<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 March 31, 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 May 10, 1999
- ----- ---------------------------
Common Shares, $1 par value 45,616,873 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 Ended March 31,
1999 1998
-------- --------
<S> <C> <C>
Operating revenues $371,870 $394,117
-------- --------
Operating expenses:
Fuel and purchased power 153,188 149,661
Operations and maintenance 79,631 96,133
Depreciation and amortization 47,501 46,104
Demand side management and renewable energy
programs 13,268 8,067
Taxes - property and other 20,507 29,526
Income taxes 14,046 15,236
-------- --------
Total operating expenses 328,141 344,727
-------- --------
Operating income 43,729 49,390
Other expense, net (2,485) (1,190)
-------- --------
Operating and other income 41,244 48,200
-------- --------
Interest charges:
Long-term debt 19,458 22,907
Other 2,670 2,710
Allowance for borrowed funds used during
construction (446) (276)
-------- --------
Total interest charges 21,682 25,341
-------- --------
Net income 19,562 22,859
Preferred stock dividends of subsidiary 1,490 2,919
-------- --------
Earnings available for common shareholders $ 18,072 $ 19,940
======== ========
Weighted average common shares outstanding:
Basic 46,946 48,515
====== ======
Diluted 47,092 48,674
====== ======
Earnings per common share:
Basic and diluted $0.38 $0.41
===== =====
Dividends declared per common share $0.485 $0.47
====== =====
</TABLE>
<TABLE>
Consolidated Statements of Comprehensive Income
(Unaudited)
(in thousands)
<CAPTION>
Three Months Ended March 31,
1999 1998
-------- --------
<S> <C> <C>
Net income $ 19,562 $ 22,859
Other comprehensive income, net:
Unrealized gain on investments 10,728 -
-------- --------
Comprehensive income $ 30,290 $ 22,859
======== ========
</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>
March 31, December 31,
---------- ------------
1999 1998
---------- ----------
<S> <C> <C>
Assets
- ------
Utility plant in service, at original cost $2,734,698 $2,720,681
Less: accumulated depreciation 959,323 926,020
---------- ----------
1,775,375 1,794,661
Generation-related regulatory asset, net 357,870 366,336
Nuclear fuel, net 76,727 68,706
Construction work in progress 44,316 40,965
---------- ----------
Net utility plant 2,254,288 2,270,668
Nonutility property 22,822 21,565
Nuclear decommissioning trust 177,306 172,908
Equity investments 80,342 84,770
Other investments 48,345 30,206
Current assets:
Cash and cash equivalents 102,425 98,989
Accounts receivable 202,661 202,275
Accrued unbilled revenues 12,608 14,322
Materials and supplies, at average cost 19,835 15,474
Prepaid expenses and other 101,835 102,448
---------- ----------
Total current assets 439,364 433,508
---------- ----------
Other regulatory assets:
Power contracts 52,420 58,415
Income taxes, net 52,080 52,168
Redemption premiums 22,822 23,419
Postretirement benefits costs 21,380 21,592
Other 5,034 12,048
---------- ----------
Total regulatory assets 153,736 167,642
Other deferred debits 36,372 32,632
---------- ----------
Total assets $3,212,575 $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>
March 31, December 31,
1999 1998
---------- ------------
<S> <C> <C>
Capitalization and Liabilities
- ------------------------------
Common equity:
Common stock, par value $1 per share
(46,405,473 and 47,184,073 shares issued
and outstanding) $ 46,405 $ 47,184
Premium on common stock 615,463 644,205
Retained earnings 356,045 360,509
Accumulated other comprehensive income, net 10,728 -
---------- ----------
Total common equity 1,028,641 1,051,898
---------- ----------
Cumulative preferred stock of subsidiary:
Nonmandatory redeemable series 43,000 43,000
Mandatory redeemable series 49,100 49,040
---------- ----------
Total preferred stock 92,100 92,040
---------- ----------
Long-term debt 890,511 955,563
---------- ----------
Total capitalization 2,011,252 2,099,501
---------- ----------
Current liabilities:
Long-term debt due within one year 65,267 667
Notes payable 101,000 78,000
Accounts payable 96,466 110,194
Accrued interest 12,295 20,516
Dividends payable 23,469 23,878
Other 201,516 183,664
---------- ----------
Total current liabilities 500,013 416,919
---------- ----------
Deferred credits:
Accumulated deferred income taxes 353,536 348,557
Accumulated deferred investment tax credits 45,124 45,930
Nuclear decommissioning liability 180,734 176,578
Power contracts 52,420 58,415
Other 69,496 67,999
---------- ----------
Total deferred credits 701,310 697,479
Commitments and contingencies __________ __________
Total capitalization and liabilities $3,212,575 $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>
Three Months Ended March 31,
1999 1998
--------- ---------
<S> <C> <C>
Operating activities:
Net income $ 19,562 $ 22,859
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization 53,854 56,329
Deferred income taxes and investment
tax credits (2,900) 367
Allowance for borrowed funds used during
construction (446) (276)
Net changes in:
Accounts receivable and accrued
unbilled revenues 1,328 37,868
Fuel, materials and supplies (4,455) 10,616
Accounts payable (13,728) (2,526)
Other current assets and liabilities 9,835 10,156
Other, net 5,269 (26,392)
--------- ---------
Net cash provided by operating activities 68,319 109,001
--------- ---------
Investing activities:
Plant expenditures (excluding AFUDC) (22,214) (18,938)
Nuclear fuel expenditures (14,160) (959)
Investments 10 (14,069)
--------- ---------
Net cash used in investing activities (36,364) (33,966)
--------- ---------
Financing activities:
Common share repurchases (27,145) 0
Long-term debt redemptions 0 (100,000)
Net change in notes payable 23,000 61,987
Dividends paid (24,374) (25,721)
--------- ---------
Net cash used in financing activities (28,519) (63,734)
--------- ---------
Net increase in cash and cash equivalents 3,436 11,301
Cash and cash equivalents at beginning of year 98,989 4,140
--------- ---------
Cash and cash equivalents at end of period $ 102,425 $ 15,441
========= =========
Supplemental disclosures of cash flow
information:
Cash paid during the period for:
Interest, net of amounts capitalized $ 29,133 $ 36,084
========= =========
Income taxes $ 85 $ 10,233
========= =========
</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. The financial
information presented as of March 31 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.
Under the Boston Edison restructuring settlement agreement, which was
approved by the Massachusetts Department of Telecommunications and Energy
(DTE), 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 business continues to be subject to rate-
regulation. The remaining 25% is collected under Pilgrim's wholesale power
contracts with other utilities and municipalities. The consolidated balance
sheets reflect a reclassification of the Pilgrim net assets recoverable
through the transition charge from utility plant to regulatory asset. This
Pilgrim regulatory asset, included in the generation-related regulatory asset
on the consolidated balance sheets, continues to be grouped with utility
plant for financial statement presentation.
The sale of Boston Edison's fossil generating assets to Sithe Energies was
completed in May 1998. The amount received above net book value on the sale
of these assets is being returned to Boston Edison's customers over the
settlement period. That amount is partially offset by certain costs
recoverable through the transition charge due to the support of standard
offer service provided by Boston Edison's fossil generating assets prior to
the divestiture. The net gain on the sale of the fossil assets is included
as a
<PAGE> 7
reduction to the generation-related regulatory asset on the consolidated
balance sheets.
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 periods ended March 31, 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) Nature of Operations
--------------------
Within the restructured electric utility industry, BEC has announced its
intention to focus its utility operations on the transmission and
distribution of energy. The sale of Boston Edison's fossil generating assets
to Sithe Energies was completed in May 1998. In November 1998, Boston Edison
signed an agreement with Entergy Nuclear Generating Company to sell Pilgrim,
its wholly owned nuclear generating unit. Regulatory approvals were received
from the DTE, Federal Energy Regulatory Commission (FERC) and Nuclear
Regulatory Commission in 1999.
BEC signed a merger agreement with Commonwealth Energy System (CES) in 1998
that, upon completion, will create a new holding company, NSTAR. 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 of BEC and CES shareholders. Shareholder votes on the
merger will be held as part of each of BEC's and CES' annual shareholder
meetings scheduled for June 24, 1999.
Refer to the BEC 1998 Annual Report on Form 10-K/A for more information on
the sale of Pilgrim and the merger with CES.
Boston Edison currently supplies 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 BETG.
Refer to Note F of these Consolidated Financial Statements for information
regarding BEC's nonutility operations.
<PAGE> 8
C) 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 March 31, 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.
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 DTE. Proceedings
relative to generating unit performance remain pending before the DTE. 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 DTE 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.
<PAGE> 9
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 DTE 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 DTE ruling is expected in this
proceeding in mid-1999.
Each of the Reading Municipal Light Department, the Littleton Electric Light
Department and the West Boylston Municipal Light Department have filed
separate claims for arbitration in Massachusetts alleging that the proposed
sale of Pilgrim Station constitutes a breach of their respective power sale
agreements and seeking to terminate those agreements. The remaining
municipal light departments have also indicated that they plan to file
similar claims for arbitration. Boston Edison has requested the FERC to
exercise its pre-emptive authority to consider the claims of the municipal
light departments. In the event that either the FERC determines, or as a
result of the arbitrations, that the contracts should be terminated, Boston
Edison would continue to be obligated to purchase power from Entergy that it
intended to resell to the municipal light departments. Boston Edison may not
be able to resell such power in the short-term power exchange at a price
equal to or greater than the price it is required to pay to Entergy.
However, Boston Edison has filed at the DTE for recovery of any such
shortfall as part of its Pilgrim divestiture filing through the transition
charge.
Management is currently unable to determine the outcome of these 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.
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
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.
<PAGE> 10
D) 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 5.1 5.2
Investment tax credit amortization (1.4) (6.9)
Other 0.4 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 1.0% as a result of the associated
decrease in the amortization of investment tax credits.
E) 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 ended March 31,
1999 1998
------- -------
<S> <C> <C>
Earnings available for common shareholders $18,072 $19,940
Basic EPS $0.38 $0.41
Diluted EPS $0.38 $0.41
Weighted average common shares outstanding
for basic EPS 46,946 48,515
Effect of dilutive securities:
Weighted average dilutive potential common
shares related to share-based compensation 146 159
Weighted average common shares outstanding
for diluted EPS 47,092 48,674
</TABLE>
F) Segment and Related Information
-------------------------------
For the purpose of providing segment information, BEC's principal operating
segment, or its traditional core business, is the electric utility that
provides electric energy service, primarily in the city of Boston and 39
<PAGE> 11
surrounding cities and towns. The utility also supplies electricity at
wholesale for resale to other utilities and municipalities. The unregulated
operating segment engages in certain nonutility business activities. Such
activities include telecommunications, construction management and district
energy primarily in the Boston area. Financial data for the operating
segments are as follows (in thousands):
<TABLE>
Three months ended March 31,
<CAPTION>
Electric Unregulated
Utility Nonutility Consolidated
Operations Operations Total
---------- ---------- ------------
<S> <C> <C> <C>
1999
- ----
Operating revenues $ 371,195 $ 675 $ 371,870
Segment net income (loss) $ 24,857 $ (5,295) $ 19,562
1998
- ----
Operating revenues $ 394,555 $ (438) $ 394,117
Segment net income (loss) $ 27,545 $ (4,686)(a) $ 22,859
</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 $1,272,000
for the three months ended March 31, 1998.
G) RCN Conversion
--------------
BETG is a participant in a telecommunications venture with RCN Telecom
Services, Inc. (RCN). As part of the joint venture agreement, BETG has the
option to exchange a portion of its investment in the joint venture for
shares of RCN Corporation common stock. 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 common stock in exchange for a portion
of its joint venture interest that had a book value of $11 million. The RCN
shares received are included in other investments on the 1999 consolidated
balance sheet at their fair value of $37 million. The unrealized gain due to
the increase in market value on these shares is reflected, net of associated
income taxes, as comprehensive income on the 1999 consolidated statement of
comprehensive income and the 1999 consolidated balance sheet.
<PAGE> 12
Item 2. Management's Discussion and Analysis
- ---------------------------------------------
Results of Operations - Three Months Ended March 31, 1999 vs. Three Months
- --------------------------------------------------------------------------
Ended March 31, 1998
- --------------------
Basic and diluted earnings per common share for the three months ended
March 31, 1999 were $0.38 compared to $0.41 for the same period in 1998, a
7.3% decrease 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 decreased 5.6% during the first quarter of 1999 as
follows:
<TABLE>
<CAPTION>
(in thousands)
- ------------------------------------------------------
<S> <C>
Retail electric revenues $(17,817)
Wholesale revenues 195
Short-term sales and other revenues (4,625)
- ------------------------------------------------------
Decrease in operating revenues $(22,247)
======================================================
</TABLE>
Retail revenues were $320.1 million in 1999 compared to $337.9 million in
1998, a decrease of $17.8 million or 5%. 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 2.4% increase in retail kWh sales resulting
from a strong local economy and colder weather in 1999 than in 1998 partially
offset the impact of the rate reduction.
Total short-term sales and other revenues were $15.8 million in 1999 compared
to $20.4 million in 1998, a decrease of $4.6 million or 23%. This decrease
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 $153.2 million in 1999 compared to
$149.7 million in 1998, an increase of $3.5 million or 2%. The fuel expense
related to fossil generation units decreased $47 million reflecting the
divestiture of those units in May 1998. Purchased power expense increased
$63 million reflecting the increase in Boston Edison's purchased power
requirements in the absence of its fossil generating units. Boston Edison
collects the costs related to fuel and purchased power from customers on a
fully reconciling basis. Fuel and purchased power expense in 1999 includes
a net reduction of $11 million related to these mechanisms. Due to the rate
adjustment mechanisms, this reduction had no net impact on earnings.
<PAGE> 13
Operations and maintenance expense was $79.6 million in 1999 compared to
$96.1 million in 1998, a decrease of $16.5 million or 17%. The decrease is
primarily due to a $12 million decrease in fossil-related power production
expenses due to the fossil divestiture in May 1998. The remaining decrease
reflects lower employee benefit expense of $5 million.
Depreciation and amortization expense was $47.5 million in 1999 compared to
$46.1 million in 1998, an increase of $1.4 million or 3%. The increase is
due to the required increase in depreciation on distribution utility plant
under the terms of the Boston Edison settlement agreement partially offset by
a reduction in amortization due to the return to customers of the proceeds
from the fossil divestiture.
Demand side management (DSM) and renewable energy programs expense was $13.3
million in 1999 compared to $8.1 million in 1998, an increase of $5.2 million
or 64%. The increase reflects an increase in the required spending for DSM
programs in 1999. In addition, renewable energy programs expense increased
$3 million as a result of a state mandate for the funding of renewable energy
that became effective March 1, 1998. Renewable energy expenses are collected
through a separate rate mechanism and, therefore, have no net impact on
earnings.
Property and other taxes were $20.5 million in 1999 compared to $29.5 million
in 1998, a decrease of $9 million or 31%. The decrease is due to a decrease
in municipal property taxes of $8.5 million resulting from the fossil
divestiture.
Other expense, net
Other expense, net was $2.5 million in 1999 compared to $1.2 million in 1998,
an increase of $1.3 million. The increase is due to a $1 million increase in
equity losses from BETG's joint venture with RCN.
Interest charges
Interest charges on long-term debt were $19.5 million in 1999 compared to
$22.9 million in 1998, a decrease of $3.4 million or 15%. The decrease
reflects 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 approximately $2 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 49%. The decrease is primarily 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,
<PAGE> 14
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 due to choosing a competitive 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.
As part of the Boston Edison restructuring settlement agreement, the annual
performance adjustment charge ceased and the cost recovery mechanism for
Pilgrim Station changed effective March 1, 1998. Approximately 25% of the
operations and capital costs, including a return on investment, continues to
be collected under wholesale contracts with other utilities and
municipalities. Refer to the Electric Revenues section of Item 7 of the BEC
1998 Annual Report on Form 10-K/A for a description of Pilgrim's cost
recovery mechanism.
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 with the DTE in February
1999. Under the 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 $100 million) over a
ten-year period and recovery of the acquisition premium (estimated to be
approximately $500 million) over 40 years. The companies have proposed that
this recovery be allocated among the utility subsidiaries, including Boston
Edison. Completion of the merger is subject to the approval of this rate
plan by the DTE.
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 March 31, 1999.
In July 1998, BEC established a $225 million revolving credit agreement with
a group of banks effective through July 2001. $101 million of short-term
debt was outstanding under this credit agreement as of March 31, 1999. The
purpose of this agreement is to provide financing to the holding company for
general
<PAGE> 15
corporate purposes, invest in BEC's subsidiaries and 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 March 31, 1999, 2.1 million shares have been repurchased
at a total cost of approximately $83 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.
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 information and transaction
processing computer systems and determined that approximately one-third of
business critical systems software needed modification or replacement. BEC
defines its business critical systems as those which are necessary for the
delivery of and billing and accounting for electricity to its customers.
Plans have been developed and are being implemented to correct and test all
affected systems, with priorities assigned based on the importance of the
supported activity. As systems are being remediated or replaced, they are
tested for operational and year 2000 compliance in their own environment.
After completion of implementation, the systems are then tested for their
integration and compliance with other interactive systems. Management
estimates that approximately 85% of the efforts necessary to implement and
test its critical computer systems to alleviate the year 2000 issue are
complete and expects to complete all efforts by the end of the second quarter
of 1999. In addition, all other non-critical systems have been inventoried
and assessed. Approximately one-third of these systems required modification
or replacement. Under the year 2000 plan, each non-critical system has a
form of readiness acceptance commensurate with its business importance. The
more important and complex systems are being 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. Management expects to complete the remediation, replacement and
testing of at least 95% of its non-critical computer systems by the end of
the second quarter of 1999. All non-critical systems are scheduled for
completion by the third quarter of 1999.
BEC has also inventoried its non-information technology systems that may be
date-sensitive and that use embedded technology such as micro-controllers or
micro-processors. Approximately 27% of these systems require modification or
replacement. The three categories of these systems are (1)
telecommunications, (2) distribution system controls and (3) other
<PAGE> 16
distribution equipment. BEC is approximately 90%, 80% and 90% complete,
respectively, with its efforts to resolve and remediate the systems that have
been identified as year 2000 non-compliant within each category. BEC expects
completion of resolution and testing by the end of the second quarter of
1999.
Costs incurred to remediate non-compliant systems are expensed as incurred.
In addition, a decision was made to use this opportunity to upgrade some of
BEC's inefficient 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 $21 million on this project
through March 31, 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 all business critical vendors. Approximately
40% of the vendors indicated their systems would not be adversely impacted by
year 2000 issues. All of the vendors contacted have indicated that they will
be year 2000 compliant 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 compliant 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 compliance, BEC has a risk
that power will not be available from the New England Power Pool (NEPOOL) for
the purchase and distribution to Boston Edison's customers. Should NEPOOL
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 NEPOOL to establish inter-utility testing
guidelines to determine year 2000 readiness. Boston Edison is also a
participant in the NEPOOL/ISO New England Year 2000 Joint Oversight Committee
which has responsibility for the operational reliability of NEPOOL. Overall
regional activities, including those of NEPOOL/ISO New England, will be
coordinated by the Northeast Power Coordinating Council, whose activities
will be incorporated into the interregional coordinating effort by the North
American Electric Reliability Council. The target for the completion of this
effort is mid-1999.
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.
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.
<PAGE> 17
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 New
England requires that ISO New England dispatch at all times sufficient
resources to meet total New England load requirements. ISO New England has
the responsibility and authority to dispatch all regional generation sources
including maintaining sufficient operating reserves to respond to
unanticipated system conditions. ISO New England, in conjunction with the
New England Power Pool 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 New England plans to increase its
operating reserves during the early year 2000 period from approximately 15%
to 40%.
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.
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.
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.
<PAGE> 18
Item 3. Quantitative and Qualitative Disclosures about Market Risk
- -------------------------------------------------------------------
There have been no material changes since year-end.
<PAGE> 19
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 first quarter of 1999.
<PAGE> 20
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: May 17, 1999 /s/ Robert J. Weafer, Jr.
-----------------------------
Robert J. Weafer, Jr.
Vice President-Finance,
Controller, Assistant
Treasurer and Assistant
Clerk
<PAGE> 21
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 March 31, 1999 and the related statements of income for the
three-month periods ended March 31, 1999 and 1998 and cash flows for the
three-month periods ended March 31, 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
April 22, 1999
<PAGE> 22
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 April 22, 1999 on our review of the
interim financial information of BEC Energy (BEC) for the period ended
March 31, 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
April 22, 1999
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