<PAGE>
UNITED STATES 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 June 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
BEC ENERGY
(Exact name of registrant as specified in its charter)
Massachusetts 04-6830187
- ------------- ----------
(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: 1-888-423-2364
--------------
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 August 9, 1999
- ----- -----------------------------
Common Shares, $1 par value 45,553,073 shares
<PAGE> 2
Part I - Financial Information
Item 1. Financial Statements
- -----------------------------
<TABLE>
BEC Energy
Consolidated Statements of Income
(Unaudited)
(in thousands, except per share amounts)
<CAPTION>
Three Months Six Months
Ended June 30, Ended June 30,
1999 1998 1999 1998
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Operating revenues $379,290 $385,348 $751,160 $779,465
-------- -------- -------- --------
Operating expenses:
Fuel and purchased power 144,510 120,467 297,697 270,131
Operations and maintenance 71,318 90,721 150,949 185,666
Depreciation and amortization 47,687 52,819 95,188 100,112
Demand side management and
renewable energy programs 13,433 8,975 26,701 17,041
Taxes - property and other 19,440 23,349 39,948 52,875
Income taxes 24,233 24,072 38,279 39,307
-------- -------- -------- --------
Total operating expenses 320,621 320,403 648,762 665,132
-------- -------- -------- --------
Operating income 58,669 64,945 102,398 114,333
Other expense, net (884) (4,774) (3,369) (5,964)
-------- -------- -------- --------
Operating and other income 57,785 60,171 99,029 108,369
-------- -------- -------- --------
Interest charges:
Long-term debt 19,444 21,125 38,901 44,029
Other 2,562 5,010 5,233 7,723
Allowance for borrowed funds
used during construction (474) (287) (919) (564)
-------- -------- -------- --------
Total interest charges 21,532 25,848 43,215 51,188
-------- -------- -------- --------
Net income 36,253 34,323 55,814 57,181
Preferred stock dividends of
subsidiary 1,490 2,871 2,980 5,790
-------- -------- -------- --------
Earnings available for common
shareholders $ 34,763 $ 31,452 $ 52,834 $ 51,391
======== ======== ======== ========
Weighted average common shares
outstanding:
Basic 45,772 48,513 46,356 48,514
====== ====== ====== ======
Diluted 45,963 48,701 46,521 48,683
====== ====== ====== ======
Earnings per common share:
Basic and diluted $0.76 $0.65 $1.14 $1.06
===== ===== ===== =====
Dividends declared per common share $0.485 $0.47 $0.97 $0.94
====== ===== ===== =====
</TABLE>
<TABLE>
Consolidated Statements of Comprehensive Income
(Unaudited)
(in thousands)
<CAPTION>
Three Months Six Months
Ended June 30, Ended June 30,
1999 1998 1999 1998
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Net income $ 36,253 $ 34,323 $ 55,814 $ 57,181
Other comprehensive income, net:
Unrealized gain on investments 6,205 0 16,933 0
-------- -------- -------- --------
Comprehensive income $ 42,458 $ 34,323 $ 72,747 $ 57,181
======== ======== ======== ========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
<PAGE> 3
<TABLE>
BEC Energy
Consolidated Balance Sheets
(Unaudited)
(in thousands)
<CAPTION>
June 30, December 31,
1999 1998
---------- ------------
<S> <C> <C>
Assets
- ------
Utility plant in service, at original cost $2,763,146 $2,720,681
Less: accumulated depreciation 980,906 926,020
---------- ----------
1,782,240 1,794,661
Construction work in progress 44,620 40,965
---------- ----------
Net utility plant 1,826,860 1,835,626
Nonutility property 25,720 21,565
Nuclear decommissioning trust 180,242 172,908
Equity investments 125,901 84,770
Other investments 57,588 30,206
Current assets:
Cash and cash equivalents 28,146 98,989
Accounts receivable 212,896 202,275
Accrued unbilled revenues 24,665 14,322
Materials and supplies, at average cost 14,285 10,731
Prepaid expenses and other 108,603 102,448
---------- ----------
Total current assets 388,595 428,765
---------- ----------
Other regulatory assets:
Generation-related regulatory asset, net 552,870 455,725
Power contracts 49,566 58,415
Income taxes, net 51,992 52,168
Redemption premiums 22,225 23,419
Postretirement benefits costs 21,167 21,592
Other 27,120 1,825
---------- ----------
Total regulatory assets 724,940 613,144
Other deferred debits 37,973 26,915
---------- ----------
Total assets $3,367,819 $3,213,899
========== ==========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
<PAGE> 4
<TABLE>
BEC Energy
Consolidated Balance Sheets
(Unaudited)
(in thousands)
<CAPTION>
June 30, December 31,
1999 1998
---------- ------------
<S> <C> <C>
Capitalization and Liabilities
- ------------------------------
Common equity:
Common stock, par value $1 per share
(45,553,073 and 47,184,073 shares issued
and outstanding) $ 45,553 $ 47,184
Premium on common stock 582,710 644,205
Retained earnings 365,995 360,509
Accumulated other comprehensive income, net 16,933 -
---------- ----------
Total common equity 1,011,191 1,051,898
---------- ----------
Cumulative preferred stock of subsidiary:
Nonmandatory redeemable series 43,000 43,000
Mandatory redeemable series 49,160 49,040
---------- ----------
Total preferred stock 92,160 92,040
---------- ----------
Long-term debt 880,057 955,563
---------- ----------
Total capitalization 1,983,408 2,099,501
---------- ----------
Current liabilities:
Long-term debt due within one year 66,467 667
Notes payable 191,750 78,000
Accounts payable 131,308 110,194
Accrued interest 20,779 20,516
Dividends payable 23,087 23,878
Other 246,639 183,664
---------- ----------
Total current liabilities 680,030 416,919
---------- ----------
Deferred credits:
Accumulated deferred income taxes 352,353 348,557
Accumulated deferred investment tax credits 44,318 45,930
Nuclear decommissioning liability 185,086 176,578
Power contracts 49,566 58,415
Other 73,058 67,999
---------- ----------
Total deferred credits 704,381 697,479
Commitments and contingencies __________ __________
Total capitalization and liabilities $3,367,819 $3,213,899
========== ==========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
<PAGE> 5
<TABLE>
BEC Energy
Consolidated Statements of Cash Flows
(Unaudited)
(in thousands)
<CAPTION>
Six Months Ended June 30,
1999 1998
--------- ---------
<S> <C> <C>
Operating activities:
Net income $ 55,814 $ 57,181
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization 102,693 117,953
Deferred income taxes and investment
tax credits (7,526) (135,704)
Allowance for borrowed funds used during
construction (919) (564)
Power contract buyout (65,780) 0
Net changes in:
Accounts receivable and accrued
unbilled revenues (20,964) (20,966)
Fuel, materials and supplies 1,000 32,575
Accounts payable 21,114 119,952
Other current assets and liabilities 56,292 58,763
Other, net (71,139) 7,424
--------- ---------
Net cash provided by operating activities 70,585 236,614
--------- ---------
Investing activities:
Plant expenditures (excluding AFUDC) (59,929) (47,339)
Proceeds from sale of fossil generating assets 0 533,732
Nuclear fuel expenditures (15,751) (3,591)
Investments (57,414) (35,378)
--------- ---------
Net cash (used in) provided by investing
activities (133,094) 447,424
--------- ---------
Financing activities:
Common share repurchases (64,744) 0
Preferred stock redemption 0 (4,000)
Long-term debt redemptions (9,000) (201,600)
Net change in notes payable 113,750 (137,013)
Dividends paid (48,340) (51,443)
--------- ---------
Net cash used in financing activities (8,334) (394,056)
--------- ---------
Net (decrease) increase in cash and cash
Equivalents (70,843) 289,982
Cash and cash equivalents at beginning of year 98,989 4,140
--------- ---------
Cash and cash equivalents at end of period $ 28,146 $ 294,122
========= =========
Supplemental disclosures of cash flow
information:
Cash paid during the period for:
Interest, net of amounts capitalized $ 41,411 $ 52,921
========= =========
Income taxes $ 335 $ 65,664
========= =========
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
<PAGE> 6
Notes to Unaudited Consolidated Financial Statements
- ----------------------------------------------------
A) Basis of Presentation
---------------------
Boston Edison Company (Boston Edison) received final approval of its
reorganization plan to form a holding company structure from the Securities
and Exchange Commission in May 1998. Effective May 20, 1998 the holding
company, BEC Energy (BEC), was formed with Boston Edison as 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 the regulated
utility business. 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
report on Form 10-Q for the period ended March 31, 1999. The financial
information presented as of June 30 has been prepared from BEC'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 BEC'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 BEC
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 six-month periods ended
June 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.
B) Pilgrim Nuclear Power Station
-----------------------------
Under Boston Edison's approved restructuring settlement agreement
approximately 75% of the net assets of Pilgrim Nuclear Power Station 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-
<PAGE> 7
regulation. This Pilgrim regulatory asset is included in the generation-
related regulatory asset-net on the consolidated balance sheet.
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 of Pilgrim 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. 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 will be 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, effective
upon 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.
C) 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. As a result of the issuance of these bonds,
Boston Edison customers are expected to realize aggregate savings of
approximately $76 million over ten years.
D) Nature of Operations
--------------------
BEC 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.
BEC signed a merger agreement with Commonwealth Energy System (CES) in
December 1998 that, upon completion, will create a new holding company,
NSTAR.
<PAGE> 8
The utility subsidiaries of NSTAR will serve approximately 1.3 million
customers located entirely within Massachusetts, including more than one
million electric customers in 81 communities and 240,000 gas customers in 51
communities. The merger is subject to customary closing conditions,
including the receipt of the required approvals. On June 24, 1999, common
shareholders of BEC and CES approved the merger agreement. On June 30, 1999,
FERC approved the merger. The MDTE issued an order approving most major
elements of a rate plan filed by the utility subsidiaries of the two
companies, including Boston Edison, on July 27, 1999. The highlights of the
rate plan include a four-year distribution rate freeze for each of the NSTAR
utility subsidiaries, the collection from customers of the acquisition
premium of approximately $516 million over 40 years and the recovery of
transaction and integration costs of approximately $111 million over 10
years. The Massachusetts Attorney General has announced his intention to
file an appeal of the MDTE order regarding the rate plan. Management cannot
determine the outcome of this appeal or its impact on the rate plan. The
Nuclear Regulatory Commission approved the merger on August 11, 1999. The
remaining approval from the Securities and Exchange Commission is expected in
the third quarter. For financial reporting purposes, the merger will be
accounted for by BEC as an acquisition of CES under the purchase method of
accounting.
Boston Edison currently delivers electricity at retail to an area of 590
square miles, including the city of Boston and 39 surrounding cities and
towns. It also supplies electricity at wholesale for resale to other
utilities and municipalities. Boston Edison is 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 BEC's
wholly owned subsidiary, BETG. Refer to Note H of these Consolidated
Financial Statements for information regarding BEC's nonutility operations.
E) Contingencies
-------------
1. Hazardous Waste
Boston Edison is an owner or operator of approximately 20 properties where
oil or hazardous materials were spilled or released. As such, Boston Edison
is 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 five
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 June 30, 1999, BEC had approximately $6
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, it does not believe that it
is probable that any such additional costs will have a material impact on its
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.
<PAGE> 9
2. Generating Unit Performance Program
Boston Edison's generating unit performance program ceased March 1, 1998.
Under this program the recovery of incremental purchased power costs
resulting from Boston Edison's generating unit outages and outages at units
in which it had entitlements was 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. Boston Edison is a 9.5% 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, it does not believe that it is probable
that any such additional costs will have a material impact on its
consolidated financial position. However, it is reasonably possible that
additional provisions for disallowance 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.
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, Boston
Edison has been named as a defendant 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 began in the fourth quarter of 1998 and were completed
during the first quarter of 1999. A MDTE ruling is expected in this
proceeding in the second half of 1999.
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. Other Litigation
In the normal course of its business BEC and its subsidiaries are also
involved in certain other legal matters. Management is unable to fully
<PAGE> 10
determine a range of reasonably possible legal costs in excess of amounts
accrued. Based on the information currently available, it does not believe
that it is probable that any such additional costs will have a material
impact on its 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.
F) 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 5.0 5.2
Investment tax credit amortization (1.4) (6.9)
Other 0.5 1.0
---- ----
Effective tax rate 39.1% 34.3%
==== ====
</TABLE>
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.
The 1999 effective tax rate increased by 0.4% as a result of the associated
decrease in the amortization of investment tax credits. The 1999 estimated
effective tax rate will decrease in the third quarter by approximately 8% 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.
<PAGE> 11
G) 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 Six Months
Ended June 30, Ended June 30,
1999 1998 1999 1998
------- ------- ------- -------
<S> <C> <C> <C> <C>
Earnings available for common
shareholders $34,763 $31,452 $52,834 $51,391
Basic EPS $0.76 $0.65 $1.14 $1.06
Diluted EPS $0.76 $0.65 $1.14 $1.06
Weighted average common shares
outstanding for basic EPS 45,772 48,513 46,356 48,514
Effect of dilutive securities:
Weighted average dilutive potential
common shares related to share-based
compensation 191 188 165 169
Weighted average common shares
outstanding for diluted EPS 45,963 48,701 46,521 48,683
</TABLE>
<PAGE> 12
H) Segment and Related Information
-------------------------------
BEC's principal operating segment, or its traditional core business, is the
electric utility that provides electric delivery service, primarily in the
city of Boston and 39 surrounding cities and towns. The utility also
supplies electricity at wholesale for resale to other utilities and
municipalities. The unregulated operating segment engages in nonutility
business activities such as telecommunications, construction management and
district energy in the Boston area. Financial data for the operating
segments are as follows (in thousands):
<TABLE>
<CAPTION>
Electric Unregulated
Utility Nonutility Consolidated
Operations Operations Total
---------- ---------- ------------
<S> <C> <C> <C>
Three months ended June 30,
- ---------------------------
1999
- ----
Operating revenues $ 379,144 $ 146 $ 379,290
Segment net income (loss) $ 41,178 $ (4,925) $ 36,253
1998
- ----
Operating revenues $ 384,372 $ 976 $ 385,348
Segment net income (loss) $ 42,995 $ (8,672)(a) $ 34,323
Six months ended June 30,
- -------------------------
1999
- ----
Operating revenues $ 750,339 $ 821 $ 751,160
Segment net income (loss) $ 66,036 $ (10,222) $ 55,814
1998
- ----
Operating revenues $ 778,927 $ 538 $ 779,465
Segment net income (loss) $ 71,237 $ (14,056)(a) $ 57,181
</TABLE>
[FN]
(a) 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 $801,000 and
$2,073,000 for the three months and six months ended June 30, 1998,
respectively.
I) 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 June 30, 1999
consolidated balance sheet at their fair value of $46 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 with a book value
of $90 million. The ultimate number of RCN Corp. shares received will be
determined based on an agreed upon fair value of the joint venture interest.
<PAGE> 13
Item 2. Management's Discussion and Analysis
- ---------------------------------------------
Results of Operations - Three Months Ended June 30, 1999 vs. Three Months
- -------------------------------------------------------------------------
Ended June 30, 1998
- -------------------
Basic and diluted earnings per common share for the three months ended
June 30, 1999 were $0.76 compared to $0.65 for the same period in 1998, a
16.9% increase in 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 kilowatt-
hour (kWh) sales and revenues. Refer to Note A to the Consolidated Financial
Statements.
Operating revenues
Operating revenues were $379.3 million in 1999 compared to $385.3 million in
1998, a decrease of $6.0 million or 1.6% as follows:
<TABLE>
<CAPTION>
(in thousands)
- ------------------------------------------------------
<S> <C>
Retail electric revenues $ 11,986
Wholesale revenues (1,339)
Short-term sales and other revenues (16,705)
- ------------------------------------------------------
Decrease in operating revenues $ (6,058)
======================================================
</TABLE>
Retail revenues were $332.1 million in 1999 compared to $320.1 million in
1998, an increase of approximately $12.0 million or 4%. The increase in
retail revenues reflects a 7.6% increase in retail kWh sales resulting from
the higher than normal early summer temperatures in 1999 and a continuing
strong local economy.
Wholesale revenues were $33.0 million in 1999 compared to $34.3 million in
1998, a decrease of $1.3 million or 4%. This reflects a $3.1 million
decrease in sales to Pilgrim contract customers due to the scheduled 1999
refueling and maintenance outage. This is partially offset by a $1.8 million
increase in sales to municipal wholesale customers.
Total short-term sales and other revenues were $14.1 million in 1999 compared
to $30.8 million in 1998, a decrease of $16.7 million or 54%. This reflects
$11 million of revenue received in 1998 as a result of support of standard
offer service by the fossil generating stations prior to divestiture. This
decrease also reflects a $7 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 and purchased power expense was $144.5 million in 1999 compared to
$120.5 million in 1998, an increase of $24.0 million or 20%. The fuel
expense related to fossil generation units decreased $19 million reflecting
the divestiture of those units in May 1998. Fuel expense related to Pilgrim
<PAGE> 14
station decreased $4 million due to the 1999 refueling outage. Purchased
power expense increased $21 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. Boston Edison adjusts its
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 $15 million in 1999 and $42 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 has no net impact
on earnings.
Operations and maintenance expense was $71.3 million in 1999 compared to
$90.7 million in 1998, a decrease of $19.4 million or 21%. The decrease
reflects a $9 million decrease in fossil-related power production expenses
due to the fossil divestiture in May 1998. This also reflects a decrease of
$11 million of nuclear production expenses due to the deferral of costs
related to the 1999 refueling outage at Pilgrim station.
Depreciation and amortization expense was $47.7 million in 1999 compared to
$52.8 million in 1998, a decrease of $5.1 million or 10%. The decrease is
due to the reduction in amortization resulting from the amortization of the
gain on the sale of the fossil generating units.
Demand side management (DSM) and renewable energy programs expense was $13.4
million in 1999 compared to $9.0 million in 1998, an increase of $4.4 million
or 49%. These costs are collected from customers on a fully reconciling
basis. Therefore, the increase has no impact on earnings.
Property and other taxes were $19.4 million in 1999 compared to $23.3 million
in 1998, a decrease of $3.9 million or 17%. The decrease is due to a
decrease in municipal property taxes of $4 million resulting from the fossil
divestiture.
Other expense, net
Other expense, net was $0.9 million in 1999 compared to $4.8 million in 1998,
a decrease of $3.9 million or 81%. Prior to the consideration of tax
benefits, other expenses were $1.9 million in 1999 compared to $24.8 million
in 1998, a decrease of $22.9 million. BETG's equity losses in the RCN joint
venture were $4.0 million in 1999 compared to its equity losses in 1998 in
both the RCN and EnergyVision joint ventures of $4.6 million. 1998 reflects
$22.3 million of costs related to the fossil divestiture that is offset by
the recognition of investment tax credits disclosed below. These negative
amounts are offset by $0.5 million of interest income in 1999 and $2.8
million in 1998 due to the levels of cash on hand as a result of the proceeds
of the fossil divestiture. Other miscellaneous income was $1.6 million in
1999 compared to expense of $0.7 million in 1998. Income tax benefits
related to other expense were $1.0 million in 1999 compared to $20.0 million
in 1998. The 1998 income tax benefit includes $10.9 million related to the
recognition of previously deferred investment tax credits associated with the
fossil generating stations.
<PAGE> 15
Interest charges
Interest on long-term debt was $19.4 million in 1999 compared to $21.1
million in 1998, a decrease of $1.7 million or 8%. The decrease reflects a
reduction of approximately $1.7 million due to the redemption of a $100
million 6.662% bank loan in June 1998.
Preferred stock dividends
Preferred stock dividends were $1.5 million in 1999 compared to $2.9 million
in 1998, a decrease of $1.4 million or 48%. 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.
Results of Operations - Six Months Ended June 30, 1999 vs. Six Months Ended
- ---------------------------------------------------------------------------
June 30, 1998
- -------------
Basic and diluted earnings per common share for the six months ended June 30,
1999 were $1.14 compared to $1.06 for the same period in 1998, a 7.5%
increase in earnings as described below.
The results of operations for the six months ended are not indicative of the
results which may be expected for the entire year due to the seasonality of
kilowatt-hour (kWh) sales and revenues. Refer to Note A to the Consolidated
Financial Statements.
Operating revenues
Operating revenues were $751.2 million in 1999 compared to $779.5 million in
1998, a decrease of $28.3 million or 3.6% as follows:
<TABLE>
<CAPTION>
(in thousands)
- ------------------------------------------------------
<S> <C>
Retail electric revenues $ (5,831)
Wholesale revenues (1,148)
Short-term sales and other revenues (21,326)
- ------------------------------------------------------
Decrease in operating revenues $(28,305)
======================================================
</TABLE>
Retail revenues were $652.2 million in 1999 compared to $658.0 million in
1998, a decrease of $5.8 million or 1%. The decrease in retail revenues
reflects the impact of the 10% reduction in retail rates mandated by the
Massachusetts Electric Utility Industry Restructuring Law that was
implemented in March 1998. A 4.9% increase in retail kWh sales resulting
from the higher than normal early summer temperatures in 1999 and the
continuing strong local economy in 1999 partially offset the impact of the
rate reduction.
Wholesale revenues were $69.1 million in 1999 compared to $70.2 million in
1998, a decrease of $1.1 million or 2%. This decrease in wholesale revenues
reflects a $3.6 million decrease in sales to Pilgrim contract customers due
to the scheduled 1999 refueling and maintenance outage. This is partially
offset by a $2.4 million increase in sales to municipal wholesale customers.
Total short-term sales and other revenues were $29.9 million in 1999 compared
to $51.2 million in 1998, a decrease of $21.3 million or 42%. This reflects
$16 million of revenue received in 1998 as a result of support of standard
<PAGE> 16
offer service by the fossil generating stations prior to divestiture. This
decrease also reflects an $11 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 a $6 million increase to other revenues in
1999 related to a FERC approved settlement for transmission contract
customers.
Operating expenses
Fuel and purchased power expense was $297.7 million in 1999 compared to
$270.1 million in 1998, an increase of $27.6 million or 10%. The fuel
expense related to fossil generation units decreased $66 million reflecting
the divestiture of those units in May 1998. Fuel expense related to Pilgrim
station decreased $4 million due to the 1999 refueling outage. 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. Boston Edison adjusts its
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 $24.0 million in 1999 and $39 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 has no net impact
on earnings.
Operations and maintenance expense was $150.9 million in 1999 compared to
$185.7 million in 1998, a decrease of $34.8 million or 19%. 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
$11 million of nuclear production expenses due to the deferral of costs
related to the 1999 refueling outage at Pilgrim station.
Depreciation and amortization expense was $95.2 million in 1999 compared to
$100.1 million in 1998, a decrease of $4.9 million or 5%. The decrease is
primarily due to the reduction in amortization resulting from the
amortization of the gain on the sale of the fossil generating units. The
decrease is partially offset by an increase in depreciation on distribution
utility plant required under the terms of the Boston Edison settlement
agreement beginning March 1, 1998.
Demand side management (DSM) and renewable energy programs expense was $26.7
million in 1999 compared to $17.0 million in 1998, an increase of $9.7
million or 57%. The increase reflects an increase in the required spending
for DSM programs in 1999. In addition, renewable energy programs expense
increased $4 million as a result of a state mandate for the funding of
renewable energy that became effective March 1, 1998. These costs are
collected from customers on a fully reconciling basis. Therefore, changes in
these costs have no impact on earnings.
Property and other taxes were $39.9 million in 1999 compared to $52.9 million
in 1998, a decrease of $13 million or 25%. The decrease is due to a decrease
<PAGE> 17
in municipal property taxes of $12 million resulting from the fossil
divestiture.
Other expense, net
Other expense, net was $3.4 million in 1999 compared to $6.0 million in 1998,
a decrease of $2.6 million or 43%. Prior to the consideration of tax
benefits, other expenses were $5.9 million in 1999 compared to $26.7 million
in 1998, a decrease of $20.8 million. BETG's equity losses in the RCN joint
venture were $9.3 million in 1999 compared to its equity losses in both the
RCN and EnergyVision joint ventures in 1998 of $9.0 million. 1998 reflects
$22.3 million of costs related to the fossil divestiture that is offset by
the recognition of investment tax credits disclosed below. These negative
amounts are offset in 1998 by $1.5 million of interest income in 1999 and
$3.6 million in 1998 due to the levels of cash on hand as a result of the
proceeds of the fossil divestiture. Other miscellaneous income was $1.9
million in 1999 compared to $1.0 million in 1998. Income tax benefits
related to other expense were $2.5 million in 1999 compared to $20.7 million
in 1998. The 1998 income tax benefit includes $10.9 million related to the
recognition of previously deferred investment tax credits associated with the
fossil generating stations.
Interest charges
Interest on long-term debt was $38.9 million in 1999 compared to $44.0
million in 1998, a decrease of $5.1 million or 12%. The decrease reflects a
reduction 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.
Preferred stock dividends
Preferred stock dividends were $3.0 million in 1999 compared to $5.8 million
in 1998, a decrease of $2.8 million or 48%. 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
- -----------------
Boston Edison's electric delivery business provides 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). Under Massachusetts law,
Boston Edison will be required to charge rates that provide these customers
an additional 5% average savings, after an adjustment for inflation, by
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 Boston Edison 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.
<PAGE> 18
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.
Pursuant to the merger agreement between BEC and CES, the utility
subsidiaries of the two companies filed a rate plan that was approved by the
MDTE on July 27, 1999. Under the approved plan, distribution rates of the
utility subsidiaries will be frozen for a period of four years upon
consummation of the BEC and CES merger. Other highlights of the rate plan
include recovery of transaction and integration costs (estimated to be
approximately $111 million) over a ten-year period and recovery of the
acquisition premium (estimated to be approximately $516 million) over 40
years. Recovery will be allocated among the utility subsidiaries, including
Boston Edison. The Massachusetts Attorney General has announced his
intention to file an appeal of the MDTE order regarding the rate plan.
Management cannot determine the outcome of this appeal or its impact on the
rate plan.
Liquidity
- ---------
Boston Edison supplements 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 June 30, 1999.
BEC has a $225 million revolving credit agreement with a group of banks
effective through July 2001. Approximately $192 million of short-term debt
was outstanding under this credit agreement as of June 30, 1999. The purpose
of this agreement is to provide financing to the holding company for general
corporate purposes to invest in BEC's subsidiaries and to fund the common
share repurchase program.
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
has assumed this program since the reorganization to a holding company
structure. Through June 30, 1999, 3 million shares have been repurchased at
a total cost of approximately $118 million. Under this program, 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
<PAGE> 19
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. Boston
Edison will incur a $15.1 million call premium as a result of this tender
offer. The MDTE has approved the recovery of this premium from customers.
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. BEC 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.
BEC is addressing the year 2000 issue on a coordinated basis. BEC
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 to customers.
BEC has inventoried mission critical systems that may be date-sensitive and
that use embedded technology such as micro-controllers or microprocessors.
Approximately 27% of these systems required modification or replacement.
These systems can be categorized as: (1) telecommunications, (2)
distribution systems controls, and (3) other distribution equipment. BEC has
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.
BEC inventoried important business systems that are date-sensitive and
determined that approximately one-third of these 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
<PAGE> 20
year 2000 readiness in their own environment. After completion of
implementation, the systems are 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 these 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.
Over 95% of these systems were declared ready by June 30, 1999. Management
expects to complete the remediation, replacement and testing of all non-
critical internal productivity systems by the end of third quarter of 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. BEC expects the modification
and testing of its information and transaction processing systems to cost $32
million. BEC has expended $26 million on this project through June 30, 1999.
BEC 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 has initiated formal communications
with its significant suppliers, service providers and other vendors to
determine the extent to which BEC may be vulnerable to their failure to
correct their own year 2000 issues. BEC has received responses from over 500
third party vendors including mission critical vendors. Approximately 40% of
the vendors indicated their systems would not be adversely impacted by year
2000 issues. All of the vendors responding have indicated that they will be
year 2000 ready by the end of the fourth quarter of 1999. In addition, BEC
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 the fourth
quarter of 1999. In addition to the risk faced from its dependence on third
party suppliers for year 2000 readiness, BEC has a risk that power will not
be available from the Independent System Operator-New England (ISO-NE) for
the purchase and distribution to Boston Edison's customers. Should ISO-NE
fail to resolve its year 2000 issues as planned, there would be an adverse
impact on Boston Edison 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.
Boston Edison is a participant 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.
<PAGE> 21
BEC 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,
BEC 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 BEC could
include, among other things, business disruption, increased costs, loss of
business and other similar risks.
BEC'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
BEC's ability to respond to unforeseen year 2000 complications.
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 with 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 I of these Consolidated Financial
Statements for more information regarding the RCN conversion.
Safe Harbor Cautionary Statement
- --------------------------------
BEC 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.
<PAGE> 22
The preceding sections include certain forward-looking statements about
environmental and legal issues and year 2000.
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, BEC 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> 23
Part II - Other Information
Item 6. Exhibits and Reports on Form 8-K
- -----------------------------------------
a) Exhibits filed herewith:
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-3 Registration Statement filed by BEC Energy
on July 2, 1998 (File No. 33-59693); Form S-8
Registration Statements filed by BEC Energy on
June 17, 1998 (File Nos. 33-58457, 33-59662 and
33-59682) and June 29, 1998 (File No. 333-30975-99)
b) No Form 8-K was filed during the second quarter of 1999.
<PAGE> 24
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.
BEC ENERGY
------------
(Registrant)
Date: August 16, 1999 /s/ Robert J. Weafer, Jr.
----------------------------
Robert J. Weafer, Jr.
Vice President-Finance,
Controller, Assistant
Treasurer and Assistant
Clerk
<PAGE> 25
Exhibit 15.1
Report of Independent Accountants
To the Shareholders and Trustees
of BEC Energy
We have reviewed the accompanying consolidated balance sheet of BEC Energy
(BEC) as of June 30, 1999 and the related statements of income for the three
and six-month periods ended June 30, 1999 and 1998 and cash flows for the
six-month periods ended June 30, 1999 and 1998. These 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 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 financial statements in order for them to
be in conformity with generally accepted accounting principles.
Boston, Massachusetts PricewaterhouseCoopers LLP
July 22, 1999
<PAGE> 26
Exhibit 99.1
Securities and Exchange Commission
450 Fifth Street, N.W.
Washington, D.C. 20549
Re: BEC Energy
Registration on
Forms S-3 and S-8
We are aware that our report dated July 22, 1999 on our review of the interim
financial information of BEC Energy (BEC) for the period ended June 30, 1999
and included in this Form 10-Q is incorporated by reference in BEC's
registration statements on Form S-3 (File No. 33-59693) and on Form S-8 (File
Nos. 33-58457, 33-59662, 33-59682 and 333-30975-99). 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.
Boston, Massachusetts PricewaterhouseCoopers LLP
July 22, 1999
<TABLE> <S> <C>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> JUN-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,826,860
<OTHER-PROPERTY-AND-INVEST> 389,451
<TOTAL-CURRENT-ASSETS> 388,595
<TOTAL-DEFERRED-CHARGES> 762,913
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 3,367,819
<COMMON> 45,553
<CAPITAL-SURPLUS-PAID-IN> 582,710
<RETAINED-EARNINGS> 365,995
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,011,191
49,160
43,000
<LONG-TERM-DEBT-NET> 880,057
<SHORT-TERM-NOTES> 191,750
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 66,467
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,126,194
<TOT-CAPITALIZATION-AND-LIAB> 3,367,819
<GROSS-OPERATING-REVENUE> 751,160
<INCOME-TAX-EXPENSE> 38,279
<OTHER-OPERATING-EXPENSES> 610,483
<TOTAL-OPERATING-EXPENSES> 648,762
<OPERATING-INCOME-LOSS> 102,398
<OTHER-INCOME-NET> (3,369)
<INCOME-BEFORE-INTEREST-EXPEN> 99,029
<TOTAL-INTEREST-EXPENSE> 43,215
<NET-INCOME> 55,814
2,980
<EARNINGS-AVAILABLE-FOR-COMM> 52,834
<COMMON-STOCK-DIVIDENDS> 44,569
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 70,585
<EPS-BASIC> 1.14
<EPS-DILUTED> 1.14
</TABLE>
