston
Edison closed the sale of $725 million of notes to a special purpose trust
created by two Massachusetts state agencies. The trust then concurrently
closed the sale of $725 million of electric rate reduction bonds to the
public. The notes are secured by a portion of the transition charge assessed
on Boston Edison's retail customers as permitted under the Massachusetts
Electric Industry Restructuring Act and authorized by the Massachusetts
Department of Telecommunications and Energy (MDTE). These bonds are non-
recourse to Boston Edison.
E) Nature of Operations
--------------------
NSTAR is focusing its utility operations on the transmission and distribution
of energy. This is illustrated by the sale of Boston Edison's fossil
generating assets to Sithe Energies in May 1998 and the sale of Pilgrim to
Entergy Nuclear Generating Company in July 1999. In December 1998, COM/Energy
completed the sale of substantially all of its generating assets to a
subsidiary of Southern Company.
NSTAR's utility subsidiaries currently deliver electricity at retail to
1,040,000 customers in 81 communities, including the city of Boston, and
<PAGE> 10
provide gas services to approximately 240,000 customers in 51 communities.
They also supply electricity at wholesale for resale to other utilities and
municipalities and gas transportation services to many commercial and
industrial customers. NSTAR's utility subsidiaries are required to continue
to develop and implement electric demand side management programs as well as
to provide funding for renewable energy projects pursuant to Massachusetts
law. In addition, unregulated activities continue to be conducted through
various nonutility subsidiaries of NSTAR. Refer to Note I of these
Consolidated Financial Statements for information regarding NSTAR's nonutility
operations.
F) Contingencies
-------------
1. Hazardous Waste
The utility subsidiaries of NSTAR are involved in approximately 30 properties
where oil or hazardous materials were spilled or released. As such, the
companies are required to clean up these remaining properties in accordance
with a timetable developed by the Massachusetts Department of Environmental
Protection. There are uncertainties associated with these costs due to the
complexities of cleanup technology, regulatory requirements and the particular
characteristics of the different sites. Boston Edison also faces possible
liability as a potentially responsible party in the cleanup of six multi-party
hazardous waste sites in Massachusetts and other states where it is alleged to
have generated, transported or disposed of hazardous waste at the sites.
Boston Edison is one of many potentially responsible parties and currently
expects to have only a small percentage of the total potential liability for
these sites. Through September 30, 1999, NSTAR had approximately $7 million
accrued on its consolidated balance sheet related to these cleanup
liabilities. Management is unable to fully determine a range of reasonably
possible cleanup costs in excess of the accrued amount. Based on its
assessments of the specific site circumstances, management does not believe
that it is probable that any such additional costs will have a material impact
on NSTAR's consolidated financial position. However, it is reasonably
possible that additional provisions for cleanup costs that may result from a
change in estimates could have a material impact on the results of a reporting
period in the near term.
2. Generating Unit Performance Program
The MDTE's generating unit performance programs ceased March 1, 1998. Under
these programs the recovery of incremental purchased power costs resulting
from generating unit outages and outages at units in which they had
entitlements were subject to review by the MDTE. Proceedings relative to
generating unit performance remain pending before the MDTE. These proceedings
will include the review of replacement power costs associated with the
shutdown of the Connecticut Yankee nuclear electric generating unit. NSTAR is
a 14% equity investor in Connecticut Yankee Atomic Power Company and was a
power purchaser from the generating unit. Management is unable to fully
determine a range of reasonably possible disallowance costs in excess of
amounts accrued. Based on its assessment of the information currently
available, management does not believe that it is probable that any such
additional costs will have a material impact on the NSTAR Company's
consolidated financial position. However, it is reasonably possible that
additional provisions for disallowance costs that may result from a change in
<PAGE> 11
estimates could have a material impact on the results of a reporting period in
the near term.
3. Industry and Corporate Restructuring Legal Proceedings
The MDTE order approving the Boston Edison restructuring settlement agreement
was appealed by certain parties to the Massachusetts Supreme Judicial Court.
One settlement agreement appeal remains pending, however there has to date
been no briefing, hearing or other action taken with respect to this
proceeding.
In addition, along with other Massachusetts investor-owned utilities, the
NSTAR utility subsidiaries have been named as defendants in a class action
suit seeking to declare certain provisions of the Massachusetts electric
industry restructuring legislation unconstitutional.
Management is currently unable to determine the outcome of these outstanding
proceedings however, if an unfavorable outcome were to occur, there could be a
material adverse impact on business operations, the consolidated financial
position or results of operations for a reporting period.
4. Regulatory Proceedings
In October 1997, the MDTE opened a proceeding to investigate Boston Edison's
compliance with the 1993 order which permitted the formation of BETG and
authorized Boston Edison to invest up to $45 million in unregulated
activities. Hearings were completed during the first quarter of 1999. A MDTE
ruling is expected in 2000.
Management is currently unable to determine the outcome of this proceeding
however, if an unfavorable outcome were to occur, there could be a material
adverse impact on business operations, the consolidated financial position or
results of operations for a reporting period.
5. Rate Plan
The MDTE issued an order approving most major elements of a rate plan filed by
the retail utility subsidiaries of NSTAR on July 27, 1999. The highlights of
the rate plan include a four-year distribution rate freeze for each of the
NSTAR retail utility subsidiaries, the collection from customers of the
acquisition premium of approximately $478 million over 40 years and the
recovery of transaction and integration costs initially estimated at
approximately $111 million over 10 years. The Massachusetts Attorney General
and a group of four intervenors filed separate appeals of the MDTE order with
the Massachusetts Supreme Judicial Court (SJC) regarding the rate plan. While
management anticipates that the MDTE's decision to approve the rate plan will
be upheld by the SJC, it cannot determine the ultimate outcome of these
appeals or their impact on the rate plan.
6. Other Litigation
In the normal course of its business NSTAR and its subsidiaries are also
involved in certain other legal matters. Management is unable to fully
determine a range of reasonably possible legal costs in excess of amounts
accrued. Based on the information currently available, management does not
<PAGE> 12
believe that it is probable that any such additional costs will have a
material impact on NSTAR's consolidated financial position. However, it is
reasonably possible that additional legal costs that may result from a change
in estimates could have a material impact on the results of a reporting period
in the near term.
G) Income Taxes
------------
The following table reconciles the statutory federal income tax rate to the
annual estimated effective income tax rate for 1999 and the actual effective
income tax rate for 1998.
<TABLE>
<CAPTION>
1999 1998
---- ----
<S> <C> <C>
Statutory tax rate 35.0% 35.0%
State income tax, net of federal income
tax benefit 5.3 5.1
Investment tax credit amortization (13.5) (6.8)
Other 2.0 0.8
---- ----
Effective tax rate 28.8% 34.1%
==== ====
</TABLE>
The 1999 estimated effective tax rate decreased by 11.6% as a result of the
recognition in net income of the remaining unamortized investment tax credits
related to Pilgrim at the time of its sale. The 1998 effective tax rate
declined by 5.1% as a result of the recognition in net income of the remaining
unamortized investment tax credits related to Boston Edison's fossil
generating assets at the time of their sale. This shareholder benefit, which
was realized in the second quarter of 1998, is included in other expense, net
on the 1998 consolidated statement of income.
<PAGE> 13
H) Earnings Per Common Share
-------------------------
The following table illustrates the reconciliation between basic and diluted
earnings per share (EPS) computations.
<TABLE>
(in thousands, except per share amounts)
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
1999 1998 1999 1998
------- ------- -------- --------
<S> <C> <C> <C> <C>
Earnings available for common
shareholders $66,770 $74,004 $119,604 $125,396
Basic EPS $1.32 $1.55 $2.50 $2.60
Diluted EPS $1.31 $1.55 $2.49 $2.59
Weighted average common shares
outstanding for basic EPS 50,674 47,691 47,811 48,239
Effect of dilutive securities:
Weighted average dilutive potential
common shares related to share-based
compensation 248 168 152 148
Weighted average common shares
outstanding for diluted EPS 50,922 47,859 47,963 48,387
</TABLE>
<PAGE> 14
I) Segment and Related Information
-------------------------------
NSTAR's operations are classified into two reportable segments: utility
operations and unregulated nonutility operations.
NSTAR's four regulated operating public utility companies provide electricity
and natural gas services to approximately 1.3 million retail customers in
communities located in central, eastern and southeastern Massachusetts,
including the City of Boston, and supply electricity at wholesale to several
other utilities and municipalities. The unregulated nonutility operating
segment engages in activities which include telecommunications, district
energy operations, steam distribution, operation of liquefied natural gas
facilities, operation of an energy information technology company, and
ownership of five real estate trusts.
The accounting policies used to develop segment information correspond to
those described in Note B, "Basis of Presentation". NSTAR evaluates
performance based on earnings from operations before income taxes and
nonrecurring gains and losses. NSTAR accounts for inter-segment sales and
transfers at current market prices. Profits on inter-segment sales are not
eliminated. Financial data for the operating segments are as follows:
<TABLE>
<CAPTION>
(in thousands) Unregulated
Utility Operations Nonutility Consolidated
Electric Gas Operations Total
---------- -------- ----------- ------------
<S> <C> <C> <C> <C>
Three months ended September 30,
- --------------------------------
1999
- ----
Operating revenues $ 498,074 $ 13,336 $ 5,741 $ 517,151
Segment net income (loss) $ 82,556 $ (1,691) $ (12,605)(a) $ 68,260
1998
- ----
Operating revenues $ 479,664 $ 0 $ 233 $ 479,897
Segment net income (loss) $ 82,492 $ 0 $ (7,002)(b) $ 75,490
Nine months ended September 30,
- -------------------------------
1999
- ----
Operating revenues $1,248,413 $ 13,336 $ 6,562 $1,268,311
Segment net income (loss) $ 148,492 $ (1,691) $ (22,727)(a) $ 124,074
1998
- ----
Operating revenues $1,258,591 $ 0 $ 772 $1,259,363
Segment net income (loss) $ 153,730 $ 0 $ (21,059)(b) $ 132,671
Total assets
- ------------
September 30, 1999 $4,139,867 $610,635 $ 695,596 $5,446,098
December 31, 1998 $3,073,058 $ 0 $ 130,978 $3,204,036
</TABLE>
[FN]
(a) Net income of the nonutility operations reflects a charge of $11 million
related to the reduction of the carrying value of property, plant and
equipment.
(b) During the latter half of 1998 BEC decided to discontinue the operations
of Coneco, a wholly owned unregulated subsidiary that provided energy
management services and to cease its participation in EnergyVision, an
energy marketing joint venture with Williams Energy Services Company.
The net loss from these businesses was $2,827,000 and $4,900,000 for the
three months and nine months ended September 30, 1998, respectively.
The operating results and financial data for 1999 reflect the merger with
COM/Energy effective August 25, 1999.
<PAGE> 15
J) RCN Conversion
--------------
BETG is a participant in a telecommunications venture with RCN Telecom
Services of Massachusetts, Inc. (RCN). As part of the joint venture
agreement, BETG has the option to exchange portions of its investment in the
joint venture for shares of RCN Corporation (RCN Corp.) common stock at
specified periods. During 1998, BETG exercised its option to convert a
portion of its interest. In the first quarter of 1999, BETG received 1.1
million shares of RCN Corp. common stock in exchange for a portion of its
joint venture interest that had a book value of $11 million. The RCN Corp.
shares received are included in other investments on the September 30, 1999
consolidated balance sheet at their fair value of $45 million. The unrealized
gain due to the increase in fair value on these shares since they were
received is reflected, net of associated income taxes, as comprehensive income
on the 1999 consolidated statement of comprehensive income and the 1999
consolidated balance sheet.
On May 27, 1999, BETG notified RCN of its intention to exercise its option to
convert an additional portion of its joint venture interest which had a book
value of $90 million at that time. The ultimate number of RCN Corp. shares
received will be determined in the fourth quarter based on an agreed upon fair
value of the joint venture interest.
Item 2. Management's Discussion and Analysis
- ---------------------------------------------
Merger of BEC Energy and Commonwealth Energy System
- ---------------------------------------------------
NSTAR, an exempt public utility holding company, was created through a merger
transaction involving BEC Energy (BEC) and Commonwealth Energy System
(COM/Energy) on August 25, 1999. The utility industry has continued to change
in response to legislative and regulatory mandates that are aimed at lowering
prices for energy by creating a more competitive marketplace. These pressures
have resulted in an increasing trend in the industry to seek competitive
advantages and other benefits through business combinations. NSTAR is
focusing its utility operations on the transmission and distribution of energy
following the sale of BEC's fossil generating facilities to Sithe Energies in
May 1998, BEC's nuclear generating facilities to Entergy Nuclear Generating
Company in July 1999 and substantially all of COM/Energy's generating
facilities to Southern Company in December 1998.
The utility companies of NSTAR form an energy delivery company serving
approximately 1.3 million customers in Massachusetts, including more than one
million electric customers in 81 communities and 240,000 gas customers in 51
communities.
Shareholders of BEC and COM/Energy approved the merger on June 24, 1999.
Pursuant to the merger, BEC shareholders received approximately 41 million
shares of NSTAR while COM/Energy shareholders received approximately 20
million shares of NSTAR. In addition, BEC and COM/Energy shareholders
received an aggregate amount of cash of approximately $300 million. An
initial quarterly dividend rate of 48.5 cents per share of NSTAR was declared
by the board of trustees ($1.94 on an annualized basis) of NSTAR on
September 23, 1999 and paid on November 1, 1999. This dividend rate will be
reviewed on a regular basis.
<PAGE> 16
The merger became effective after receipt of various regulatory approvals.
The Federal Energy Regulatory Commission approved the merger on June 24, 1999.
The Nuclear Regulatory Commission approved the transfer of control of
subsidiary Canal Electric Company's interest in the Seabrook nuclear plant
from COM/Energy to NSTAR on August 11, 1999. The Securities and Exchange
Commission issued its approval on August 24, 1999.
An integral part of the merger is the rate plan that was filed by the retail
utility subsidiaries of BEC and COM/Energy and approved by the MDTE on
July 27, 1999. Significant elements of the rate plan include a four-year
distribution rate freeze (after an adjustment to the distribution rates of
subsidiaries Cambridge Electric Light Company and Commonwealth Electric
Company to collect the appropriate level of distribution costs that is offset
by a reduction in the transition charge that was previously approved by the
MDTE), recovery of the acquisition premium (goodwill) over 40 years and
recovery of transaction and integration costs (costs to achieve) over 10
years.
The merger is being accounted for by BEC as an acquisition of COM/Energy under
the purchase method of accounting. The goodwill amounted to approximately
$478 million while the original estimate of costs to achieve the merger was
$111 million. The annual amortization of goodwill will be approximately $11.9
million while the cost to achieve amortization will initially be approximately
$11.1 million annually. The cost to achieve amortization is based on the
filed estimate of $111 million to be amortized over 10 years. NSTAR's retail
utility subsidiaries will reconcile the actual costs with that estimate and
any difference is expected to be recovered over the remainder of the
amortization period. The majority of costs incurred to date to achieve the
merger relate to severance associated with a voluntary separation program in
which approximately 700 employees elected to participate. These amounts are
expected to be offset by future cost savings and avoidances to be realized
from combining the operations of BEC and COM/Energy.
A group of four intervenors and the Massachusetts Attorney General filed two
separate appeals of the MDTE's rate plan order with the Massachusetts Supreme
Judicial Court (SJC) in August 1999. While management anticipates that the
MDTE's decision to approve the rate plan will be upheld by the SJC, it is
unable to determine the ultimate outcome of these appeals or their impact on
the rate plan.
Results of Operations - Three Months Ended September 30, 1999 vs. Three Months
- ------------------------------------------------------------------------------
Ended September 30, 1998
- ------------------------
Basic and diluted earnings per common share were $1.32 and $1.31, respectively
for the three months ended September 30, 1999 compared to $1.55 and $1.55 for
the same period in 1998, a 14.8% decrease in basic earnings as described
below.
The results of operations for the quarter are not indicative of the results
which may be expected for the entire year due to the seasonality of electric
and gas sales and revenues. Refer to Note B to the Consolidated Financial
Statements.
<PAGE> 17
Operating revenues
Operating revenues were $517.2 million in 1999 compared to $479.9 million in
1998, an increase of $37.3 million or 7.8% as follows:
<TABLE>
<CAPTION>
(in thousands)
- ------------------------------------------------------
<S> <C>
Retail revenues $ 41,204
Wholesale revenues (12,607)
Short-term sales and other revenues 8,657
- ------------------------------------------------------
Increase in operating revenues $ 37,254
======================================================
</TABLE>
Retail revenues were $460.7 million in 1999 compared to $419.5 million in
1998, an increase of approximately $41.2 million or 10%. The increase in
retail revenues reflects a 4.1% increase in retail kWh sales resulting from
the higher than normal summer temperatures in 1999 and a continuing strong
local economy offset by an additional 5% rate reduction in retail rates, from
10% to 15%, effective September 1, 1999, as mandated by the Massachusetts
Electric Utility Industry Restructuring Act. The increase also reflects a
$48.5 million or 12% increase from the COM/Energy companies from the date of
the merger.
Wholesale revenues were $23.5 million in 1999 compared to $36.1 million in
1998, a decrease of $12.6 million or 35%. This reflects a $15.9 million
decrease in sales to Pilgrim contract customers due to the Pilgrim
divestiture. This is partially offset by a $2.2 million increase in sales to
municipal wholesale customers and a $1.0 million increase from the COM/Energy
companies from the date of the merger.
Total short-term sales and other revenues were $33.0 million in 1999 compared
to $24.3 million in 1998, an increase of $8.7 million or 36%. This increase
reflects $13 million of revenues from the COM/Energy companies from the date
of the merger. This also reflects a $4.0 million increase due to a billing
settlement related to the nuclear divestiture. This increase is partially
offset by a $10.0 million decrease in short-term sales which is consistent
with the decrease in short-term kWh sales. Beginning December 1, 1998, under
an agreement with Select Energy, a subsidiary of Northeast Utilities, Boston
Edison is only purchasing enough power to meet its obligations to its retail
and wholesale customers. Therefore, Boston Edison has no excess power supply
to sell into the New England Power Pool.
Operating expenses
Fuel, purchased power and cost of gas sold was $213.2 million in 1999 compared
to $154.8 million in 1998, an increase of $58.4 million or 38%. The increase
reflects $31 million of expense from the COM/Energy companies from the date of
the merger. Fuel expense related to Pilgrim station decreased $6 million due
to the 1999 refueling outage and the sale of the plant in July 1999. NSTAR's
retail electric companies adjust their electric rates to collect the costs
related to fuel and purchased power from customers on a fully reconciling
basis. Fuel and purchased power expense reflects a reduction of $13 million
in 1999 and $47 million in 1998 related to these rate recovery mechanisms.
Due to the rate adjustment mechanisms, changes in the amount of fuel,
purchased power and cost of gas expense has no net impact on earnings.
<PAGE> 18
Operations and maintenance expense was $93.1 million in 1999 compared to $90.9
million in 1998, an increase of $2.2 million or 2%. This increase reflects
$18 million from the COM/Energy subsidiaries related to normal operations from
the date of the merger and $10 million for bad debts. In addition, NSTAR
incurred $4 million of costs in the third quarter due to restoration efforts
related to Hurricane Floyd. These increases were partially offset by
decreases of $22 million for nuclear production expenses as a result of the
sale of Pilgrim station in the third quarter, $5 million for the deferral of
costs related to the Pilgrim refueling outage and $1 million in expense from
BETG.
Depreciation and amortization expense was $56.6 million in 1999 compared to
$47.3 million in 1998, an increase of $9.3 million or 20%. The increase
reflects approximately $2 million resulting from the amortization of goodwill
and costs to achieve related to the merger, an increase of $11 million
reflecting a reduction in the carrying amount of BETG's nonutility property,
and a $4 million increase from the COM/Energy companies from the date of the
merger. These increases were partially offset by decreases resulting from the
nuclear divestiture.
Demand side management (DSM) and renewable energy programs expense was $15.5
million in 1999 compared to $20.0 million in 1998, a decrease of $4.5 million
or 23%. These costs are collected from customers on a fully reconciling
basis. Therefore, the decrease has no impact on earnings.
Property and other taxes were $17.2 million in 1999 compared to $18.1 million
in 1998, a decrease of $0.9 million or 5%. The decrease is due to lower
municipal property taxes of $3 million resulting from the nuclear divestiture,
partially offset by an increase of $2 million from the COM/Energy companies
from the date of the merger.
Other expense, net
Other income, net was $17.0 million in 1999 compared to other expense of $5.0
million in 1998, a net increase in income of $22 million. Prior to the
consideration of tax benefits, other income was $0.4 million in 1999 compared
to other expense of $6.2 million in 1998. BETG's equity losses in the RCN
joint venture were $4.1 million in 1999 compared to its total equity losses
from the RCN and EnergyVision joint ventures in 1998 of $5.3 million. 1998
reflects an additional $3.2 million of costs related to discontinued
operations of BETG's subsidiary, Coneco, and $1.1 million of costs associated
with the referendum that sought to repeal the Massachusetts electric industry
restructuring law. These factors were offset by $3.2 million of interest
income in 1999 compared to $2.7 million in 1998. Other miscellaneous income
was $1.3 million in 1999 compared to $0.7 million in 1998. Income tax
benefits in 1999 were $16.6 million compared to $1.2 million in 1998. The
1999 income tax benefit includes $20.8 million related to the recognition of
previously deferred investment tax credits associated with the Pilgrim nuclear
generating station.
Interest charges
Interest on long-term debt and transmission property securitization bonds was
$28.1 million in 1999 compared to $19.5 million in 1998, an increase of $8.6
<PAGE> 19
million or 44%. The increase reflects $8 million of interest related to
securitization and $5 million of interest from the COM/Energy companies from
the date of the merger. These increases were partially offset by
approximately $3 million in reductions related to the retirement of $19
million of 7.8% debentures, $66 million of 9.875% debentures and $91 million
of 9.375% debentures during the third quarter of 1999.
Results of Operations - Nine Months Ended September 30, 1999 vs. Nine Months
- ----------------------------------------------------------------------------
Ended September 30, 1998
- ------------------------
Basic and diluted earnings per common share for the nine months ended
September 30, 1999 were $2.50 and $2.49, respectively compared to $2.60 and
$2.59 for the same period in 1998, a 3.8% decrease in earnings as described
below.
The results of operations for the nine months ended are not indicative of the
results which may be expected for the entire year due to the seasonality of
electric and gas sales and revenues. Refer to Note B to the Consolidated
Financial Statements.
Operating revenues
Operating revenues were $1,268.3 million in 1999 compared to $1,259.4 million
in 1998, an increase of $8.9 million or 0.7% as follows:
<TABLE>
<CAPTION>
(in thousands)
- ------------------------------------------------------
<S> <C>
Retail revenues $ 35,377
Wholesale revenues (13,760)
Short-term sales and other revenues (12,669)
- ------------------------------------------------------
Increase in operating revenues $ 8,948
======================================================
</TABLE>
Retail revenues were $1,112.9 million in 1999 compared to $1,077.5 million in
1998, an increase of $35.4 million or 3%. This increase reflects a 4.6%
increase in retail kWh sales resulting from the higher than normal summer
temperatures in 1999 and the continuing strong local economy in 1999. This
also reflects an increase of $48.5 million or 5% representing one month of
retail revenues from the COM/Energy companies from the date of the merger.
These increases are partially offset by a decrease in retail revenues
reflecting the impact of the 10% reduction in retail rates mandated by the
Massachusetts Electric Utility Industry Restructuring Act that was implemented
in March 1998 and an additional 5% rate reduction effective September 1, 1999.
Wholesale revenues were $92.5 million in 1999 compared to $106.3 million in
1998, a decrease of $13.8 million or 13%. This decrease in wholesale revenues
reflects a $19.4 million decrease in sales to Pilgrim contract customers due
to the scheduled 1999 refueling and maintenance outage and subsequent sale of
Pilgrim station in July 1999. This is partially offset by a $4.6 million
increase in sales to municipal wholesale contract customers and an additional
$1.0 million increase representing one month of sales from the COM/Energy
companies from the date of the merger.
Total short-term sales and other revenues were $62.9 million in 1999 compared
to $75.6 million in 1998, a decrease of $12.7 million or 17%. This reflects
$16 million of revenue received in 1998 as a result of support of standard
<PAGE> 20
offer service by the fossil generating stations prior to divestiture. This
decrease also reflects a $22 million decrease in short-term sales which is
consistent with the decrease in short-term kWh sales. Beginning December 1,
1998, under an agreement with Select Energy, a subsidiary of Northeast
Utilities, Boston Edison is only purchasing enough power to meet its
obligations to its retail and wholesale customers. Therefore, Boston Edison
has no excess power supply to sell into the New England Power Pool. These
decreases are partially offset by an increase of $13 million representing one
month of revenues of the COM/Energy companies from the date of the merger, a
$6 million increase related to a FERC approved settlement for transmission
contract customers and a $4 million increase for billing settlements to
Pilgrim contract customers.
Operating expenses
Fuel, purchased power and cost of gas sold was $510.9 million in 1999 compared
to $424.9 million in 1998, an increase of $86.0 million or 20%. Purchased
power expense increased $84 million reflecting the increase in Boston Edison's
purchased power requirements in the absence of its fossil generating units and
the 1999 Pilgrim refueling outage and sale and $31 million from the COM/Energy
companies from the date of the merger. NSTAR's retail electric companies
adjust their electric rates to collect the costs related to fuel and purchased
power from customers on a fully reconciling basis. Fuel and purchased power
expense reflects a reduction of $38 million in 1999 and $88 million in 1998
related to these rate recovery mechanisms. Due to the rate adjustment
mechanisms, changes in the amount of fuel and purchased power expense have no
net impact on earnings. The fuel expense related to Boston Edison's fossil
generation units decreased $66 million reflecting the divestiture of those
units in May 1998. Fuel expense related to Pilgrim station decreased $10
million due to the 1999 refueling outage and the sale of the plant in July
1999. The increase is additionally offset by a decrease of $2 million related
to Boston Edison's non-electric product costs.
Operations and maintenance expense was $244.0 million in 1999 compared to
$276.5 million in 1998, a decrease of $32.5 million or 12%. The decrease
reflects a $21 million decrease in fossil-related power production expenses
due to the fossil divestiture in May 1998. This also reflects a decrease of
$38 million of nuclear power production expenses due to the deferral of costs
related to the 1999 refueling outage at Pilgrim station and the sale of the
plant in July 1999 and a decrease of $3 million in BETG expenses in 1999.
These decreases are partially offset by increases of $10 million for bad debt
expense and $4 million incurred due to restoration efforts related to
Hurricane Floyd. The increase also reflects an additional $18 million in 1999
reflecting one month of the COM/Energy companies' expense from the date of the
merger.
Depreciation and amortization expense was $151.8 million in 1999 compared to
$147.4 million in 1998, an increase of $4.4 million or 3%. The increase
reflects approximately $2 million from the amortization of goodwill and costs
to achieve related to the merger with COM/Energy and an increase of $4 million
reflecting one month of expense from the COM/Energy companies from the date of
the merger. This also reflects an increase of $11 million related to a
reduction in the carrying value of BETG's nonutility property, and an increase
in depreciation on distribution utility plant required under the terms of the
<PAGE> 21
Boston Edison settlement agreement beginning March 1, 1998. These increases
are partially offset by decreases resulting from the nuclear divestiture,
amortization of the gain on the sale of the fossil plants which began in June
1998, and a decrease of $3 million of BETG depreciation in 1999.
Demand side management (DSM) and renewable energy programs expense was $42.2
million in 1999 compared to $37.0 million in 1998, an increase of $5.2 million
or 14%. These costs are collected from customers on a fully reconciling
basis. Therefore, the increase has no impact on earnings.
Property and other taxes were $57.2 million in 1999 compared to $71.0 million
in 1998, a decrease of $13.8 million or 19%. The decrease is due to a
decrease in municipal property taxes of $17 million resulting from the fossil
and nuclear divestitures. This decrease is partially offset by an increase of
$2 million from the COM/Energy companies from the date of the merger.
Other expense, net
Other income was $13.6 million in 1999 compared to other expense of $11.0
million in 1998, a net increase in income of $24.6 million. Prior to the
consideration of tax benefits, other expense was $5.6 million in 1999 compared
to $34.0 million in 1998. BETG's equity losses in the RCN joint venture were
$13.4 million in 1999 compared to its total equity losses from both the RCN
and EnergyVision joint ventures in 1998 of $14.3 million. 1998 reflects $22.4
million of costs related to the fossil divestiture that is offset by the
recognition of investment tax credits disclosed below. 1998 also reflects an
additional $3.2 million of costs related to discontinued operations of BETG's
subsidiary, Coneco, and $1.4 million of costs associated with the referendum
that sought to repeal the Massachusetts electric industry restructuring law.
These negative amounts are offset by $4.9 million of interest income in 1999
compared to $6.2 million in 1998 due to the level of cash on hand as a result
of the proceeds of the fossil divestiture. Other miscellaneous income was
$2.9 million in 1999 compared to $1.1 million in 1998. Income tax benefits in
1999 were $19.2 million compared to $23.0 million in 1998. The income tax
benefits include $20.8 million in 1999 and $10.9 million in 1998 related to
the recognition of previously deferred investment tax credits associated with
the Pilgrim nuclear generating station sold in 1999 and the fossil generating
stations sold in 1998.
Interest charges
Interest on long-term debt and transmission property securitization bonds was
$67.0 million in 1999 compared to $63.5 million in 1998, an increase of $3.5
million or 6%. The increase reflects $8 million related to securitization and
$5 million from the COM/Energy companies from the date of the merger. This
increase is partially offset by reductions of approximately $2 million due to
the maturing of $100 million of 5.95% debentures in March 1998 and the
cessation of amortization of the associated discounts and redemption premiums,
and a reduction of approximately $3 million due to the redemption of a $100
million 6.662% bank loan in June 1998. Additionally, interest charges were
lower by approximately $3 million due to the retirement of $19 million of 7.8%
debentures, $66 million of 9.875% debentures and $91 million of 9.375%
debentures during the third quarter of 1999.
<PAGE> 22
Preferred stock dividends of subsidiary
Preferred stock dividends of subsidiary were $4.5 million in 1999 compared to
$7.3 million in 1998, a decrease of $2.8 million or 38%. The decrease is due
to the redemption of 400,000 shares of 7.75% series cumulative preferred stock
and the remaining 320,000 shares of 7.27% series in July 1998.
Electric Revenues
- -----------------
NSTAR's electric delivery business has provided its standard offer customers
service at rates designed to give 10% savings from rates in effect prior to
the retail access date (March 1, 1998) and an additional 5% average savings,
after an adjustment for inflation, as of September 1, 1999. The cost of
providing standard offer service, which includes fuel and purchased power
costs, is recovered from customers on a fully reconciling basis. New retail
customers in the NSTAR electric service territory and previously existing
customers that are no longer eligible for the standard offer service and who
have not chosen to receive service from a competitive energy supplier are on
default service. The price of default service is based on the average
competitive market price for power. Refer also to the Electric Revenues
section of Item 7 of the BEC 1998 Annual Report on Form 10-K/A.
Under the Boston Edison restructuring settlement agreement, the rates of
Boston Edison's distribution business will remain unchanged, subject to a
minimum and maximum return on average common equity (ROE), until December 31,
2000. Refer to the Electric Revenues section of Item 7 of the BEC 1998 Annual
Report on Form 10-K/A for detail regarding the minimum and maximum ROE. Under
the Boston Edison settlement agreement, the cost of providing transmission
service to distribution customers is recovered on a fully reconciling basis.
Liquidity
- ---------
NSTAR companies supplement internally generated funds as needed, primarily
through the issuance of short-term commercial paper and bank borrowings.
Boston Edison has authority from the Federal Energy Regulatory Commission to
issue up to $350 million of short-term debt. Boston Edison has a $200 million
revolving credit agreement with a group of banks as well as other arrangements
with several banks to provide additional short-term credit on an uncommitted
and as available basis. No amount was outstanding under these revolving
credit agreements as of September 30, 1999.
BEC Energy has a $225 million revolving credit agreement with a group of banks
effective through July 2001. Approximately $146 million of short-term debt
was outstanding under this credit agreement as of September 30, 1999. The
purpose of this agreement is to provide financing for general corporate
purposes and to fund the common share repurchase program.
COM/Energy currently has a $122 million line of credit. Approximately $87
million was outstanding under this agreement as of September 30, 1999.
In April 1998, Boston Edison announced a common share repurchase program under
which it would repurchase up to four million of its common shares. BEC
assumed this program since the reorganization to a holding company structure.
NSTAR assumed this program effective as of the merger date. Through
<PAGE> 23
September 30, 1999, four million shares had been repurchased at a total cost
of approximately $121 million. In October 1999, this program was completed.
Four million shares were repurchased at a total cost of approximately $157
million. In October 1999, NSTAR announced a new $300 million common share
repurchase program. Under both the old and new programs, shares are
repurchased through open market, block or privately-negotiated transactions,
or a combination. The timing and actual number of shares repurchased will be
impacted by market conditions.
On July 29, 1999, a wholly owned special purpose subsidiary (SPS) of Boston
Edison closed the sale of $725 million of notes to a special purpose trust
created by two Massachusetts state agencies. The trust then concurrently
closed the sale of $725 million of electric rate reduction bonds to the
public. The notes are secured by a portion of the transition charge assessed
on Boston Edison's retail customers as permitted under the Massachusetts
Electric Industry Restructuring Act and authorized by the MDTE. These bonds
were issued in five separate classes with variable payment periods ranging
from approximately one to ten years and bearing fixed interest rates ranging
from 5.99% to 7.03%. The bonds are non-recourse to Boston Edison. Proceeds
were utilized to finance a portion of the stranded costs that are being
collected from customers under Boston Edison's restructuring settlement
agreement. Boston Edison will collect a portion of the transition charge on
behalf of the SPS and remit the proceeds to the SPS. Boston Edison used a
portion of the proceeds received from the SPS to fund a portion of the nuclear
decommissioning fund transferred to Entergy as part of the sale of the Pilgrim
generating station. Boston Edison is using the remaining proceeds to reduce
capitalization and for general corporate purposes.
On July 30, 1999, Boston Edison announced a tender offer for any and all of
its outstanding 9-7/8% debentures due June 1, 2020 and its 9-3/8% debentures
due August 15, 2021. The aggregate principal amount of the securities is $215
million, of which approximately $157 million was redeemed. In addition,
unrelated to the tender offer, $19 million of 7.80% series due 2023 was
repurchased on the open market.
On September 30, 1999, COM/Energy's outstanding $40 million, variable rate,
two-year term note was redeemed.
Year 2000 Computer Issue
- ------------------------
The year 2000 issue is the result of computer programs that were written using
two digits rather than four to define an applicable year. If computer
programs with date-sensitive functions are not year 2000 compliant, they may
recognize a date using "00" as the year 1900 rather than the year 2000. This
could result in system failures or miscalculations causing disruptions of
operations, including, among other things, a temporary inability to process
transactions and engage in other normal business activities. NSTAR has a year
2000 program in place to address the risk of non-compliant internal business
software, internal non-business software and embedded chip technology and
external noncompliance of third parties. While the recently completed merger
transaction between BEC Energy and COM/Energy has led to some integrated
planning efforts, the companies have essentially continued to resolve year
2000 issues independently.
<PAGE> 24
NSTAR is addressing the year 2000 issue on a coordinated basis. Both BEC and
COM/Energy have inventoried and assessed all date-sensitive systems including
mission critical systems, important business systems used for information and
transaction processing systems, and non-critical internal productivity
systems. The North American Electric Reliability Council (NERC) has defined
mission critical systems as those whose mis-operation could result in loss of
electric generation, transmission or load interruption. Important business
systems are those necessary to maintain core business functions such as
billing and accounting for electricity and gas service to customers.
NSTAR has inventoried mission critical systems that may be date-sensitive and
that use embedded technology such as micro-controllers or microprocessors.
Approximately 27% of BEC's systems and approximately 20% of COM/Energy's
systems required modification or replacement. These systems can be
categorized as: (1) telecommunications, (2) distribution systems controls,
and (3) other distribution equipment. Both BEC and COM/Energy have completed
remediation and testing of mission critical systems and reported to NERC on
June 30, 1999 that all mission critical systems are ready for year 2000.
NSTAR inventoried important business systems that are date-sensitive and
determined that approximately one-third of BEC's systems and approximately 90%
of COM/Energy's systems needed modification or replacement. Plans were
developed and implemented to correct and test all affected systems, with
priorities based on the importance of the supported activity. As systems were
remediated they were tested for operational and year 2000 readiness in their
own environment. After completion of implementation, the systems were then
tested for their integration and compatibility with other interactive systems.
All important business system replacements, remediation and testing were
completed by July 1999. These systems are now considered year 2000 ready.
In addition all non-critical internal productivity systems have been
inventoried and assessed. Approximately one-third of BEC's systems and
approximately 90% of COM/Energy's systems required modification or
replacement. Under the year 2000 plan, each of these systems has a form of
readiness acceptance commensurate with its business importance. More
important and complex systems are tested as a means of acceptance. Less
important and non-complex systems may refer to industry test results, vendor
test results and/or vendor statements of readiness as a means of acceptance.
All of these systems were declared ready by September 30, 1999.
Costs incurred to remediate systems are expensed as incurred. In addition, a
decision was made to use this opportunity to upgrade some of BEC's less
efficient centralized business systems. Systems' replacement costs will be
capitalized and amortized over future periods. NSTAR expects the modification
and testing of its information and transaction processing systems to cost $42
million. NSTAR has expended $37 million on this project through September 30,
1999. NSTAR has funded and plans on continuing to fund all costs related to
year 2000 with internally generated cash flows.
In addition to its internal efforts, BEC and COM/Energy have initiated formal
communications with their significant suppliers, service providers and other
vendors to determine the extent to which they may be vulnerable to their
failure to correct their own year 2000 issues. The companies have received
responses from more than 1,000 third party vendors including mission critical
vendors. All of these vendors have indicated that they will be year 2000
ready by the end of 1999. In addition, NSTAR has contacted all of its
significant power suppliers. Each has indicated that they either are or will
be year 2000 ready by the end of 1999. In addition to the risk faced from
its dependence on third party suppliers for year 2000 readiness, NSTAR has a
risk that power will not be available from the Independent System Operator-
New
<PAGE> 25
England (ISO-NE) for the purchase and distribution to NSTAR's customers.
Should ISO-NE fail to resolve its year 2000 issues as planned, there would be
an adverse impact on NSTAR and its customers. To mitigate this risk, efforts
are being coordinated with ISO-NE and the New England Power Pool (NEPOOL) to
establish inter-utility testing guidelines coordinated with NERC plans to
determine year 2000 readiness.
NSTAR's electric utility subsidiaries are participants in the NEPOOL/ISO New
England Year 2000 Joint Oversight Committee which is overseeing ISO-NE's and
NEPOOL's year 2000 readiness activities. Overall the Northeast Power
Coordinating Council, whose activities will be incorporated into the
interregional coordinating efforts by the NERC, will coordinate regional
activities, including those of ISO-NE/NEPOOL. Regional year 2000 contingency
plans were developed and submitted to NERC in June 1999. Drills will continue
through the remainder of the year.
In addition, parts of the global infrastructure, including national banking
systems, electrical power grids, gas pipelines, transportation facilities,
communications and government activities, may not be fully functional after
1999 due to the year 2000 issue. Infrastructure failures could significantly
reduce BEC's ability to acquire energy and its ability to serve its customers
as effectively as they are now being served.
NSTAR believes that its efforts to address the year 2000 issue will allow it
to successfully avoid any material adverse effect on its operations or
financial condition. However, it recognizes that failing to resolve year 2000
issues on a timely basis would, in a most reasonable worst case scenario,
significantly limit its ability to acquire and distribute energy or process
its daily business transactions for a period of time, especially if such
failure is coupled with third party or infrastructure failures. Similarly,
NSTAR could be significantly affected by the failure of one or more
significant suppliers, customers or components of the infrastructure to
conduct their respective operations normally after 1999. Adverse effects on
NSTAR could include, among other things, business disruption, increased costs,
loss of business and other similar risks.
NSTAR's year 2000 program includes contingency plans. If required, these
plans are intended to address both internal risks as well as potential
external risks related to vendors, customers and energy suppliers. Plans have
been developed in conjunction with available national and regional guidance
and are based on system emergency plans that were developed and successfully
tested over the past several years. Included within its contingency plans are
procedures for the procurement of short-term power supplies and emergency
distribution system restoration procedures. The contract with ISO-NE requires
ISO-NE dispatch at all times sufficient resources to meet total New England
load requirements. ISO-NE has the responsibility and authority to dispatch
all regional generation sources including maintaining sufficient operating
reserves to respond to unanticipated system conditions. ISO-NE, in
conjunction with NEPOOL has an extensive year 2000 readiness program underway
to ensure that it will have sufficient generation and transmission resources
to reliably serve load. In addition, ISO-NE indicated that it will maximize
the operating reserves during the early year 2000 period.
The foregoing discussion regarding year 2000 project timing, effectiveness,
implementation and costs includes forward-looking statements that are based on
management's current evaluation using available information. Factors that
might cause material changes include, but are not limited to, the availability
of key year 2000 personnel, the readiness of third parties and NSTAR's ability
to respond to unforeseen year 2000 complications.
<PAGE> 26
RCN Conversion
- --------------
On May 27, 1999, BETG notified RCN of its intention to exercise its option to
convert an additional portion of its joint venture interest which had a book
value of $90 million as allowed under its agreement with RCN. The ultimate
number of shares received will be determined based on an agreed upon fair
value of the joint venture interest. Refer to Note J of these Consolidated
Financial Statements for more information regarding the RCN conversion.
Safe Harbor Cautionary Statement
- --------------------------------
NSTAR occasionally makes forward-looking statements such as forecasts and
projections of expected future performance or statements of its plans and
objectives. These forward-looking statements may be contained in filings with
the Securities and Exchange Commission, press releases and oral statements.
Actual results could potentially differ materially from these statements.
Therefore, no assurances can be given that the outcomes stated in such
forward-looking statements and estimates will be achieved. Refer also to the
safe harbor cautionary statements included in the BEC 1998 Annual Report on
Form 10-K/A.
The preceding sections include certain forward-looking statements about
merger, environmental and legal issues and year 2000 compliance.
The cost savings and cost avoidances ultimately realized from the merger may
differ from current estimates.
The impacts of various environmental and legal issues could differ from
current expectations. New regulations or changes to existing regulations
could impose additional operating requirements or liabilities other than
expected. The effects of changes in specific hazardous waste site conditions
and cleanup technology could affect estimated cleanup liabilities. The
impacts of changes in available information and circumstances regarding legal
issues could affect the estimated litigation costs.
The timing and total costs related to the year 2000 plan could differ from
current expectations. Factors that may cause such differences include the
ability to locate and correct all relevant computer codes and the availability
of personnel trained in this area. In addition, NSTAR cannot predict the
nature or impact on operations of third party noncompliance.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
- -------------------------------------------------------------------
There have been no material changes since year-end.
<PAGE> 27
Part II - Other Information
Item 6. Exhibits and Reports on Form 8-K
- -----------------------------------------
a) Exhibits filed herewith and incorporated by reference:
Exhibit 4 - Instruments Defining the Rights of Security Holders,
Including Indentures
Management agrees to furnish to the Securities and
Exchange Commission, upon request, a copy of any
agreements or instruments defining the rights of
holders of any long-term debt whose authorization
does not exceed 10% of total assets.
Exhibit 15 - Letter Re Unaudited Interim Financial Information
15.1 - Report of Independent Accountants
Exhibit 27 - Financial Data Schedule
27.1 - Schedule UT
Exhibit 99 - Additional Exhibits
99.1 - Letter of Independent Accountants
Form S-4 Registration Statement filed by NSTAR on
May 12, 1999 (File No. 333-78285); Post-effective
Amendment to Form S-4 on Form S-3 filed by NSTAR on
August 19, 1999 (File No. 333-78285); Post-effective
Amendment to Form S-4 on Form S-8 filed by NSTAR on
August 19, 1999 (File No. 333-78285); Form S-8
Registration Statement filed by NSTAR on August 19,
1999 (File No. 333-85559)
b) NSTAR filed a Form 8-K on August 25, 1999 to disclose the completion
of the merger transaction between BEC Energy and Commonwealth Energy
System.
<PAGE> 28
Signature
---------
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
NSTAR
------------
(Registrant)
Date: November 15, 1999 /s/ R. J. Weafer, Jr.
------------------------------
Robert J. Weafer, Jr.
Vice President, Controller
and Chief Accounting
Officer
<PAGE> 29
Exhibit 15.1
Report of Independent Accountants
To the Shareholders and Trustees
of NSTAR:
We have reviewed the accompanying consolidated balance sheet of NSTAR as of
September 30, 1999 and the related consolidated statements of income and
comprehensive income for the three and nine-month periods ended September 30,
1999 and 1998 and consolidated cash flows for the nine-month periods ended
September 30, 1999 and 1998. These consolidated financial statements are the
responsibility of management.
We conducted our review in accordance with standards established by the
American Institute of Certified Public Accountants. A review of interim
financial information consists principally of applying analytical procedures
to financial data and making inquiries of persons responsible for financial
and accounting matters. It is substantially less in scope than an audit
conducted in accordance with generally accepted auditing standards, the
objective of which is the expression of an opinion regarding the consolidated
financial statements taken as a whole. Accordingly, we do not express such
an opinion.
Based on our review, we are not aware of any material modifications that
should be made to the accompanying consolidated financial statements in order
for them to be in conformity with generally accepted accounting principles.
Hartford, Connecticut PricewaterhouseCoopers LLP
November 15, 1999
<PAGE> 30
Exhibit 99.1
Securities and Exchange Commission
450 Fifth Street, N.W.
Washington, D.C. 20549
Re: NSTAR
Registration on
Forms S-4 and S-8
We are aware that our report dated November 15, 1999 on our review of the
consolidated interim financial information of NSTAR as of and for the period
ended September 30, 1999 and included in NSTAR's quarterly report on Form
10-Q for the quarter then ended is incorporated by reference in NSTAR's
registration statement on Form S-4 and related amendments (File No.
333-78285) and on Form S-8 (File No. 333-85559). Pursuant to Rule 436(c)
under the Securities Act of 1933, this report should not be considered a part
of the registration statements prepared or certified by us within the meaning
of Sections 7 and 11 of that Act.
Hartford, Connecticut PricewaterhouseCoopers LLP
November 15, 1999
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