Back to GetFilings.com
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
---------------
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended DECEMBER 31, 1999
Commission Exact name of registrant as specified in IRS Employer
File Number its charter Identification No.
-------------------------------------------------------------------------
1-12869 CONSTELLATION ENERGY GROUP, INC. 52-1964611
1-1910 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210
MARYLAND
(States of incorporation)
250 W. PRATT STREET, BALTIMORE, MARYLAND 21201
--------------------------------------------------
(Address of principal executive offices) (Zip Code)
410-234-5000
(Registrants' telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
Name of each exchange
Title of each class on which registered
------------------- -----------------------------
New York Stock Exchange, Inc.
Constellation Energy Group, Inc. Common } Chicago Stock Exchange, Inc.
Stock--Without Par Value Pacific Stock Exchange, Inc.
7.16% Trust Originated Preferred Securities
($25 liquidation amount per preferred secu-
rity) issued by BGE Capital Trust I, fully } New York Stock Exchange, Inc.
and unconditionally guaranteed, based on
several obligations, by Baltimore Gas and
Electric Company
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
Not Applicable
Indicate by check mark whether the registrants (1) have 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, and (2) have been subject to such filing
requirements for the past 90 days. Yes X No .
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrants' knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
Aggregate market value of Constellation Energy Group, Inc. Common Stock,
without par value, held by non-affiliates as of February 29, 2000 was
approximately $4,439,562,000 based upon New York Stock Exchange composite
transaction closing price.
CONSTELLATION ENERGY GROUP, INC. COMMON STOCK, WITHOUT PAR VALUE 149,602,816
SHARES OUTSTANDING ON FEBRUARY 29, 2000.
DOCUMENTS INCORPORATED BY REFERENCE
Part of Form 10-K Document Incorporated by Reference
----------------- ----------------------------------
III Certain sections of the Proxy Statement for Constellation
Energy Group, Inc. for the Annual Meeting of Shareholders to
be held on April 28, 2000.
Baltimore Gas and Electric Company meets the conditions set forth in General
Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this Form in
the reduced disclosure format.
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
TABLE OF CONTENTS
Page
----
Forward Looking Statements................................. 1
PART I
Item 1 -- Business
Overview................................................... 1
Electric Business.......................................... 4
Electric Operating Statistics.............................. 10
Gas Business............................................... 11
Gas Operating Statistics................................... 13
Franchises................................................. 14
Diversified Businesses..................................... 14
Consolidated Capital Requirements.......................... 17
Environmental Matters...................................... 17
Employees.................................................. 21
Item 2 -- Properties
Electric................................................... 21
Gas........................................................ 22
General.................................................... 22
Item 3 -- Legal Proceedings
Asbestos................................................... 22
Restructuring Order........................................ 23
Item 4 -- Submission of Matters to a Vote of Security Holders........ 24
Executive Officers of the Registrant (Instruction 3 to Item
401(b) of Regulation S-K).................................. 24
PART II
Item 5 -- Market for Registrant's Common Equity and Related Shareholder
Matters Stock Trading...................................... 25
Dividend Policy............................................ 25
Common Stock Dividends and Price Ranges.................... 25
Item 6 -- Selected Financial Data.................................... 26
Item 7 -- Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................. 28
Item 7A-- Quantitative and Qualitative Disclosures About Market
Risk....................................................... 47
Item 8 -- Financial Statements and Supplementary Data................ 48
Item 9 -- Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure................................... 86
PART III
Item 10 -- Directors and Executive Officers of the Registrant......... 86
Item 11 -- Executive Compensation..................................... 86
Item 12 -- Security Ownership of Certain Beneficial Owners and
Management................................................. 86
Item 13 -- Certain Relationships and Related Transactions............. 86
PART IV
Item 14 -- Exhibits, Financial Statement Schedules and Reports on
Form 8-K.................................................... 87
Signatures............................................................. 91
Forward Looking Statements
We make statements in this report that are considered forward looking
statements within the meaning of the Securities Exchange Act of 1934. Sometimes
these statements will contain words such as "believes," "expects," "intends,"
"plans," and other similar words. These statements are not guarantees of our
future performance and are subject to risks, uncertainties, and other important
factors that could cause our actual performance or achievements to be
materially different from those we project. These risks, uncertainties, and
factors include, but are not limited to:
. general economic, business, and regulatory conditions,
. energy supply and demand,
. competition,
. federal and state regulations,
. availability, terms, and use of capital,
. nuclear and environmental issues,
. weather,
. implications of the Restructuring Order by the Maryland PSC,
. commodity price risk,
. operating our currently regulated generation assets in a deregulated market
beginning July 1, 2000 without the benefit of a fuel rate adjustment clause,
. loss of revenues due to customers choosing alternative suppliers,
. higher volatility of earnings and cash flows,
. increased financial requirements of our nonregulated subsidiaries,
. inability to recover all costs associated with providing electric retail
customers service during the electric rate freeze period, and
. implications from the transfer of BGE's generation assets to nonregulated
subsidiaries of Constellation Energy.
Given these uncertainties, you should not place undue reliance on these forward
looking statements. Please see the other sections of this report and our other
periodic reports filed with the Securities and Exchange Commission for more
information on these factors. These forward looking statements represent our
estimates and assumptions only as of the date of this report.
- --------------------------------------------------------------------------------
PART I
Item 1. Business
Overview
On April 30, 1999, Constellation Energy(R) Group, Inc. (Constellation Energy)
became the holding company for Baltimore Gas and Electric Company (BGE(R)) and
Constellation(R) Enterprises, Inc. Constellation Enterprises was previously
owned by BGE. Constellation Energy was incorporated in Maryland on September
25, 1995.
References in this report to "we" and "our" are to Constellation Energy and its
subsidiaries, collectively. References in this report to the "utility business"
are to BGE.
Constellation Energy's subsidiaries primarily include BGE and a group of energy
services businesses focused mostly on power marketing and merchant generation
in North America.
BGE is an electric and gas public utility company with a service territory that
covers the City of Baltimore and all or part of ten counties in Central
Maryland. BGE was incorporated in Maryland in 1906.
BGE's electric service territory includes an area of approximately 2,300 square
miles with an estimated population of 2.7 million. BGE's gas service territory
includes an area of more than 600 square miles with an estimated population of
2.0 million. There are no municipal or cooperative wholesale customers within
BGE's service territory.
The electric utility industry is undergoing rapid and substantial change. On
April 8, 1999, Maryland enacted legislation authorizing customer choice and
competition among electric suppliers. On November 10, 1999, the Maryland Public
Service Commission (Maryland PSC) issued Order No. 75757 (Restructuring Order)
approving a Stipulation and Settlement Agreement between BGE and a majority of
the active parties involved in the electric restructuring proceeding that
resolves the major issues surrounding electric restructuring. Our electric
business will change significantly beginning July 1, 2000 as we enter into
retail customer choice for electric generation and our generation assets are
transferred from BGE to nonregulated subsidiaries of Constellation Energy.
Please refer to the Electric Regulatory Matters and Competition section for
more information.
1
As discussed throughout this report, the two units at the Calvert Cliffs
Nuclear Power Plant (Calvert Cliffs) are our principal generating facilities
and use the cheapest fuel in our system. An extended outage of either of these
units could have a substantial adverse effect on our business and financial
results.
We describe our utility business further in five other sections of this report
- -- Electric Business, Electric Operating Statistics, Gas Business, Gas
Operating Statistics, and Franchises.
Our energy services businesses are:
. Constellation Power Source,(TM) Inc. -- wholesale power marketing,
. Constellation Power,(TM) Inc. and Subsidiaries -- power projects,
. Constellation Energy Source,(TM) Inc. -- energy products and services,
. Constellation Nuclear Group,(TM) LLC -- nuclear generation and consulting
services,
. BGE Home Products & Services,(TM) Inc. and Subsidiaries -- home products,
commercial building systems, and residential and small commercial gas retail
marketing, and
. District Chilled Water General Partnership (ComfortLink(R)) -- a general
partnership, in which BGE is a partner, that provides cooling services for
commercial customers in Baltimore.
Our other businesses are:
. Constellation Investments,(TM) Inc. -- financial investments, and
. Constellation Real Estate Group,(TM) Inc. -- real estate and senior-living
facilities.
We describe our diversified businesses further in the Diversified Businesses
section.
Strategy
The change toward customer choice will significantly impact our business going
forward. In response to this change, we regularly evaluate our strategies with
two goals in mind: to improve our competitive position, and to anticipate and
adapt to regulatory change. We are realigning our organization combining all of
our domestic merchant energy businesses. We will continue to invest in the
growth of these businesses with the objective of providing new sources of
earnings. In addition, we might consider one or more of the following
strategies:
. the complete or partial separation of our transmission and distribution
functions,
. the construction, purchase or sale of generation assets,
. mergers or acquisitions of utility or non-utility businesses,
. spin-off or sale of one or more businesses, and
. growth of earnings from other nonregulated businesses.
We cannot predict whether any of the strategies described above may actually
occur, or what their effect on our financial results or competitive position
might be. However, with the shift toward customer choice, competition, and the
growth of our nonregulated subsidiaries, various factors will affect our
financial results in the future. These factors include, but are not limited to,
operating our currently regulated generation assets in a deregulated market
beginning July 1, 2000 without the benefit of a fuel rate adjustment clause,
the loss of revenues due to customers choosing alternate suppliers, higher
volatility of earnings and cash flows, and increased financial requirements of
our nonregulated subsidiaries. Please refer to the Forward Looking Statements
section for additional factors.
In addition, our Board of Directors has a Long-Range Strategy Committee to
oversee the development of our long-range strategic goals, and to consider
strategic initiatives presented by management. We also have a Corporate
Strategy and Development Group, led by a Vice President, that is responsible
for evaluating strategic objectives and developing strategy implementation.
We discuss competition in our electric and gas businesses in more detail in the
Electric Regulatory Matters and Competition and Gas Regulatory Matters and
Competition sections.
2
Revenues and Net Income by Operating Segment
The percentages of revenues and net income attributable to our electric, gas,
and diversified businesses are shown in the tables below. We present
information about our operating segments, including certain nonrecurring items,
in Note 2 to Consolidated Financial Statements. We are realigning our
organization combining all of our domestic merchant energy businesses. We have
not determined the impact of this reorganization on our operating segments, but
such change will impact our operating segments in the future.
Revenues*
-----------------------------------
Electric Gas Diversified
-------- --- ---------------------
Energy Services Other
--------------- -----
1999 60% 12% 25% 3%
1998 66 13 16 5
1997 66 16 12 6
1996 70 16 10 4
1995 76 14 6 4
Net income*/(1)/
---------------------------------------
Electric Gas Diversified
-------- --- ---------------------
Energy Services Other
--------------- -----
1999 81%/(1)/ 10% 15% (6)%
1998 85 9 13 (7)
1997 88 10 10 (8)
1996 74 11 10 5
1995 85 7 6 2
*Reflects the elimination of intercompany transactions.
/(1)/ Excludes an extraordinary charge of $66.3 million related to electric
restructuring as discussed in Note 4 to Consolidated Financial Statements.
The differences in percentages of revenues and net income for our electric and
gas businesses are due to two factors:
. our level of investment in each business, and
. our fuel costs in each business.
Our electric and gas revenues reflect amounts collected for fuel and other
operating expenses plus a return on our investment. Our investment for
ratemaking purposes in the electric business is $4.7 billion and our investment
for ratemaking purposes in the gas business is approximately $719 million. As a
result, our electric revenues include a much higher return component than our
gas revenues.
Also, as shown in our Consolidated Statements of Income in Item 8. Financial
Statements and Supplementary Data, our electric fuel costs ("Electric fuel and
purchased energy") were 22% of electric revenues in 1999, and our purchased gas
costs ("Gas purchased for resale") were 48% of gas revenues in 1999. This means
our cost of fuel in relation to our revenues is lower in the electric business
than in the gas business.
Currently and until July 1, 2000, we charge the actual cost of the fuel we use
to generate electricity and the net cost of purchases and sales of electricity
to customers with no profit to us. We discuss the elimination of the electric
fuel rate clause on July 1, 2000 further in the Electric Regulatory Matters and
Competition section. The price we charge for natural gas is based on a market
based rates incentive mechanism approved by the Maryland PSC. The difference
between our actual cost and the price we charge under market based rates does
not significantly impact earnings. We discuss market based rates further in the
Gas Regulatory Matters and Competition section.
Our electric and gas revenues come from many customers -- residential,
commercial, and industrial. In 1999, our largest electric customer provided
2.0% of our total electric revenues. In 1999, our largest gas customer provided
1.4% of our total gas revenues.
As shown in the tables above, the percentages for revenues and net income
differ for our diversified businesses due primarily to nonrecurring items
included in operations that are discussed in Note 2 to Consolidated Financial
Statements.
3
Electric Business
We get most of our revenues and net income from our electric utility business.
Our electric business will change significantly beginning July 1, 2000 as we
enter into retail customer choice for electric generation. No earlier than July
1, 2000, and after all regulatory approvals are received, BGE will transfer all
of its generation assets to nonregulated subsidiaries of Constellation Energy.
The impact of this transfer on BGE's financial results will be material. BGE's
transmission and distribution business will continue to be regulated by the
Maryland PSC. We describe this business and these changes in the sections
below.
Electric Regulatory Matters and Competition
On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition
Act of 1999 (the "Act") and accompanying tax legislation that will
significantly restructure Maryland's electric utility industry and modify the
industry's tax structure. In the Restructuring Order discussed below, the
Maryland PSC addressed the major provisions of the Act. The accompanying tax
legislation is discussed in detail in Note 4 to Consolidated Financial
Statements.
On November 10, 1999, the Maryland PSC issued a Restructuring Order that
resolves the major issues surrounding electric restructuring, accelerates the
timetable for customer choice, and addresses the major provisions of the Act.
The Restructuring Order also resolves the electric restructuring proceeding
(transition costs, customer price protections, and unbundled rates for electric
services) and a petition filed in September 1998 by the Office of People's
Counsel (OPC) to lower our electric base rates. The major provisions of the
Restructuring Order are discussed in Item 7. Management's Discussion and
Analysis--Electric Restructuring and Note 4 to Consolidated Financial
Statements.
In early December, the Mid-Atlantic Power Supply Association (MAPSA), Trigen-
Baltimore Energy Corporation, and Sweetheart Cup Company, Inc. filed appeals of
the Restructuring Order. MAPSA also filed a motion seeking to delay the
implementation of the Restructuring Order pending a decision on the merits by
the court. While we believe that the appeals are without merit, no assurances
can be given as to the timing or outcome of these cases, and whether the
outcome will have a material adverse effect on our and BGE's financial results.
We discuss these appeals further in Item 3. Legal Proceedings.
Electric utilities are facing competition on various fronts, including:
. construction of generating units to meet increased demand for electricity,
. sale of electricity in bulk power markets,
. competing with alternative energy suppliers, and
. electric sales to retail customers.
As a result of the deregulation of BGE's electric generation, no earlier than
July 1, 2000, and upon receipt of all regulatory approvals, we expect that BGE
will transfer, at book value, its nuclear generating assets and its nuclear
decommissioning trust fund to a subsidiary of Constellation Nuclear Group, LLC.
In addition, we expect that BGE will transfer, at book value, its fossil
generating assets and its partial ownership interest in two coal plants and a
hydroelectric plant located in Pennsylvania to a nonregulated subsidiary of
Constellation Energy. In total, these generating assets represent about 6,240
megawatts of generation capacity with a total projected net book value at June
30, 2000 of approximately $2.4 billion. We estimate that the electric
generation portion of our business currently represents about one-half of BGE's
operating income.
We expect BGE to transfer approximately $278 million of tax exempt debt to our
nonregulated subsidiaries related to the transferred assets and that BGE will
receive approximately $1.1 billion in unsecured promissory notes. Repayments of
the notes by our nonregulated subsidiaries will be used exclusively to service
certain long-term debt of BGE. BGE will also transfer equity associated with
the generation assets to nonregulated subsidiaries of Constellation Energy.
Under the Restructuring Order, BGE will provide standard offer service to
customers at fixed rates over various time periods during the transition period
for those customers that do not choose an alternate supplier once customer
choice begins July 1, 2000. In addition, the electric fuel rate will be
discontinued effective July 1, 2000. Nonregulated subsidiaries of Constellation
Energy will provide BGE with the energy and capacity required to meet
4
its standard offer service obligations for the first three years of the
transition period. Standard offer service will be competitively bid thereafter.
Nonregulated subsidiaries of Constellation Energy will obtain the energy and
capacity to supply BGE's standard offer service obligations from Calvert Cliffs
and BGE's former fossil plants, supplemented with energy purchased from the
wholesale energy market as necessary. Our earnings will be exposed to the risks
of the competitive wholesale electricity market to the extent that our
nonregulated subsidiaries have to purchase energy and/or capacity or generate
energy to meet obligations to supply power to BGE at market prices or costs,
respectively, which may approach or exceed BGE's standard offer service rates.
We will also be affected by operational risk, that is, the risk that a
generating plant is not available to produce energy when the energy is
required.
Until July 1, 2000, we will continue to recover our cost of fuel and purchased
energy through the electric fuel rate as long as the Maryland PSC finds that,
among other things, we have kept the productive capacity of our generating
plants at a reasonable level. To do this, the Maryland PSC will evaluate the
performance of our generating plants, and will determine if we used all
reasonable and cost-effective maintenance and operating control procedures
under the Generating Unit Performance Program. We discuss the Generating Unit
Performance Program further in Note 10 to Consolidated Financial Statements.
We have been able to recover all of our costs of fuel and purchased energy from
1992 through 1996. Under the Restructuring Order, BGE's electric fuel rate is
frozen at its current level until July 1, 2000, at which time the fuel rate
clause will be discontinued. We will continue to defer the difference between
our actual costs of fuel and energy and what we collect from customers under
the fuel rate through June 30, 2000. Any accumulated difference between our
actual costs of fuel and energy and the amounts collected from customers under
the electric fuel rate clause will be collected from our customers over a
period to be determined by the Maryland PSC.
After July 1, 2000, any energy purchased to meet BGE's load commitments will
become a cost of doing business in the newly competitive marketplace.
Therefore, if BGE provides standard offer service at fixed rates to its
customers that do not select an alternative provider as required under the
terms of the Restructuring Order, and the load demand exceeds our capacity to
supply energy due to a plant outage, we would be required to purchase
additional power in the wholesale energy market. If the price of obtaining
energy in the wholesale market exceeds the fixed standard offer service price,
our earnings would be adversely affected. Imbalances in demand and supply can
occur not only because of plant outages, but also because of transmission
constraints or due to extreme temperatures (hot or cold) causing demand to
exceed available supply.
We cannot estimate the impact of the increased financial risks associated with
this transition. However, these financial risks could have a material impact on
our, and BGE's, financial results.
Nuclear Operations
The two units at Calvert Cliffs use the cheapest fuel. As a result, the costs
of replacement energy associated with outages at these units can be
significant. If any unplanned outage were to occur during the summer or winter
when demand was at a high level, the replacement power costs could have a
material adverse impact on our financial results.
Generation
Megawatt- Capacity
Hours (MWH) Factor
----------- --------
1999....................................................... 13,309,306 91%
1998....................................................... 13,326,633 91
1997....................................................... 13,133,441 90
1996....................................................... 12,069,937 82
1995....................................................... 12,940,496 88
In 1998, we filed an application with the NRC for 20-year license renewals for
both units at Calvert Cliffs. The current operating licenses expire in 2014 for
Unit 1 and in 2016 for Unit 2. This is discussed further in Item 7.
Management's Discussion and Analysis -- Current Issues.
5
Electric Load Management, Energy and Capacity Purchases
We have implemented various programs for use when system operating conditions
require a reduction in load. We refer to these programs as active load
management programs. These programs include:
. customer-owned generation and curtailable service for large commercial and
industrial customers,
. air conditioning control which is available to residential and commercial
customers, and
. residential water heater control.
We have generally activated these programs on peak summer days. The potential
reduction in the summer 2000 peak load from active load management is
approximately 440 megawatts (MW).
We have an agreement with Pennsylvania Power & Light Company (PP&L) to purchase
electricity and capacity (availability to supply electricity) from June 1, 1990
through May 31, 2001. This agreement, which has been accepted by the FERC, is
designed to help maintain adequate reserve margins and provide flexibility in
meeting capacity obligations. The PP&L agreement:
. entitles us to 5.94% of the electricity output, and net capacity (currently
130 MW), of PP&L's nuclear Susquehanna Steam Electric Station from October
1, 1991 to May 31, 2001, and
. enables us to treat a portion of PP&L's capacity as our capacity for
purposes of satisfying our installed capacity requirements as a member of
the PJM (Pennsylvania-New Jersey-Maryland) Interconnection energy market.
The PJM is the operator of a regional transmission organization (RTO) as
well as a regional power pool with members that include many wholesale
market participants, as well as BGE and six other utility companies.
We are not acquiring an ownership interest in any of PP&L's generating units.
PP&L will continue to control, manage, operate, and maintain that station and
all other PP&L-owned generating facilities.
Our firm capacity purchases at December 31, 1999 represented:
. 150 MW of rated capacity of Bethlehem Steel Corporation's Sparrows Point
complex,
. 57 MW of rated capacity of the Baltimore Refuse Energy Systems Company, and
. 130 MW of Susquehanna capacity from PP&L.
On or about July 1, 2000, BGE will transfer certain purchase power contracts to
our nonregulated subsidiaries.
Our generation and transmission facilities are connected to those of
neighboring utility systems to form the PJM. Under the PJM agreement, we use
the interconnected facilities for substantial energy interchange and capacity
transactions as well as emergency assistance. In addition, sometimes we enter
into short-term capacity transactions to meet PJM obligations.
On December 20, 1999, the Federal Energy Regulatory Commission (FERC) issued
Order 2000, amending its regulations under the Federal Power Act to advance the
formation of RTOs. The regulations require that each public utility that owns,
operates, or controls facilities for the transmission of electric energy in
interstate commerce make certain filings with respect to forming and
participating in an RTO. FERC also identified the minimum characteristics and
functions that a transmission entity must satisfy in order to be considered an
RTO.
According to the Order, a public utility that is a member of an existing
transmission entity that has been approved by FERC as in conformance with the
Independent System Operator (ISO) principles set forth in the FERC Order No.
888 (such as BGE, through its membership in the PJM) must make a filing no
later than January 15, 2001. That filing must explain the extent to which the
transmission entity in which it participates meets the minimum characteristics
and functions of an RTO, and either propose to modify the existing institution
to the extent necessary to become an RTO, or explain the efforts, obstacles and
plans with respect to conforming to these characteristics and functions.
As a member of the PJM, an existing ISO, BGE does not expect to be
significantly impacted by the Order. However, the full impact has not yet been
determined.
6
Fuel for Electric Generation
Our electric generation by type of fuel and the cost of each fuel in the five-
year period 1995-1999 is shown below. No earlier than July 1, 2000, the
electric generation fuel contracts as discussed below will be included with the
generation assets transferred to nonregulated subsidiaries of Constellation
Energy.
Average Cost of Fuel Consumed
Generation by Fuel Type ((cent) per million BTU)
---------------------------- ----------------------------------
1999 1998 1997 1996 1995 1999 1998 1997 1996 1995
---- ---- ---- ---- ---- ------ ------ ------ ------ ------
Nuclear(a)....... 43% 44% 44% 40% 43% 45.07 45.45 46.51 47.29 47.22
Coal............. 57 58 59 58 57 140.09 137.17 140.52 143.80 148.64
Oil.............. 4 3 1 1 1 226.95 243.18 283.61 313.33 267.59
Hydro & Gas...... 3 4 3 4 3 -- -- -- -- --
--- --- --- --- ---
107 109 107 103 104
Net Interchange
Sales........... (7) (9) (7) (3) (4)
--- --- --- --- ---
100% 100% 100% 100% 100%
=== === === === ===
(a) Nuclear fuel costs include disposal costs associated with long-term off-
site spent fuel storage and shipping, which is currently set by law at one mill
per kilowatt-hour of nuclear generation (approximately 10 cents per million
Btu), and contributions to a fund for decommissioning and decontaminating the
Department of Energy's uranium enrichment facilities. We discuss this further
below.
Nuclear
The supply of fuel for nuclear generating stations includes the:
. purchase of uranium concentrates,
. conversion to uranium hexafluoride,
. enrichment of uranium hexafluoride, and
. fabrication of nuclear fuel assemblies.
Information is shown below about fuel requirements for Calvert Cliffs Units 1
and 2:
Uranium
We have, either in inventory or
Concentrates:
under contract, sufficient quantities of uranium to meet 70% to 80%
of our requirements through 2004.
Conversion:
We have contractual commitments providing for the conversion of
uranium concentrates into uranium hexafluoride which will meet
approximately 75% of our requirements through 2004.
Enrichment:
We have a contract with the U.S. Enrichment Corporation that
provides approximately 75% of our enrichment requirements, which
will decline to approximately 50% by 2004.
Fuel We have contracted for the fabrication of fuel assemblies for
reloads required through 2013.
Assembly
Fabrication:
Any remaining nuclear fuel requirements will be purchased on the spot market.
The nuclear fuel market is very competitive and we do not anticipate any
problem in meeting our requirements beyond these periods. We discuss our
expenditures for nuclear fuel in Item 7. Management's Discussion and Analysis
- -- Capital Resources.
Storage of Spent Nuclear Fuel -- Federal Facilities: Under the Nuclear Waste
Policy Act of 1982 (the 1982 Act), we contracted with the United States
Department of Energy (DOE) to place spent fuel discharged from Calvert Cliffs
into a federal repository. Such facilities do not currently exist, and,
consequently, must be developed and licensed. We cannot predict when such
facilities will be available. However, the 1982 Act required the DOE to accept
spent fuel starting in 1998. We cannot predict what the ultimate cost to
dispose of the spent fuel will be. However, the 1982 Act assesses a one mill
per kilowatt-hour fee on nuclear electricity generated and sold. We estimate
this fee to be approximately $13 million for Calvert Cliffs each year based on
expected operating levels. Fees are deposited into the Nuclear Waste Fund.
In December 1996, the DOE notified us and other nuclear utilities that it would
not be able to meet the 1998 deadline for accepting spent fuel. We participated
in litigation, along with 36 other utilities, against the DOE. The litigation,
titled Northern States Power, et al. v. DOE, was filed January 31, 1997 in the
United States Court of
7
Appeals for the D.C. Circuit. That court has original jurisdiction under the
1982 Act. The utilities asked the court to allow them to pay fees that formerly
went directly to the DOE for deposit into the Nuclear Waste Fund, into escrow
instead. Among other remedies, the utilities also asked the court to force the
DOE to submit a program with milestones illustrating how it would meet the
deadline for accepting spent nuclear fuel, and a monthly report to allow the
utilities to monitor the DOE's progress.
On November 14, 1997, the court ordered the DOE to comply with its
unconditional obligation under the 1982 Act to dispose of spent fuel. The court
did not grant the utilities the remedies sought, stating that adequate
contractual and statutory remedies already existed. The DOE and several
utilities filed separate motions for reconsideration with the court, which were
denied. The DOE's request for review to the U.S. Supreme Court was also denied.
We are currently evaluating our contractual options in light of the court's
decision. We cannot currently estimate the total amount of the costs we will
incur as a result of the DOE's failure to meet the 1998 deadline.
Storage of Spent Nuclear Fuel -- BGE Facility: We have a license from the NRC
to operate an on-site independent spent fuel storage facility. We have storage
capacity at Calvert Cliffs that will accommodate spent fuel from operations
through the year 2006. In addition, we can expand our temporary storage
capacity to meet future requirements until federal storage is available.
Costs for Decommissioning Uranium Enrichment Facilities: The Energy Policy Act
of 1992 (the 1992 Act) contains provisions requiring domestic nuclear utilities
to contribute to a fund for decommissioning and decontaminating the DOE's
uranium enrichment facilities. These contributions are generally payable over a
fifteen-year period with escalation for inflation and are based upon the amount
of uranium enriched by the DOE for each utility through 1992. The 1992 Act
provides that these costs are recoverable through utility service rates.
Information about the cost of decommissioning is discussed in Note 1 to
Consolidated Financial Statements -- Fuel And Purchased Energy Costs.
Restructuring Order Impacts: When BGE transfers its nuclear generation assets
to a nonregulated subsidiary of Constellation Energy, that subsidiary will also
become liable for the decommissioning costs of Calvert Cliffs and costs
associated with the on-site independent spent fuel storage facilities. BGE will
transfer the trust fund established to decommission Calvert Cliffs and the spent
fuel storage facilities, as well as future amounts collected from customers for
decommissioning under the Restructuring Order, to the nonregulated subsidiary.
In addition, the responsibility for quarterly fees to the DOE for the future
disposal of spent nuclear fuel and the liability for decommissioning uranium
enrichment facilities will also be transferred to a nonregulated subsidiary of
Constellation Energy. The cost for decommissioning uranium enrichment facilities
will be recovered through BGE's service rates.
Coal
We get most of our coal under supply contracts with mining operators, and we
get the rest through spot purchases. We believe that we will be able to renew
supply contracts as they expire or enter into similar contracts with other coal
suppliers. Our coal-burning facilities have the following requirements:
Annual Coal
Requirement
(tons)
-----------
Brandon Shores (a)
Units 1 and 2 (combined)........................................... 3,500,000
Crane (b)
Units 1 and 2 (combined)........................................... 800,000
Wagner (c)
Units 2 and 3 (combined)........................................... 1,000,000
Special Coal Restrictions:
(a) Sulfur content less than 0.8%
(b) Low ash melting temperature
(c) Sulfur content no more than 1%
Coal deliveries to our coal burning facilities are made by rail and barge. The
coal we use is produced from mines located in central and northern Appalachia.
We have a 20.99% undivided interest in the Keystone coal-fired generating plant
and a 10.56% undivided interest in the Conemaugh coal-fired generating plant.
Both of these plants are located in Pennsylvania. The majority of the annual
coal requirements for the Keystone plant are under contract from Rochester and
Pittsburgh Coal Company. The remainder of the Keystone plant and all of the
Conemaugh plant annual coal requirements are purchased from local suppliers on
the open market.
8
Oil
Under normal burn practices, our requirements for residual fuel oil amount to
approximately 1,500,000 to 2,000,000 barrels of low-sulfur oil per year.
Deliveries of residual fuel oil are made directly into our barges from the
suppliers' Baltimore Harbor marine terminal for distribution to the various
generating plant locations. We have contacts with various suppliers to purchase
oil at spot prices to meet our requirements.
Gas
We purchase firm natural gas transportation entitlements, as necessary, to
provide ignition and banking at certain power plants. We purchase gas for
electric generation, as needed using interruptible transportation arrangements.
Some of our gas-fired units can use residual fuel oil instead of gas.
9
Electric Operating Statistics
Year Ended December 31,
--------------------------------------------
1999 1998 1997 1996 1995
-------- -------- -------- -------- --------
Electric Output (In Thousands) --
MWH:
Generated........................ 32,684 32,372 31,289 30,107 30,548
Purchased (A).................... 3,232 3,496 4,737 7,560 7,403
-------- -------- -------- -------- --------
Subtotal........................ 35,916 35,868 36,026 37,667 37,951
Less Interchange and Other Sales.. 4,785 5,454 6,224 7,580 8,149
-------- -------- -------- -------- --------
Total Output.................... 31,131 30,414 29,802 30,087 29,802
======== ======== ======== ======== ========
Power Generated and Purchased at
Times of Peak Load (MW) (one
hour):
Generated by Company............. 5,366 5,565 5,472 4,789 5,162
Net Purchased (A)................ 1,017 480 508 1,166 785
-------- -------- -------- -------- --------
Peak Load (B)..................... 6,383 6,045 5,980 5,955 5,947
======== ======== ======== ======== ========
Annual System Load Factor (%)..... 55.7 57.4 56.9 57.5 57.2
Revenues (In Millions)
Residential...................... $ 975.2 $ 948.6 $ 932.5 $ 958.7 $ 955.2
Commercial....................... 939.3 912.9 892.6 861.3 879.4
Industrial....................... 204.3 211.5 211.9 207.6 208.5
-------- -------- -------- -------- --------
System Sales..................... 2,118.8 2,073.0 2,037.0 2,027.6 2,043.1
Interchange and Other Sales...... 112.1 120.8 132.7 155.9 167.0
Other............................ 29.1 27.0 22.3 25.5 21.0
-------- -------- -------- -------- --------
Total........................... $2,260.0 $2,220.8 $2,192.0 $2,209.0 $2,231.1
======== ======== ======== ======== ========
Sales (In Thousands) -- MWH:
Residential...................... 11,349 10,965 10,806 11,243 10,966
Commercial....................... 13,565 13,219 12,718 12,591 12,635
Industrial....................... 4,350 4,583 4,575 4,596 4,591
-------- -------- -------- -------- --------
System Sales..................... 29,264 28,767 28,099 28,430 28,192
Interchange and Other Sales...... 4,785 5,454 6,224 7,580 8,149
-------- -------- -------- -------- --------
Total........................... 34,049 34,221 34,323 36,010 36,341
======== ======== ======== ======== ========
Customers (In Thousands)
Residential...................... 1,021.4 1,009.1 1,001.0 995.2 988.2
Commercial....................... 107.7 106.5 105.9 104.5 103.4
Industrial....................... 4.7 4.6 4.5 4.3 4.1
-------- -------- -------- -------- --------
Total........................... 1,133.8 1,120.2 1,111.4 1,104.0 1,095.7
======== ======== ======== ======== ========
Average Cost of Fuel Consumed
(cents per million BTU).......... 107.27 104.05 105.76 108.05 104.78
======== ======== ======== ======== ========
We achieved an all-time peak load of 6,383 megawatts on July 6, 1999.
(A) Includes purchases from Safe Harbor Water Power Corporation, a
hydroelectric company, of which we own two-thirds of the capital stock.
(B) We discuss active load management programs that may be activated at times
of peak load in Electric Load Management, Energy, and Capacity Purchases.
10
Gas Business
We describe our gas utility business in the sections below.
Gas Regulatory Matters and Competition
Currently, no regulation exists for the wholesale price of natural gas as a
commodity, and the regulation of interstate transmission at the federal level
has been reduced. All BGE industrial and commercial gas customers and,
effective November 1, 1999, all BGE residential customers have the option to
purchase gas from other suppliers. However, the delivery of gas continues to be
regulated by the Maryland PSC.
We buy all gas that we resell directly from various suppliers (rather than
pipeline companies) and arrange separately for transportation and storage.
Alternatively, we can transport gas for our customers. We also participate in
the interstate markets, by releasing pipeline capacity or bundling pipeline
capacity with gas for off-system sales.
We provide all of our customers with the option for delivery service across our
distribution system so that they may make direct purchase and transportation
arrangements with suppliers and pipelines. In addition to the delivery service,
we also provide these customers with meter readings, billing, emergency
response, regular maintenance, and balancing.
Approximately 55% of the gas on our distribution system is for customers using
delivery service. We charge all our delivery service customers fees to recover
the fixed costs for the transportation service we provide. These fees are the
same as the base rate charged for gas sales.
Delivery service customers may choose to purchase gas from several different
suppliers, including two of our diversified businesses. The basis of
competition for delivery service customers is primarily commodity price.
As part of our response to the increase in competition in the natural gas
business, earnings from off-system gas sales and capacity release revenues are
shared between shareholders and customers. Off-system gas sales are low-margin
direct sales of gas to wholesale suppliers of natural gas outside our service
territory. We make these sales as part of a program to balance our supply of,
and cost of, natural gas. In addition, we have a market based rates incentive
mechanism for gas we sell on our system. Under market based rates, our actual
cost of gas is compared to a market index (a measure of the market price of gas
in a given period). The difference between our actual cost and the market index
is shared equally between shareholders and customers.
On November 17, 1999, we applied for a $36.3 million annual increase in our gas
base rates. The Maryland PSC is currently reviewing our application, and is
expected to issue an order by June 2000.
Gas Operations
We distribute natural gas purchased directly from many producers and marketers.
We have transportation and storage agreements as shown below. These agreements
are on file with the FERC. The gas is transported to our city gates, under
various transportation agreements, by:
. Columbia Gas Transmission Corporation,
. CNG Transmission Corporation, and
. Transcontinental Gas Pipe Line Corporation.
To transport gas from the pipelines that supply gas to the pipelines that are
connected to our city gates as mentioned above, we also have transportation
capacity under contract with:
. Texas Eastern Transmission Corporation,
. Texas Gas,
. Columbia Gulf Transmission Company, and
. ANR Pipeline Company.
We have storage service agreements with:
. Columbia Gas Transmission Corporation,
. CNG Transmission Corporation, and
. ANR Pipeline Company.
11
Our current pipeline firm transportation entitlements to serve our firm loads
are 280,553 DTH per day during the winter period and 255,533 DTH per day during
the summer period. We use the firm transportation capacity to move gas from the
Gulf of Mexico, Louisiana, south central regions of Texas, and Canada to our
city gates. We can arrange short-term contracts or exchange agreements with
other gas companies in the event of short-term emergencies.
We have three market area storage contracts to manage weather sensitive gas
demand during the winter period. Our current maximum storage entitlements are
235,080 DTH per day. To supplement our gas supply at times of heavy winter
demands and to be available in temporary emergencies affecting gas supply, we
have:
. a liquefied natural gas facility for the liquefaction and storage of natural
gas with a total storage capacity of 1,000,000 DTH and a planned daily
capacity of 287,988 DTH, and
. a propane air facility with a mined cavern with a total storage capacity
equivalent to 500,000 DTH and a planned daily capacity of 85,000 DTH.
We have under contract sufficient volumes of propane for the operation of the
propane air facility and are capable of liquefying sufficient volumes of
natural gas during the summer months for operation of our liquefied natural gas
facility during winter emergencies.
12
Gas Operating Statistics
Year Ended December 31,
---------------------------------------
1999 1998 1997 1996 1995
------- ------- ------- ------- -------
Gas Output (In Thousands)-- DTH:
Purchased............................. 49,082 47,972 62,988 70,260 70,391
LNG Withdrawn from Storage............ 463 268 484 904 815
Produced.............................. 486 46 541 784 528
------- ------- ------- ------- -------
Total Output........................ 50,031 48,286 64,013 71,948 71,734
Delivery service gas (A)............... 59,494 55,608 52,629 45,964 43,854
Off-system sales (B)................... 15,543 16,724 14,759 9,968 --
------- ------- ------- ------- -------
Total............................... 125,068 120,618 131,401 127,880 115,588
======= ======= ======= ======= =======
Peak Day Sendout (DTH)................. 727,800 658,359 765,011 708,966 706,287
======= ======= ======= ======= =======
Capability on Peak Day (DTH)........... 836,600 833,000 870,000 870,000 847,000
Revenues (In Millions)
Residential
Excluding Delivery Service........... $ 298.1 $ 279.2 $ 321.7 $ 320.1 $ 248.3
Delivery Service..................... 11.5 4.9 0.5 -- --
Commercial
Excluding Delivery Service........... 79.3 75.6 113.5 125.1 109.9
Delivery Service..................... 24.4 19.4 12.9 7.2 3.7
Industrial
Excluding Delivery Service........... 8.2 8.0 11.4 17.1 16.7
Delivery Service..................... 16.1 16.0 17.2 14.6 16.3
------- ------- ------- ------- -------
System sales.......................... 437.6 403.1 477.2 484.1 394.9
Off-system sales...................... 42.9 40.9 37.5 26.6 --
Other................................. 7.7 7.2 6.9 6.6 5.6
------- ------- ------- ------- -------
Total............................... $ 488.2 $ 451.2 $ 521.6 $ 517.3 $ 400.5
======= ======= ======= ======= =======
Sales (In Thousands) -- DTH:
Residential
Excluding Delivery Service........... 34,272 33,595 39,958 43,784 40,211
Delivery Service..................... 4,468 1,890 205 -- --
Commercial
Excluding Delivery Service........... 11,733 11,775 18,435 22,698 23,612
Delivery Service..................... 20,288 16,633 12,964 8,755 6,982
Industrial
Excluding Delivery Service........... 1,367 1,412 2,016 2,887 4,102
Delivery Service..................... 33,118 34,798 38,791 36,201 35,925
------- ------- ------- ------- -------
System sales.......................... 105,246 100,103 112,369 114,325 110,832
Off-system sales...................... 15,543 16,724 14,759 9,968 --
------- ------- ------- ------- -------
Total............................... 120,789 116,827 127,128 124,293 110,832
======= ======= ======= ======= =======
Customers (In Thousands)
Residential........................... 543.5 532.5 524.5 516.5 506.8
Commercial............................ 39.9 39.6 39.3 38.9 38.4
Industrial............................ 1.3 1.3 1.3 1.3 1.3
------- ------- ------- ------- -------
Total............................... 584.7 573.4 565.1 556.7 546.5
======= ======= ======= ======= =======
For the periods presented, we achieved an all-time peak day sendout of 765,011
DTH on January 18, 1997. Subsequently, on January 17, 2000, we achieved a new
all-time peak day sendout of 795,700 DTH.
(A) Delivery service gas is gas purchased by customers directly from suppliers
for which we receive a fee for transportation through our system.
(B) Off-system sales are low-margin sales to wholesale suppliers of natural gas
outside our service territory (beginning first quarter 1996).
We discuss these programs further in the Gas Regulatory Matters and Competition
section.
13
Franchises
We have nonexclusive electric and gas franchises to use streets and other
highways that are adequate and sufficient to permit us to engage in our present
business. All such franchises, other than the gas franchises in Manchester,
Hampstead, Perryville, Sykesville, Havre de Grace, Mt. Airy, and Montgomery and
Frederick Counties, are unlimited as to time. The gas franchises for these
jurisdictions expire at various times from 2015 to 2087, except for Havre de
Grace which has the right, exercisable at twenty-year intervals from 1907, to
purchase all of our gas properties in that municipality. Conditions of the
franchises are satisfactory.
- --------------------------------------------------------------------------------
Diversified Businesses
Our diversified businesses engage primarily in energy services that focus
mostly on power marketing and merchant generation in North America. We also
have other diversified businesses that engage in financial investments and
develop, own, and manage real estate and senior-living facilities. Our
diversified businesses are presented below. We present operating segment
information in Note 2 to Consolidated Financial Statements.
In anticipation of the deregulation of Maryland's electric industry on July 1,
2000, we are realigning our organization. We are combining the existing power
marketing functions of Constellation Power Source with domestic plant
operations, development, and generation functions of Constellation Power and no
earlier than July 1, 2000, certain portions of BGE's business. Together these
functions will form an integrated domestic merchant energy organization that
will strategically develop, own, and operate power plants, market power, and
manage risk in the wholesale energy market.
Energy Services
Our energy services businesses experience substantial competition from
utilities and their affiliates, independent power producers and other power
marketers. Competition is based on the price of the commodities, services
delivered, and the quality and reliability of services provided.
Power Marketing
Constellation Power Source, Inc. (CPS), formed in 1997, provides power
marketing and risk management services to wholesale customers in North America
through the purchase and sale of electric power, other energy commodities and
related derivative contracts. CPS has an exclusive agreement with a subsidiary
of Goldman, Sachs and Co. to serve as an advisory for power marketing and
related risk management services. CPS purchases electric power by several
methods, including:
. from regional power pools, or
. through bilateral agreements with third parties.
Upon the transfer of BGE's fossil and nuclear plants to nonregulated
subsidiaries of Constellation Energy, which is expected to occur no earlier
than July 1, 2000, CPS will also manage the output of those plants (combined
capacity of approximately 6,200 megawatts) including sales of power to BGE that
will allow BGE to meet its standard offer service obligations under the
Maryland PSC's Restructuring Order.
CPS sells the electric power it purchases to customers such as utilities,
cooperatives and other resellers, structuring the transactions to meet each
customer's diverse needs.
CPS supplies standard offer electric supply service to several distribution
utilities in New England and is currently focusing efforts in high-energy
growth areas such as Texas and the mid-west. CPS sold 69,787,986 megawatt hours
of electric power in 1999 and 27,608,080 megawatt hours in 1998, its first full
year of operation.
CPS engages in trading activities in order to manage its portfolio of energy
purchases and sales to customers through structured transactions. These
activities involve the use of a variety of instruments, including:
. forward contracts (which commit it to purchase or sell energy commodities in
the future),
. swap agreements (which require payments to or from counterparties based upon
the differential between two prices for a predetermined contractual
(notional) quantity),
. options contracts (which convey the right to buy or sell a commodity,
financial instrument or index at a predetermined price), and
. futures contracts (which are exchange traded standardized commitments to
purchase or sell a commodity or financial instrument, or make a cash
settlement, at a specified price and future date).
14
Active portfolio management allows CPS to manage and hedge its fixed price
purchase and sale commitments; provide fixed-price commitments to customers and
suppliers; reduce exposure to the volatility of cash market prices; and hedge
fuel requirements at third-party power generation facilities.
CPS' trading activities expose it to market and credit risk. CPS monitors and
controls its risk exposure through separate but complementary financial,
operational, and credit reporting systems. Our Board of Directors establishes
parameters for the risks that CPS undertakes, which management monitors. In
addition, CPS maintains a segregation of duties, with credit review and risk
monitoring functions performed by groups that are independent from revenue
producing groups.
CPS is exposed to the risk that fluctuating market prices may adversely affect
its, or our, financial results. For additional information on market risk, see
Item 7. Management's Discussion And Analysis--Market Risk.
CPS' credit risk is the loss that may result from a counterparty's non-
performance. CPS uses credit policies to control its credit risk, including
utilizing an established credit approval process, monitoring counterparty
limits, employing credit mitigation measures such as margin, collateral or
prepayment arrangements, and using master netting agreements. However, due to
the possibility of extreme short term volatility in the prices of electricity
commodities and derivatives, the market value of contractual positions with
individual counterparties could exceed established credit limits or collateral
provided by those counterparties. If such a counterparty were then to fail to
perform its obligations under its contract (for example fail to deliver the
electricity CPS had contracted for), CPS could sustain a loss that could have a
material impact on its, or our, financial results.
CPS is affected by weather conditions in the different regions of North
America. Typically, demand for electricity, and its price, is higher in the
summer and the winter, when weather is more extreme. However, not all regions
of North America typically experience extreme weather conditions at the same
time. CPS uses forward contracts, swap agreements, options contracts, and
futures contracts to monitor its risk on a regional basis and to manage its
exposure to changing weather conditions and the underlying impact on customer
usage and power availability regionally.
In March 1998, we formed Orion Power Holdings, Inc. (Orion) with Goldman, Sachs
Capital Partners II L.P., an affiliate of Goldman, Sachs & Co., to acquire
electric generating plants in the United States and Canada. Our energy services
businesses own a minority interest in Orion. To date, our energy services
businesses have funded $104 million in equity and have a commitment to
contribute an additional $121 million to Orion. Orion has entered into
strategic relationships with Constellation Power Source and Constellation
Operating Services, Inc., a subsidiary of Constellation Power, Inc.
Constellation Power Source has the exclusive right to provide power marketing
and risk management services to Orion. Currently, Constellation Operating
Services has the exclusive right to provide operating and maintenance services
to Orion's plants.
Power Projects
Constellation Power, Inc. and Subsidiaries primarily develop, own, and operate
domestic and international power projects and manage power projects owned by
Constellation Investments, Inc. Our power projects business has operated in the
nonregulated power markets since 1985.
Domestic Projects
Our power projects business holds up to a 50% ownership interest in 28 domestic
energy projects in operation or under construction that account for $531.3
million of assets. These projects consist of electric generation, fuel
processing, or fuel handling and are either qualifying facilities under the
Public Utility Regulatory Policies Act of 1978 or otherwise exempt from the
Public Utility Holding Company Act of 1935. Projects totaling approximately
$55.7 million of assets are located in the East and $475.6 million of assets
are located in the West. The electric generation projects, with a combined
capacity of 731.5 megawatts, are either biomass, coal, geothermal,
hydroelectric, solar, waste coal or municipal solid waste. Some are also
cogeneration plants. Each plant sells its output to its local utility.
Our power projects business has 17 power project sites under active
development. Construction of 800 megawatts of peaking capacity in the Mid-
Atlantic/Mid-West region is planned by the summer of 2001 and an additional
4,300 megawatts of peaking and combined cycle production facilities are
15
scheduled for completion in 2002 and beyond throughout the United States. All
of these plants will be gas fired, with some having duel fuel capability. They
are expected to sell their output under tolling arrangements or in the market
to third parties.
Our power projects business also invests in international power projects. These
are discussed later in this section.
California Power Purchase Agreements
Our Domestic-West power projects include $301.8 million invested in 14 projects
that sell electricity in California under power purchase agreements called
"Interim Standard Offer No. 4" agreements.
Under these agreements, the electricity rates change from fixed rates to
variable rates beginning in 1996 and continuing through 2000. The projects that
already have had rate changes have lower revenues under variable rates than
they did under fixed rates. When the remaining projects transition to variable
rates, we expect their revenues also to be lower than they are under fixed
rates. We discuss these projects further in Note 10 to Consolidated Financial
Statements.
Our power projects business continues to pursue alternatives for some of these
projects including:
. repowering the projects to reduce operating costs,
. changing fuels to reduce operating costs,
. renegotiating the power purchase agreements to improve the terms,
. restructuring financing to improve existing terms, and
. selling its ownership interests in the projects.
Constellation Operating Services, Inc.
Constellation Power, Inc., through its subsidiary, Constellation Operating
Services, Inc., provides operation and maintenance services, including testing
and start up, to owners of electric generating plants, including plants owned
by our power projects business and Orion Power Holdings, Inc.
International Projects
Constellation Power's business in Latin America:
. develops, acquires, owns, and operates power generation projects, and
. acquires and owns distribution systems.
At December 31, 1999, Constellation Power had invested about $254.1 million in
10 power projects in Latin America. These investments include:
. the purchase of a 51% interest in a Panamanian electric distribution company
for approximately $90 million in 1998 by an investment group in which
subsidiaries of Constellation Power hold an 80% interest, and
. approximately $98 million for the purchase of existing electric generation
facilities and the construction of an electric generation facility in
Guatemala.
In December 1999, we decided to exit the international portion of our power
projects business as part of our strategy to improve our competitive position.
We expect to complete our exit strategy by the end of 2000. We discuss this
further in Item 7. Management's Discussion And Analysis--Power Projects
section.
Energy Products and Services
Constellation Energy Source, Inc. offers energy products and services designed
primarily to provide solutions to the energy needs of mid-sized commercial and
industrial customers. These energy products and services include:
. wholesale gas marketing services,
. a full range of heating, ventilation, air conditioning, and energy services,
. energy consulting and power-quality services,
. services to enhance the reliability of individual electric supply systems,
and
. customized financing alternatives.
Constellation Nuclear Group
Constellation Nuclear Group, LLC offers nuclear consulting services to nuclear
power plant owners and operators. Upon transfer by BGE no earlier than July 1,
2000, it will also own Calvert Cliffs.
Home Products, Commercial Building Systems, and Gas Retail Marketing
BGE Home Products & Services, Inc. and Subsidiaries offer services to
residential and small commercial customers. These services include:
. the sale and service of electric and gas appliances,
. home improvements,
. the sale and service of heating, air conditioning, plumbing, electrical, and
indoor air quality systems, and
. natural gas retail marketing.
16
ComfortLink
ComfortLink provides cooling services using a central chilled water
distribution system to commercial customers in Baltimore.
Other Diversified Businesses
Financial Investments
Constellation Investments, Inc. engages in financial investments, including:
. marketable securities, and
. financial limited partnerships.
Real Estate and Senior-Living Facilities
Constellation Real Estate Group, Inc. develops, owns, and manages real estate
and senior-living facilities, including:
. land under development in the Baltimore-Washington corridor,
. a mixed-use planned-unit development,
. senior-living facilities, and
. an equity interest in Corporate Office Properties Trust (COPT), a real
estate investment trust.
We describe the real estate business and the COPT transaction further in Item
7. Management's Discussion and Analysis and Note 3 to Consolidated Financial
Statements.
We consider market demand, interest rates, the availability of financing, and
the strength of the economy in general when making decisions about our real
estate projects. If we were to decide to sell our real estate projects, we
could have write-downs. In addition, if we were to sell our real estate
projects in the current market, we would have losses which could be material,
although the amount of the losses is hard to predict. Depending on market
conditions, we could also have material losses on any future sales.
- --------------------------------------------------------------------------------
Consolidated Capital Requirements
Our business requires a great deal of capital. Our total capital requirements
for 1999 were $1,245 million. Of this amount, $778 million was used in our
utility operations and $467 million was used in our diversified businesses. We
estimate our total capital requirements for the years 2000 through 2002 to be:
. $1,920 million in 2000,
. $2,117 million in 2001, and
. $1,356 million in 2002.
We continuously review and change our capital expenditure programs, so actual
expenditures may vary from the estimates for the years 2000 through 2002.
We discuss our capital requirements further in Item 7. Management's Discussion
and Analysis-- Capital Resources.
- --------------------------------------------------------------------------------
Environmental Matters
We are subject to regulation by various federal, state, and local authorities
with regard to:
. air quality,
. water quality,
. waste disposal, and
. other environmental matters.
Some of the regulations require substantial expenditures for additions to our
utility plant and the use of more expensive low-sulfur fuels. We cannot
precisely estimate the total effect on our facilities and operations of current
and future environmental regulations and standards. However, our capital
expenditures (excluding allowance for funds used during construction) were
approximately $85 million during the five-year period 1995-1999 to comply with
existing environmental standards and regulations, and we estimate that the
future capital expenditures (excluding allowance for funds used during
construction) necessary to comply with environmental standards and regulations
will be approximately:
. $66 million in 2000,
. $53 million in 2001, and
. $ 4 million in 2002.
Clean Air
The Federal Clean Air Act (the Act) regulates health and welfare standards for
concentrations of air
17
pollutants. Under the Act, the State of Maryland must set limits on all major
sources of these pollutants in the State so that the standards are not
exceeded. We have certain limits on our generating units that put us in
compliance with existing air quality regulations, as follows:
. All of our generating units, except Crane Units 1 and 2, are limited to
burning fuel (coal or oil) with a sulfur content of 1% or below.
. The Crane Units 1 and 2 are limited to 3.5 pounds of sulfur dioxide per
million Btu, which is equivalent to a coal sulfur content of approximately
2.4%.
. All units are limited to releasing particulate matter at or below 0.02
grains per standard cubic foot of exhaust gas for oil fired units and 0.03
grains per standard cubic foot for coal-fired units.
. Brandon Shores, a newer plant, is subject to more stringent standards for
sulfur dioxides (1.2 pounds per million Btu), and nitrogen oxides (0.7
pounds per million Btu).
The Clean Air Act of 1990 contains two titles designed to reduce emissions of
sulfur dioxides and nitrogen oxides (NOx) from electric generating stations --
Title IV and Title I.
Title IV addresses emissions of sulfur dioxides. Compliance is required in two
separate phases:
. Phase I became effective January 1, 1995. We met the requirements of this
phase by installing flue gas desulfurization systems, switching fuels, and
retiring some units.
. Phase II became effective January 1, 2000. We met the compliance
requirements through a combination of switching fuels and allowance trading.
Title I addresses emissions of NOx. The Maryland Department of the Environment
(MDE) has issued regulations, effective October 18, 1999, which require up to
65% NOx emissions reductions by May 1, 2000. We have entered into a settlement
agreement with the MDE since we cannot meet this deadline. Under the terms of
the settlement agreement, BGE will install emissions reduction equipment at two
sites by May 2002. In the meantime, we are taking steps to control NOx
emissions at our generating plants.
The Environmental Protection Agency (EPA) issued a final rule in September 1998
that requires up to 85% NOx emissions reduction by 22 states including Maryland
and Pennsylvania. Maryland will meet the requirements of the rule by 2003.
Based on the MDE and EPA regulations, we currently estimate that the additional
controls needed at our generating plants to meet the 65% NOx emission reduction
requirements will cost approximately $135 million. Through December 31, 1999,
we have spent approximately $51 million to meet the MDE's 65% reduction
requirements. We estimate the additional cost for the EPA's 85% reduction
requirements to be approximately $35 million by 2003.
In July 1997, the EPA published new National Ambient Air Quality Standards for
very fine particulates and revised standards for ozone attainment. In 1999,
these new standards were successfully challenged in court. The EPA is expected
to appeal the 1999 court rulings to the Supreme Court. While these standards
may require increased controls at our fossil generating plants in the future,
implementation will be delayed for several years. We cannot estimate the cost
of these increased controls at this time because the states, including Maryland
and Pennsylvania, still need to determine what reductions in pollutants will be
necessary to meet the federal standards.
Water
The MDE regulates the discharge of waste materials into the waters of the State
of Maryland under the National Pollutant Discharge Elimination System permit
program. This program was established as part of the Federal Clean Water Act.
At the present time, we have the required permits under the program for all of
our steam electric generating plants.
The MDE water quality regulations require us to, among other things, define
procedures to determine compliance with State water quality standards. These
procedures require extensive studies involving sampling and monitoring of the
waters around affected generating plants. The State of Maryland may require
changes in plant operations. We continually perform studies to determine
whether any changes will be necessary to comply with these regulations.
Waste Disposal
The EPA has regulations for implementing the portions of the Resource
Conservation and Recovery
18
Act that deal with the management of hazardous wastes. These regulations, and
the Hazardous and Solid Waste Amendments of 1984, identify certain spent
materials as hazardous wastes and establish standards and permit requirements
for those who generate, transport, store, or dispose of such wastes. The State
of Maryland has adopted regulations governing the management of hazardous
wastes that are similar to the EPA regulations. We have procedures in place to
comply with all applicable EPA and State of Maryland regulations governing the
management of hazardous wastes. Some high volume utility wastes, such as coal
fly ash and bottom ash, are exempt from these regulations. We mostly use our
coal fly ash and bottom ash as structural fill material in a manner approved by
the State of Maryland. Beginning in 1999, we provided some of our coal fly ash
to a processing facility that is designed to recycle it into a new material
that can be sold to the construction industry. We sell the remainder of the
coal ash to the construction industry for a number of other approved uses.
The Federal Comprehensive Environmental Response, Compensation and Liability
Act (Superfund statute) establishes liability for the cleanup of hazardous
wastes that contaminate the soil, water, or air. Those who generated,
transported, or deposited the waste at the contaminated site are each jointly
and severally liable for the cost of the cleanup, as are the current property
owner and the owner when the contamination occurred. Many states have
implemented laws similar to the Superfund statute.
The EPA and several state agencies have notified us that we are considered a
potentially responsible party with respect to the cleanup of certain
environmentally contaminated sites owned and operated by others. We cannot
estimate the cleanup costs for all of these sites.
In the early 1970s, we shipped an unknown number of scrapped transformers to
Metal Bank of America, a metal reclaimer in Philadelphia. Metal Bank's scrap
and storage yard has been found to be contaminated with oil containing high
levels of PCBs (hazardous chemicals frequently used as a fire-resistant coolant
in electrical equipment). On December 7, 1987, the EPA notified us and nine
other utilities that we are considered potentially responsible parties (PRPs)
with respect to the cleanup of the site. We, along with the other PRPs,
submitted a remedial investigation and feasibility study (RI/FS) to the EPA on
October 14, 1994, and the EPA issued its Record of Decision (ROD) on December
31, 1997. On June 26, 1998, the EPA ordered us, the other utility PRPs, and the
owner/ operator to implement the requirements of the ROD. The utility PRPs are
currently conducting the remedial design. Based on the ROD, our share of the
reasonably possible cleanup costs, estimated to be approximately 15.43%, could
be as much as $4.9 million higher than amounts we have recorded as a liability
on our Consolidated Balance Sheets.
On October 16, 1989, the EPA filed a complaint in the U.S. District Court for
the District of Maryland under the Superfund statute against us and seven other
defendants to recover past and future expenditures associated with the cleanup
of a site located at Kane and Lombard Streets in Baltimore. The State of
Maryland filed a similar complaint in the same case and court on February 12,
1990. The complaints alleged that we arranged for our coal fly ash to be
deposited on the site. The Court dismissed these complaints in November 1995.
The MDE began additional investigation on the remainder of the site for the
EPA, but never completed the investigation. We, along with three other
defendants, agreed to complete the RI/FS of groundwater contamination around
the site in a July 1993 consent order. The remedial action, if any, for the
remainder of the site will not be selected until these investigations are
concluded. Therefore, we cannot estimate the total amount, or our share of the
site cleanup costs.
From 1985 until 1989, we shipped waste oil and other materials to the
Industrial Solvents and Chemical Company in York County, Pennsylvania for
disposal. The Pennsylvania Department of Environmental Protection (PADEP)
subsequently investigated this site and found it to be heavily contaminated by
hazardous wastes. The PADEP notified us on August 15, 1990, that approximately
1,000 other entities and we are PRPs with respect to the cost of all remedial
activities to be conducted at the site. The PRPs have performed waste
characterization, removed and disposed of all tanks and drums of waste,
completed a RI/FS at the site, and installed public water lines. In 1998, PADEP
notified BGE and other PRPs of the final remedy and requested the installation
of additional public water lines. In 1999, the PRPs installed the water
19
lines and once PADEP approves the final report, we will have no further
obligations under the consent orders at the site.
In December 1995, the EPA notified us that we are one of approximately 650
parties that may have incurred liability under the Superfund statute for
shipments of hazardous wastes to a site in Denver, Colorado known as the RAMP
Industries site. We, through our disposal vendor, shipped a small amount of low
level radioactive waste to the site between 1989 and 1992. The site, which was
found to have been operated improperly, was closed in 1994. That same year, the
EPA began cleaning up the site by removing drums of radioactive and hazardous
mixed wastes. BGE accepted a settlement offer from EPA in August 1999, whereby
BGE will pay an immaterial amount to resolve its liability at this site. The
consent order will be finalized in 2000.
In September 1996, we received an information request from the EPA about the
Drumco Drum Dump Site, located in the Curtis Bay area of Maryland. This site
was the subject of an emergency drum removal action in 1991, due to a concern
about hazardous substances leaking from drums and posing a threat to human
health and the environment. According to EPA documents, approximately $2
million dollars were spent on the drum removal action. To our knowledge, no
long-term remediation is planned for this site. In addition, we understand that
the EPA has sent information requests to approximately 17 other parties. Our
records indicate that we sold empty drums to Drumco, Inc. from approximately
1983-1990. Although our potential liability cannot be estimated, we do not
expect such liability to be material based on our records showing that we sold
only empty storage drums to Drumco, Inc.
On July 12, 1999, the EPA notified us, along with nineteen other entities, that
we may be a potentially responsible party at the 68th Street Dump/Industrial
Enterprises Site, also known as the Robb Tyler Dump located in Baltimore,
Maryland. The EPA indicated that it is proceeding with plans to conduct a
remedial investigation and feasibility study. This site was proposed for
listing as a federal Superfund site in January 1999, but the listing has not
been finalized. Although our potential liability cannot be estimated, we do not
expect such liability to be material based on our records showing that we did
not send waste to the site.
In the early part of the century, predecessor gas companies (which were later
merged into BGE) manufactured coal gas for residential and industrial use. The
residue from this manufacturing process was coal tar, previously thought to be
harmless but now found to contain a number of chemicals designated by the EPA
as hazardous substances. We are coordinating an investigation of some of these
former manufacturing sites, and determining what, if any, remedial action may
be required by MDE.
In late December 1996, we signed a consent order with the MDE that requires us
to implement remedial action plans for contamination at and around the Spring
Gardens site, located in Baltimore, Maryland. We submitted the required
remedial action plans and they have been approved by the MDE. Based on the
remedial action plans, the costs we consider to be probable to remedy the
contamination are estimated to total $47 million in nominal dollars (including
inflation). We have recorded these costs as a liability on our Consolidated
Balance Sheets and have deferred these costs, net of accumulated amortization
and amounts we recovered from insurance companies, as a regulatory asset. We
discuss this further in Note 5 to Consolidated Financial Statements. Through
December 31, 1999, we have spent approximately $34 million for remediation at
this site.
We are also required by accounting rules to disclose additional costs we
consider to be less likely than probable, but still "reasonably possible" of
being incurred at these sites. Because of the results of studies at these
sites, it is reasonably possible that these additional costs could exceed the
amount we recognized by approximately $14 million in nominal dollars ($7
million in current dollars, plus the impact of inflation at 3.1% over a period
of up to 36 years).
20
Employees
As of December 31, 1999, we employed about 9,000 people.
Item 2. Properties
We describe our electric and gas business properties separately below. We lease
several properties in our service area which are used for Constellation
Energy's headquarters, various offices, and services. We own our principal
plants and other important units that are located in Maryland including BGE's
principal headquarters building in downtown Baltimore. None of the properties
used in connection with the operation of our diversified businesses are
considered material to Constellation Energy.
Electric
Our principal electric properties are discussed below:
Generation (MWH)
Installed ---------------------
Generating Plant Location Capacity (MW) Primary Fuel 1999 1998
- ---------------- -------- ---------------------- ------------ ---------- ----------
(at December 31, 1999)
----------------------
Steam
Calvert Cliffs Calvert County, MD 1,685 Nuclear 13,309,306 13,326,633
Brandon Shores Anne Arundel County, MD 1,300 Coal 9,116,356 8,259,725
Herbert A. Wagner Anne Arundel County, MD 1,006 Coal/Oil/Gas 3,529,019 4,108,074
Charles P. Crane Baltimore County, MD 385 Coal 2,314,076 1,995,318
Gould Street Baltimore City, MD 104 Oil 112,327 137,560
Riverside Baltimore County, MD 78 Oil/Gas 42,039 46,322
Jointly Owned -- Steam
Keystone Armstrong and Indiana
Counties, PA 359(A) Coal 2,755,946 2,800,921
Conemaugh Indiana County, PA 181(A) Coal 1,335,411 1,387,837
Combustion Turbine
Perryman Harford County, MD 350 Oil/Gas 92,464 234,990
Notch Cliff Baltimore County, MD 128 Gas 28,954 29,644
Westport Baltimore City, MD 121 Gas 16,460 20,814
Riverside Baltimore County, MD 173 Oil/Gas 19,639 11,989
Philadelphia Road Baltimore City, MD 64 Oil 8,026 8,021
Charles P. Crane Baltimore County, MD 14 Oil 1,919 2,247
Herbert A. Wagner Anne Arundel County, MD 14 Oil 1,713 1,665
----- ---------- ----------
Totals 5,962 32,683,655 32,371,760
===== ========== ==========
- --------
(A) These totals reflect BGE's proportionate interest and entitlement to
capacity from Keystone and Conemaugh, which include 2 megawatts of diesel
capacity for Keystone and 1 megawatt of diesel capacity for Conemaugh. We
share the ownership of the properties for the Keystone and Conemaugh plants
in Pennsylvania. There are minor liens and easements on the Keystone and
Conemaugh properties, but these encumbrances do not materially interfere
with our use of the properties.
We also own two-thirds of the outstanding capital stock of Safe Harbor Water
Power Corporation, and are currently entitled to 277 megawatts of the rated
capacity of the Safe Harbor Hydroelectric Project. Safe Harbor is operated
under a Federal Energy Regulatory Commission license which expires in 2030.
21
Gas
We own the following propane air and liquefied natural gas facilities:
. a liquefied natural gas facility for the liquefication and storage of
natural gas with a total storage capacity of 1,000,000 DTH and a planned
daily capacity of 287,988 DTH, and
. a propane air facility with a mined cavern with a total storage capacity of
500,000 DTH and a planned daily capacity of 85,000 DTH.
We also have rights-of-way to maintain 26-inch natural gas mains across certain
Baltimore City owned property (principally parks) which expire in 2004. These
rights-of-way can be renewed during their last year for an additional period of
25 years based on a fair revaluation.
General
We have electric transmission and electric and gas distribution lines located:
. in public streets and highways pursuant to franchises, and
. on permanent rights-of-way secured for the most part by grants from owners
of the property and for a relatively small part by condemnation. Conditions
of the grants are satisfactory.
All of BGE's property, including the generation assets that will be transferred
as part of deregulation, is subject to the lien of BGE's mortgage securing its
mortgage bonds.
- --------------------------------------------------------------------------------
Item 3. Legal Proceedings
Asbestos
Since 1993, we have been involved in several actions concerning asbestos. The
actions are based upon the theory of "premises liability," alleging that we
knew of and exposed individuals to an asbestos hazard. The actions relate to
two types of claims.
The first type is direct claims by individuals exposed to asbestos. We
described these claims in a Report on Form 8-K filed August 20, 1993. We are
involved in these claims with approximately 70 other defendants. Approximately
530 individuals that were never employees of BGE each claim $6 million in
damages ($2 million compensatory and $4 million punitive). These claims were
filed in the Circuit Court for Baltimore City, Maryland in the summer of 1993.
We do not know the specific facts necessary to estimate our potential liability
for these claims. The specific facts we do not know include:
. the identity of our facilities at which the plaintiffs allegedly worked as
contractors,
. the names of the plaintiff's employers, and
. the date on which the exposure allegedly occurred.
To date, 23 of these cases were settled for amounts that were not significant.
The second type is claims by one manufacturer -- Pittsburgh Corning Corp. --
against us and approximately eight others, as third-party defendants. These
claims relate to approximately 1,500 individual plaintiffs and were filed in
the Circuit Court for Baltimore City, Maryland in the fall of 1993. To date,
about 140 cases have been resolved, all without any payment by BGE. We do not
know the specific facts necessary to estimate our potential liability for these
claims. The specific facts we do not know include:
. the identity of our facilities containing asbestos manufactured by the
manufacturer,
. the relationship (if any) of each of the individual plaintiffs to us,
. the settlement amounts for any individual plaintiffs who are shown to have
had a relationship to us, and
. the dates on which/places at which the exposure allegedly occurred.
Until the relevant facts for both types of claims are determined, we are unable
to estimate what our liability, if any, might be. Although insurance and hold
harmless agreements from contractors who employed the plaintiffs may cover a
portion of any awards in the actions, our potential liability could be
material.
22
Restructuring Order
Three separate appeals of the Restructuring Order issued by the Maryland PSC
have been filed. Two appeals, one by Trigen--Baltimore Energy Corporation and
the other by Sweetheart Cup Company were filed on December 9, 1999 in the
Circuit Court for Baltimore City. The third appeal was filed by the Mid-
Atlantic Power Supply Association (MAPSA) on December 10, 1999 in the Circuit
Court for Prince Georges County. MAPSA's appeal has been transferred to the
Circuit Court for Baltimore City.
Each appeal asks for a review of the Restructuring Order. MAPSA also seeks to
delay the implementation of the Restructuring Order until a decision on the
merits of the appeals by the court.
We believe that the appeals are without merit. However, if a delay in
implementation is granted or the appeals are successful, it could have a
material adverse effect on our and BGE's financial results.
See Item 1. Business -- Electric Regulatory Matters and Competition, Nuclear
Operations, Fuel for Electric Generation, Gas Regulatory Matters and
Competition, Environmental Matters, and Item 7. Management's Discussion and
Analysis and Note 10 to Consolidated Financial Statements for other information
about our legal or regulatory proceedings.
23
Item 4. Submission of Matters to Vote of Security Holders
Not applicable.
Executive Officers of the Registrant
BGE meets the conditions set forth in General Instruction I(1)(a) and (b) of
Form 10-K for a reduced disclosure format. Accordingly, the executive officers
of BGE are not presented below.
Executive Officers of Constellation Energy Group at the date of this report
are:
Other BGE Offices or
Positions
Name Age Present Office Held During Past Five Years
---- --- -------------- ---------------------------
Christian H. Poindexter 61 Chairman of the Board, President Chairman of the Board,
and Chief Executive Officer (A) President, and Chief
(Since formation of Executive Officer
Constellation Energy Group as
the holding company on April 30,
1999; since March 1, 1998 for
BGE)
Thomas F. Brady 50 Vice President Corporate Strategy Vice President, Corporate
and Development (Since April 30, Strategy and Development,
1999) Vice President, Retail
Services Vice President,
Customer Service and
Distribution
David A. Brune 59 Vice President Finance and General Counsel
Accounting, Chief Financial
Officer and Secretary (Since
formation of Constellation
Energy Group as the holding
company on April 30, 1999; since
February 25, 1997 for BGE)
Robert S. Fleishman 46 Vice President Corporate Affairs General Counsel
and General Counsel (Since Associate General Counsel--
formation of Constellation Regulatory
Energy Group as the holding
company on April 30, 1999; since
May 1, 1998 for BGE)
Linda D. Miller 49 Vice President Human Resources Vice President, Management
(Since formation of Services Manager, Employee
Constellation Energy Group as Services
the holding company on April 30,
1999; since May 1, 1998 for BGE)
- --------
(A) Chief Executive Officer, Director, and member of the Executive Committee.
Officers of Constellation Energy Group are elected by, and hold office at the
will of, the Board of Directors and do not serve a "term of office" as such.
There is no arrangement or understanding between any director or officer and
any other person pursuant to which the director or officer was selected.
24
PART II
Item 5. Market for Registrant's Common Equity and Related Shareholder Matters
Stock Trading
Constellation Energy's common stock is traded under the ticker symbol CEG. It
is listed on the New York, Chicago, and Pacific stock exchanges. It has
unlisted trading privileges on the Boston, Cincinnati, and Philadelphia
exchanges.
As of February 29, 2000, there were 65,226 common shareholders of record.
Dividend Policy
Constellation Energy pays dividends on its common stock after its Board of
Directors declares them. There is no limitation on Constellation Energy paying
common stock dividends.
BGE pays dividends on its common stock after its Board of Directors declares
them. There is no limitation on BGE paying common stock dividends unless:
. BGE elects to defer interest payments on the 7.16% Deferrable Interest
Subordinated Debentures due June 30, 2038, and any deferred interest remains
unpaid; or
. all dividends (and any redemption payments) due on BGE's preference stock
have not been paid.
Dividends have been paid on the common stock continuously since 1910. Future
dividends depend upon future earnings, our financial condition, and other
factors. Quarterly dividends were declared on the common stock during 1999 and
1998 in the amounts set forth below. Dividends paid prior to April 30, 1999
were on BGE common stock. As a result of the share exchange Constellation
Energy is the successor of BGE.
Common Stock Dividends and Price Ranges
1999 1998
--------------------- -----------------------
Price* Price*
------------ --------------
Dividend Dividend
Declared High Low Declared High Low
-------- ---- ---- -------- ---- ----
First Quarter............ $ .42 $31 1/8 $24 11/16 $ .41 $34 1/8 $29 3/4
Second Quarter........... .42 31 3/8 25 1/8 .42 32 15/16 29 1/4
Third Quarter............ .42 30 7/8 27 3/16 .42 33 5/8 29 5/16
Fourth Quarter........... .42 31 1/2 27 1/2 .42 35 1/4 30 1/8
----- -----
Total................... $1.68 $1.67
===== =====
- --------
* Based on New York Stock Exchange Composite Transactions as reported in THE
WALL STREET JOURNAL.
25
Item 6. Selected Financial Data
Constellation Energy Group, Inc. and Subsidiaries
1999 1998 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------
(Dollar amounts in millions, except per share amounts)
Summary of Operations
Total Revenues $3,786.2 $3,358.1 $3,307.6 $3,153.2 $2,934.8
Operating Expenses 3,026.3 2,617.0 2,584.0 2,483.7 2,239.1
- --------------------------------------------------------------------------------------------------------------
Income From Operations 759.9 741.1 723.6 669.5 695.7
Other Income (Expense) 7.9 5.7 (52.8) 6.1 8.8
- --------------------------------------------------------------------------------------------------------------
Income Before Fixed Charges
and Income Taxes 767.8 746.8 670.8 675.6 704.5
Fixed Charges 255.0 262.7 258.7 237.0 237.6
- --------------------------------------------------------------------------------------------------------------
Income Before Income Taxes 512.8 484.1 412.1 438.6 466.9
Income Taxes 186.4 178.2 158.0 166.3 169.5
- --------------------------------------------------------------------------------------------------------------
Income Before Extraordinary Item 326.4 305.9 254.1 272.3 297.4
Extraordinary Loss, Net of Income Taxes (66.3) - - - -
- --------------------------------------------------------------------------------------------------------------
Net Income $ 260.1 $ 305.9 $ 254.1 $ 272.3 $ 297.4
==============================================================================================================
Earnings Per Share of Common Stock
and Earnings Per Share of Common
Stock-- Assuming Dilution Before
Extraordinary Item $ 2.18 $ 2.06 $ 1.72 $ 1.85 $ 2.02
Extraordinary Loss, Net of Income Taxes (.44) - - - -
- --------------------------------------------------------------------------------------------------------------
Earnings Per Share of Common Stock and
Earnings Per Share of Common Stock--
Assuming Dilution $ 1.74 $ 2.06 $ 1.72 $ 1.85 $ 2.02
==============================================================================================================
Dividends Declared Per Share
of Common Stock $ 1.68 $ 1.67 $ 1.63 $ 1.59 $ 1.55
==============================================================================================================
Summary of Financial Condition
Total Assets $9,683.8 $9,275.0 $8,900.0 $8,678.2 $8,419.1
==============================================================================================================
Capitalization
Long-term debt $2,575.4 $3,128.1 $2,988.9 $2,758.8 $2,598.2
Preferred stock - - - - 59.2
Redeemable preference stock - - 90.0 134.5 242.0
Preference stock not subject to
mandatory redemption 190.0 190.0 210.0 210.0 210.0
Common shareholders' equity 2,993.0 2,981.5 2,870.4 2,854.7 2,811.2
- --------------------------------------------------------------------------------------------------------------
Total Capitalization $5,758.4 $6,299.6 $6,159.3 $5,958.0 $5,920.6
==============================================================================================================
Financial Statistics at Year End
Ratio of Earnings to Fixed Charges 2.87 2.60 2.35 2.44 2.52
Book Value Per Share of Common Stock $ 20.01 $ 19.98 $ 19.44 $ 19.33 $ 19.06
Number of Common Shareholders (In Thousands) 66.1 69.9 73.7 77.6 79.8
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
26
Baltimore Gas and Electric Company and Subsidiaries
1999 1998 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------
(Dollar amounts in millions, except per share amounts)
Summary of Operations
Total Revenues $3,028.3 $3,358.1 $3,307.6 $3,153.2 $2,934.8
Operating Expenses 2,324.0 2,617.0 2,584.0 2,483.7 2,239.1
- --------------------------------------------------------------------------------------------------------------
Income From Operations 704.3 741.1 723.6 669.5 695.7
Other Income (Expense) 8.4 5.7 (52.8) 6.1 8.8
- --------------------------------------------------------------------------------------------------------------
Income Before Fixed Charges
and Income Taxes 712.7 746.8 670.8 675.6 704.5
Fixed Charges 205.9 240.9 230.0 198.5 197.0
- --------------------------------------------------------------------------------------------------------------
Income Before Income Taxes 506.8 505.9 440.8 477.1 507.5
Income Taxes 178.4 178.2 158.0 166.3 169.5
- --------------------------------------------------------------------------------------------------------------
Income Before Extraordinary Item 328.4 327.7 282.8 310.8 338.0
Extraordinary Loss, Net of Income Taxes (66.3) - - - -
- --------------------------------------------------------------------------------------------------------------
Net Income 262.1 327.7 282.8 310.8 338.0
Preferred and Preference Stock Dividends 13.5 21.8 28.7 38.5 40.6
- --------------------------------------------------------------------------------------------------------------
Earnings Applicable to Common Stock $ 248.6 $ 305.9 $ 254.1 $ 272.3 $ 297.4
==============================================================================================================
Summary of Financial Condition
Total Assets $7,272.6 $9,275.0 $8,900.0 $8,678.2 $8,419.1
==============================================================================================================
Capitalization
Long-term debt $2,206.0 $3,128.1 $2,988.9 $2,758.8 $2,598.2
Preferred stock - - - - 59.2
Redeemable preference stock - - 90.0 134.5 242.0
Preference stock not subject to
mandatory redemption 190.0 190.0 210.0 210.0 210.0
Common shareholder's equity 2,355.4 2,981.5 2,870.4 2,854.7 2,811.2
- --------------------------------------------------------------------------------------------------------------
Total Capitalization $4,751.4 $6,299.6 $6,159.3 $5,958.0 $5,920.6
==============================================================================================================
Financial Statistics at Year End
Ratio of Earnings to Fixed Charges 3.45 2.94 2.78 3.10 3.21
Ratio of Earnings to Combined Fixed Charges and
Preferred and Preference Stock Dividends 3.14 2.60 2.35 2.44 2.52
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
27
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Introduction
On April 30, 1999, Constellation Energy(R) Group, Inc. (Constellation Energy)
became the holding company for Baltimore Gas and Electric Company (BGE(R)) and
Constellation(R) Enterprises, Inc. Constellation Enterprises was previously
owned by BGE.
Constellation Energy's subsidiaries primarily include BGE and a group of energy
services businesses focused mostly on power marketing and merchant generation in
North America.
BGE is an electric and gas public utility company with a service territory that
covers the City of Baltimore and all or part of ten counties in Central
Maryland.
Our energy services businesses are:
. Constellation Power Source,(TM) Inc.--wholesale power marketing,
. Constellation Power,(TM) Inc. and Subsidiaries--power projects,
. Constellation Energy Source,(TM) Inc.--energy products and services,
. Constellation Nuclear Group,(TM) LLC--nuclear generation and
consulting services,
. BGE Home Products & Services,(TM) Inc. and Subsidiaries--home
products, commercial building systems, and residential and small
commercial gas retail marketing, and
. District Chilled Water General Partnership (ComfortLink(R)) --a
general partnership, in which BGE is a partner, that provides cooling
services for commercial customers in Baltimore.
Our other businesses are:
. Constellation Investments,(TM) Inc.--financial investments, and
. Constellation Real Estate Group,(TM) Inc.--real estate and
senior-living facilities.
This report is a combined report of Constellation Energy and BGE. The
consolidated financial statements of Constellation Energy include the accounts
of Constellation Energy, BGE and its subsidiaries, Constellation Enterprises,
Inc. and its subsidiaries, and Constellation Nuclear Group, LLC and its
subsidiaries. The consolidated financial statements of BGE include the accounts
of BGE, ComfortLink, and BGE Capital Trust I. As Constellation Enterprises and
its subsidiaries were subsidiaries of BGE prior to April 30, 1999, they are
included in the consolidated financial statements of BGE through that date.
References in this report to "we" and "our" are to Constellation Energy and its
subsidiaries, collectively. References in this report to the "utility business"
are to BGE.
In this discussion and analysis, we explain the general financial condition and
the results of operations for Constellation Energy and BGE including:
. what factors affect our business,
. what our earnings and costs were in 1999 and 1998,
. why earnings and costs changed from the year before,
. where our earnings came from,
. how all of this affects our overall financial condition,
. what our expenditures for capital projects were in 1997 through 1999,
and what we expect them to be in 2000 through 2002, and
. where we expect to get cash for future capital expenditures.
As you read this discussion and analysis, refer to our Consolidated Statements
of Income, which present the results of our operations for 1999, 1998, and 1997.
We analyze and explain the differences between periods by operating segment. Our
analysis is important in making decisions about your investments in
Constellation Energy and/or BGE.
Also, this discussion and analysis is based on the operation of the electric
generation portion of our utility business under current rate regulation. The
electric utility industry is undergoing rapid and substantial change. On April
8, 1999, Maryland enacted legislation authorizing customer choice and
competition among electric suppliers. On November 10, 1999, the Maryland Public
Service Commission (Maryland PSC) issued Order No. 75757 (Restructuring Order)
approving a Stipulation and Settlement Agreement between BGE and a majority of
the active parties involved in the electric restructuring proceeding that
resolves the major issues surrounding electric restructuring. See the "Electric
Restructuring" section and Note 4 for a detailed discussion of the Restructuring
Order.
Our electric business will change significantly beginning July 1, 2000 as we
enter into retail customer choice for electric generation and our generation
assets are transferred to nonregulated subsidiaries of Constellation Energy.
Accordingly, the results of operations and financial condition described in this
discussion and analysis are not necessarily indicative of future performance.
28
Strategy
The change toward customer choice will significantly impact our business going
forward. In response to this change, we regularly evaluate our strategies with
two goals in mind: to improve our competitive position, and to anticipate and
adapt to regulatory change. We are realigning our organization combining all of
our domestic merchant energy businesses. We will continue to invest in the
growth of these businesses, with the objective of providing new sources of
earnings. In addition, we might consider one or more of the following
strategies:
. the complete or partial separation of our transmission and
distribution functions,
. the construction, purchase or sale of generation assets,
. mergers or acquisitions of utility or non-utility businesses,
. spin-off or sale of one or more businesses, and
. growth of earnings from other nonregulated businesses.
We cannot predict whether any of the strategies described above may actually
occur, or what their effect on our financial results or competitive position
might be. However, with the shift toward customer choice, competition, and the
growth of our nonregulated subsidiaries, various factors will affect our
financial results in the future. These factors include, but are not limited to,
operating our currently regulated generation assets in a deregulated market
beginning July 1, 2000 without the benefit of a fuel rate adjustment clause, the
loss of revenues due to customers choosing alternate suppliers, higher
volatility of earnings and cash flows, and increased financial requirements of
our nonregulated subsidiaries. Please refer to the "Forward Looking Statements"
section for additional factors.
- --------------------------------------------------------------------------------
Current Issues
Competition--Electric
Electric utilities are facing competition on various fronts, including:
. construction of generating units to meet increased demand for
electricity,
. sale of electricity in bulk power markets,
. competing with alternative energy suppliers, and
. electric sales to retail customers.
On April 8, 1999, Maryland enacted legislation authorizing customer choice and
competition among electric suppliers. In addition, on November 10, 1999, the
Maryland PSC issued a Restructuring Order that resolved the major issues
surrounding electric restructuring. These matters are discussed further in the
"Electric Restructuring" section and Note 4.
As a result of the deregulation of BGE's electric generation, no earlier than
July 1, 2000, and upon receipt of all regulatory approvals, we expect that BGE
will transfer, at book value, its nuclear generating assets and its nuclear
decommissioning trust fund to a subsidiary of Constellation Nuclear Group, LLC.
In addition, we expect that BGE will transfer, at book value, its fossil
generating assets and its partial ownership interest in two coal plants and a
hydroelectric plant located in Pennsylvania to a nonregulated subsidiary of
Constellation Energy. In total, these generating assets represent about 6,240
megawatts of generation capacity with a total projected net book value at June
30, 2000 of approximately $2.4 billion.
We expect BGE to transfer approximately $278 million of tax exempt debt to our
nonregulated subsidiaries related to the transferred assets and that BGE will
receive approximately $1.1 billion in unsecured promissory notes. Repayments of
the notes by our nonregulated subsidiaries will be used exclusively to service
certain long-term debt of BGE. BGE will also transfer equity associated with the
generating assets to nonregulated subsidiaries of Constellation Energy.
Under the Restructuring Order, BGE will provide standard offer service to
customers at fixed rates over various time periods during the transition period
for those customers that do not choose an alternate supplier once customer
choice begins July 1, 2000. In addition, the electric fuel rate will be
discontinued effective July 1, 2000. Nonregulated subsidiaries of Constellation
Energy will provide BGE with the energy and capacity required to meet its
standard offer service obligations for the first three years of the transition
period. Standard offer service will be competitively bid thereafter.
Nonregulated subsidiaries of Constellation Energy will obtain the energy and
capacity to supply BGE's standard offer service obligations from the Calvert
Cliffs Nuclear Power Plant (Calvert Cliffs) and BGE's former fossil plants,
supplemented with energy purchased from the wholesale energy market as
necessary. Our earnings will be exposed to the risks of the competitive
wholesale electricity market to the extent that our nonregulated subsidiaries
have to purchase energy and/or capacity or generate energy to meet obligations
to supply power to BGE at market prices or costs, respectively, which may
approach or exceed
29
BGE's standard offer service rates. We will also be affected by operational
risk, that is, the risk that a generating plant is not available to produce
energy when the energy is required.
Until July 1, 2000, we will continue to recover our cost of fuel and purchased
energy through the electric fuel rate as long as the Maryland PSC finds that,
among other things, we have kept the productive capacity of our generating
plants at a reasonable level. After July 1, 2000, any energy purchased to meet
BGE's load commitments will become a cost of doing business in the newly
competitive marketplace. Therefore, if BGE provides standard offer service at
fixed rates to its customers that do not select an alternative provider as
required under the terms of the Restructuring Order, and the load demand exceeds
our capacity to supply energy due to a plant outage, nonregulated subsidiaries
of Constellation Energy would be required to purchase additional power in the
wholesale energy market. If the price of obtaining energy in the wholesale
market exceeds the fixed standard offer service price, our earnings would be
adversely affected. Imbalances in demand and supply can occur not only because
of plant outages, but also because of transmission constraints or due to extreme
temperatures (hot or cold) causing demand to exceed available supply.
We will use appropriate risk management techniques consistent with our business
plan and policies to address these issues. We cannot estimate the impact of the
increased financial risks associated with this transition. However, these
financial risks could have a material impact on our, and BGE's, financial
results.
Competition--Gas
Currently, no regulation exists for the wholesale price of natural gas as a
commodity, and the regulation of interstate transmission at the federal level
has been reduced. All BGE industrial and commercial gas customers, and effective
November 1, 1999, all BGE residential customers have the option to purchase gas
from other suppliers.
Early Retirement Program
In recognition of the changing business environment, in 1999, our Board of
Directors approved a Targeted Voluntary Special Early Retirement Program
(TVSERP) to provide enhanced early retirement benefits to certain eligible
participants in targeted jobs that elect to retire on June 1, 2000. The
financial impacts of the TVSERP will be reflected in the second quarter of 2000.
Calvert Cliffs License Extension
In 1998, we filed an application with the Nuclear Regulatory Commission (NRC)
for a 20-year license extension for Calvert Cliffs to extend its license beyond
2014 for Unit 1 and 2016 for Unit 2. License renewal evaluations focus on
age-related issues in long-lived passive components (passive components include
buildings, the reactor vessel, piping, ventilation ducts, electric cables,
etc.). We must demonstrate that we can ensure that these passive components will
continue to perform their intended functions through the renewal period. The NRC
will also consider the impact of the 20-year license extension on the
environment.
According to the NRC's timetable, approval of BGE's application is expected in
April 2000. However, we cannot predict the actual timing of the NRC's decision,
or the impact, if any, on our financial results. If we do not receive the
license extension, we may not be able to operate the Calvert Cliffs units beyond
2014 and 2016.
BGE is currently involved in a lawsuit titled National Whistleblower Center v.
Nuclear Regulatory Commission and Baltimore Gas and Electric Company regarding
its license extension process. The matter involves an appeal of the NRC's
dismissal of Whistleblower's petition to intervene in the license renewal
proceeding. At issue was the NRC's adoption of a streamlined procedure for the
proceeding, including the requirement that any requests for extensions of time
be justified by a showing of "unavoidable and extreme circumstances" rather than
the "good cause" standard previously applied. Applying the new standard, the NRC
ultimately dismissed Whistleblower's petition to intervene. Oral arguments have
been held and a decision from the court is pending.
Environmental and Legal Matters
You will find details of our environmental matters in Note 10 and under Item 1.
Business--Environmental Matters. You will find details of our legal matters
under Item 3. Legal Proceedings. Some of the information is about costs that may
be material to our financial results.
Year 2000
We did not experience any significant problems associated with the year 2000
issue.
Accounting Standards Issued
We discuss recently issued accounting standards in Note 1.
30
Results of Operations
In this section, we discuss our earnings and the factors affecting them. We
begin with a general overview, then separately discuss earnings for our
operating segments.
Overview
Total Earnings Per Share of Common Stock
1999 1998 1997
- --------------------------------------------------------------------------------
Utility business $2.03 $1.93 $1.94
Diversified businesses .45 .27 .34
- --------------------------------------------------------------------------------
Total earnings per share
before nonrecurring charges
included in operations 2.48 2.20 2.28
Nonrecurring charges included
in operations:
Hurricane Floyd
(see Note 2) (.03) - -
Write-off of merger costs
(see Note 2) - - (.25)
Write-downs of power
projects (see Note 3) (.12) - -
Write-off of energy services
investment (see Note 2) - (.04) -
Write-down of financial
investment (see Note 3) (.11) - -
Write-downs of real estate
and senior-living investments
(see Note 2 and Note 3) (.04) (.10) (.31)
- --------------------------------------------------------------------------------
Total earnings per share before
extraordinary item 2.18 2.06 1.72
- --------------------------------------------------------------------------------
Extraordinary loss
(see Note 4) (.44) - -
- --------------------------------------------------------------------------------
Total earnings per share $1.74 $2.06 $1.72
================================================================================
1999
Our 1999 total earnings decreased $45.8 million, or $.32 per share, compared to
1998. Our total earnings decreased mostly because we recorded an extraordinary
charge of $66.3 million, or $.44 per share, associated with the deregulation of
the electric generation portion of our business. Our 1999 total earnings also
include nonrecurring write-downs recorded in our power projects, financial
investments, and real estate and senior-living businesses. These decreases were
partially offset by higher earnings from utility and diversified business
operations excluding nonrecurring charges. We discuss the extraordinary charge
in Note 4.
In 1999, we had higher utility earnings before the extraordinary charge compared
to 1998 mostly because we sold more electricity and gas this year, and we
settled a capacity contract with PECO Energy Company in 1998 that had a negative
impact on earnings in that year. This increase was partially offset by storm
restoration activities related to Hurricane Floyd and higher depreciation and
amortization expense mostly due to the $75.0 million, or $48.8 million
after-tax, amortization of the regulatory asset recorded in 1999 for the
reduction of our generation plant under the Restructuring Order.
We discuss our utility earnings and the Restructuring Order in more detail in
the "Utility Business" section.
In 1999, diversified business earnings before nonrecurring charges increased
compared to 1998 mostly because of higher earnings from our power marketing
business.
We discuss our diversified business earnings, including the write-downs, further
in the "Diversified Businesses" section.
1998
Our 1998 total earnings increased $51.8 million, or $.34 per share, compared to
1997. Our total earnings increased mostly because 1997 results reflect our
write-off of costs associated with the terminated merger with Potomac Electric
Power Company, and our real estate and senior-living facilities business' write-
down of its investments in two real estate projects. This increase was partially
offset by:
. our real estate and senior-living facilities business' write-down of
its investment in a real estate project in 1998, and
. the write-off of an energy services investment in 1998. In 1998,
utility earnings were about the same compared to 1997.
In 1998, diversified business earnings before nonrecurring charges decreased
compared to 1997 mostly because of lower earnings from our real estate and
senior-living facilities and financial investments businesses. This decrease was
partially offset by higher earnings from our power projects and power marketing
businesses.
31
Utility Business
Before we go into the details of our electric and gas operations, we believe it
is important to discuss factors that have a strong influence on our utility
business performance: electric restructuring, regulation by the Maryland PSC,
the weather, and other factors, including the condition of the economy in our
service territory.
Electric Restructuring
On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition
Act of 1999 (the "Act") and accompanying tax legislation that will significantly
restructure Maryland's electric utility industry and modify the industry's tax
structure.
In the Restructuring Order discussed below, the Maryland PSC addressed the major
provisions of the Act. The accompanying tax legislation is discussed in detail
in Note 4.
On November 10, 1999, the Maryland PSC issued a Restructuring Order that
resolves the major issues surrounding electric restructuring, accelerates the
timetable for customer choice, and addresses the major provisions of the Act.
The Restructuring Order also resolves the electric restructuring proceeding
(transition costs, customer price protections, and unbundled rates for electric
services) and a petition filed in September 1998 by the Office of People's
Counsel (OPC) to lower our electric base rates. The major provisions of the
Restructuring Order are:
. All customers, except a few commercial and industrial companies that
have signed contracts with BGE, will be able to choose their electric
energy supplier beginning July 1, 2000. BGE will provide a standard
offer service for customers that do not select an alternative
supplier. In either case, BGE will continue to deliver electricity to
all customers in areas traditionally served by BGE.
. BGE's current electric base rates are frozen at their current levels
until July 1, 2000.
. BGE will reduce residential base rates by approximately 6.5% on
average, about $54 million a year, beginning July 1, 2000. These rates
will not change before July 2006.
. Commercial and industrial customers will have up to four service
options that will fix electric energy rates and transition charges for
a period that generally ranges from four to six years.
. Electric delivery service rates will be frozen for a four-year period
for commercial and industrial customers. The generation and
transmission components of rates will be frozen for different time
periods depending on the service options selected by those customers.
. BGE will be allowed to recover $528 million after-tax of its
potentially stranded investments and utility restructuring costs
through a competitive transition charge on customers' bills.
Residential customers will pay this charge for six years. Commercial
and industrial customers will pay in a lump sum or over the four to
six-year period, depending on the service option selected by each
customer.
. Generation-related regulatory assets and nuclear decommissioning costs
will be included in delivery service rates effective July 1, 2000 and
will be recovered on a basis approximating their existing amortization
schedules.
. Starting July 1, 2000, BGE will unbundle rates to show separate
components for delivery service, transition charges, standard offer
service (generation), transmission, universal service, and taxes.
. On July 1, 2000, BGE will transfer, at book value, its ten
Maryland-based fossil and nuclear power plants and its partial
ownership interest in two coal plants and a hydroelectric plant in
Pennsylvania to nonregulated subsidiaries of Constellation Energy.
. BGE will reduce its generation assets, as discussed in Note 4, by $150
million pre-tax during the period July 1, 1999 - June 30, 2000 to
mitigate a portion of its potentially stranded investments.
. Universal service will be provided for low-income customers without
increasing their bills. BGE will provide its share of a statewide fund
totaling $34 million annually.
We believe that the Restructuring Order provided sufficient details of the
transition plan to competition for BGE's electric generation business to require
BGE to discontinue the application of Statement of Financial Accounting
Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of
Regulation for that portion of its business. Accordingly, in the fourth quarter
of 1999, we adopted the provisions of SFAS No. 101, Regulated
Enterprises--Accounting for the Discontinuation of FASB Statement No. 71 and
Emerging Issues Task Force Consensus (EITF) No. 97-4, Deregulation of the
Pricing of Electricity--Issues Related to the Application of FASB Statements No.
71 and 101 for BGE's electric generation business. BGE's transmission and
distribution business continues to meet the requirements of SFAS No. 71 as that
business remains regulated. We describe the effect of applying these accounting
requirements in Note 4.
In early December, the Mid-Atlantic Power Supply Association (MAPSA), Trigen-
Baltimore Energy Corporation, and Sweetheart Cup Company, Inc. filed appeals of
the Restructuring Order. MAPSA also filed a motion seeking to delay the
implementation of the Restructuring Order pending
32
a decision on the merits by the court. While we believe that the appeals are
without merit, no assurances can be given as to the timing or outcome of these
cases, and whether the outcome will have a material adverse effect on our and
BGE's financial results.
Regulation by the Maryland PSC
Under traditional rate regulation that will continue for all BGE's businesses
except electric generation beginning July 1, 2000, the Maryland PSC determines
the rate we can charge our customers. Our rates consist of a "base rate," a
"conservation surcharge," and a "fuel rate."
Base Rate
The base rate is the rate the Maryland PSC allows us to charge our customers for
the cost of providing them service, plus a profit. We have both an electric base
rate and a gas base rate. Higher electric base rates apply during the summer
when the demand for electricity is higher. Gas base rates are not affected by
seasonal changes.
Except as provided under the terms of the electric Restructuring Order discussed
earlier, BGE may ask the Maryland PSC to increase base rates from time to time.
The Maryland PSC historically has allowed BGE to increase base rates to recover
increased utility plant asset costs, plus a profit, beginning at the time of
replacement. Generally, rate increases improve our utility earnings because they
allow us to collect more revenue. However, rate increases are normally granted
based on historical data and those increases may not always keep pace with
increasing costs. Other parties may petition the Maryland PSC to decrease base
rates.
On November 17, 1999, BGE filed an application with the Maryland PSC to increase
its gas base rates. We discuss this filing in the gas "Base Rates" section.
Conservation Surcharge
The Maryland PSC allows us to include in electric and gas rates a component to
recover money spent on conservation programs. This component is called a
"conservation surcharge." However, under this surcharge the Maryland PSC limits
what our profit can be. If at the end of the year we have exceeded our allowed
profit, we defer (include as a liability on our Consolidated Balance Sheets and
exclude from our Consolidated Statements of Income) the excess in that year and
we lower the amount of future surcharges to our customers to correct the amount
of overage, plus interest. As a result of the Restructuring Order, the electric
conservation surcharge was frozen at its current level and the associated profit
limitation is no longer applicable.
Fuel Rate
Currently, we charge our electric customers separately for the fuel we use to
generate electricity (nuclear fuel, coal, gas, or oil) and for the net cost of
purchases and sales of electricity. We charge the actual cost of these items to
the customer with no profit to us. If these costs go up, the Maryland PSC
permits us to increase the fuel rate. If these costs go down, our customers
benefit from a reduction in the fuel rate. The fuel rate is mostly impacted by
the amount of electricity generated at Calvert Cliffs because the cost of
nuclear fuel is cheaper than coal, gas, or oil.
Under the Restructuring Order, BGE's electric fuel rate is frozen at its current
level until July 1, 2000, at which time the fuel rate clause will be
discontinued. We will continue to defer the difference between our actual costs
of fuel and energy and what we collect from customers under the fuel rate
through June 30, 2000. After that date, earnings will be affected by the changes
in the cost of fuel and energy. We discuss our exposure to market risk further
in the "Current Issues" section. In addition, any accumulated difference between
our actual costs of fuel and energy and the amounts collected from customers
under the electric fuel rate clause will be collected from our customers over a
period to be determined by the Maryland PSC. At December 31, 1999, the amount to
be collected from customers was $60.0 million.
We charge our gas customers separately for the natural gas they purchase from
us. The price we charge for the natural gas is based on a market based rates
incentive mechanism approved by the Maryland PSC. We discuss market based rates
in more detail in the "Gas Cost Adjustments" section and in Note 1.
Weather
Weather affects the demand for electricity and gas. Very hot summers and very
cold winters increase demand. Mild weather reduces demand. Weather impacts
residential sales more than commercial and industrial sales, which are mostly
affected by business needs for electricity and gas.
We measure the weather's effect using "degree days." A degree day is the
difference between the average daily actual temperature and a baseline
temperature of 65 degrees. Cooling degree days result when the average daily
actual temperature exceeds the 65 degree baseline. Heating degree days result
when the average daily actual temperature is less than the baseline.
33
During the cooling season, hotter weather is measured by more cooling degree
days and results in greater demand for electricity to operate cooling systems.
During the heating season, colder weather is measured by more heating degree
days and results in greater demand for electricity and gas to operate heating
systems.
Effective March 1, 1998, the Maryland PSC allowed us to implement a monthly
adjustment to our gas business revenues to eliminate the effect of abnormal
weather patterns. We discuss this further in the "Weather Normalization"
section.
We show the number of cooling and heating degree days in 1999 and 1998, the
percentage change in the number of degree days from the prior year, and the
number of degree days in a "normal" year as represented by the 30-year
average in the following table.
30-year
1999 1998 average
- --------------------------------------------------------------------------------
Cooling degree days 845 915 843
Percentage change from prior year (7.7)% 22.7%
Heating degree days 4,585 4,119 4,755
Percentage change from prior year 11.3% (14.6)%
Other Factors
Other factors, aside from weather, impact the demand for electricity and gas.
These factors include the "number of customers" and "usage per customer" during
a given period. We use these terms later in our discussions of electric and gas
operations. In those sections, we discuss how these and other factors affected
electric and gas sales during 1999 and 1998.
The number of customers in a given period is affected by new home and apartment
construction and by the number of businesses in our service territory. When
customer choice for electric generation begins on July 1, 2000, a portion of
BGE's electric customers will become delivery service customers only and will
purchase their electricity from other sources. Other electric customers will
receive standard offer service from BGE at the fixed rates provided by the
Restructuring Order. To the extent our electricity generation exceeds or is less
than the electricity demanded by customers utilizing our standard offer service,
the incremental electricity will be sold or purchased in the wholesale market at
prevailing market prices. We discuss our exposure to market risk further in the
"Current Issues" section.
Usage per customer refers to all other items impacting customer sales that
cannot be measured separately. These factors include the strength of the economy
in our service territory. When the economy is healthy and expanding, customers
tend to consume more electricity and gas. Conversely, during an economic
downtrend, our customers tend to consume less electricity and gas.
Utility Business Earnings Per Share of Common Stock
1999 1998 1997
- --------------------------------------------------------------------------------
Electric business $1.81 $1.75 $1.77
Gas business .22 .18 .17
- --------------------------------------------------------------------------------
Total utility earnings per share
before nonrecurring charge
included in operations 2.03 1.93 1.94
Nonrecurring charge included
in operations:
Hurricane Floyd
(see Note 2) (.03) - -
Write-off of merger costs
(see Note 2) - - (.25)
- --------------------------------------------------------------------------------
Total utility earnings per share
before extraordinary item 2.00 1.93 1.69
- --------------------------------------------------------------------------------
Extraordinary loss
(see Note 4) (.44) - -
- --------------------------------------------------------------------------------
Total utility earnings per share $1.56 $1.93 $1.69
================================================================================
Our 1999 total utility earnings decreased $53.9 million, or $.37 per share,
compared to 1998. Our 1998 total utility earnings increased $36.1 million, or
$.24 per share, compared to 1997. We discuss the factors affecting utility
earnings below.
Electric Operations
The discussion below reflects the operations of the electric generation portion
of our utility business under current rate regulation by the Maryland PSC. Our
electric business will change significantly beginning July 1, 2000 as we enter
into retail customer choice for electric generation. Also, no earlier than July
1, 2000, and upon receipt of all regulatory approvals, all of BGE's generation
assets will be transferred, at book value, to nonregulated subsidiaries of
Constellation Energy. These assets represent about 6,240 megawatts of generation
capacity with a total projected net book value at June 30, 2000 of approximately
$2.4 billion.
34
We estimate that the electric generation portion of our business currently
represents about one-half of BGE's operating income.
We expect BGE to transfer approximately $278 million of tax exempt debt to our
nonregulated subsidiaries related to the transferred assets and that BGE will
receive approximately $1.1 billion in unsecured promissory notes. Repayments of
the notes by our nonregulated subsidiaries will be used exclusively to service
certain long-term debt of BGE. BGE will also transfer equity associated with the
generating assets to nonregulated subsidiaries of Constellation Energy.
Given the uncertainties surrounding electric deregulation as discussed in the
"Strategy" and "Current Issues" sections, the results discussed in this section
may not be indicative of the future performance of our generation business.
Also, these results will not be indicative of the future performance of BGE once
BGE transfers all of its generation assets to nonregulated subsidiaries of
Constellation Energy. The impact of this transfer on BGE's financial results
will be material. The total assets, liabilities, and common shareholders' equity
of Constellation Energy will not change as a result of the transfer.
Electric Revenues
The changes in electric revenues in 1999 and 1998 compared to the respective
prior year were caused by:
1999 1998
- --------------------------------------------------------------------------------
(In millions)
Electric system sales volumes $41.2 $50.8
Base rates 0.8 (6.6)
Fuel rates 3.7 (8.1)
- --------------------------------------------------------------------------------
Total change in electric revenues
from electric system sales 45.7 36.1
Interchange and other sales (8.2) (13.2)
Other 2.1 4.6
- --------------------------------------------------------------------------------
Total change in electric revenues $39.6 $27.5
================================================================================
Electric System Sales Volumes
"Electric system sales volumes" are sales to customers in our service territory
at rates set by the Maryland PSC. These sales do not include interchange sales
and sales to others.
The percentage changes in our electric system sales volumes, by type of
customer, in 1999 and 1998 compared to the respective prior year were:
1999 1998
- --------------------------------------------------------------------------------
Residential 3.5% 1.5%
Commercial 2.6 3.9
Industrial (5.1) 0.2
In 1999, we sold more electricity to residential customers due to higher usage
per customer, colder winter weather, and an increased number of customers. This
increase was partially offset by milder spring and early summer weather. We sold
more electricity to commercial customers mostly due to higher usage per
customer, an increased number of customers, and colder winter weather. We sold
less electricity to industrial customers mostly because usage by Bethlehem Steel
and other industrial customers decreased. Usage decreased at Bethlehem Steel as
a result of a shut-down from June to August for an upgrade to their facilities
that temporarily reduced their electricity consumption. This decrease was
partially offset by an increase in the number of industrial customers.
In 1998, we sold more electricity to residential customers mostly because of an
increased number of customers, hotter summer weather, and higher usage per
customer. The increase in sales to residential customers was partially offset by
milder winter weather. We sold more electricity to commercial customers mostly
because of higher usage per customer. We sold about the same amount of
electricity to industrial customers as we did in 1997.
Base Rates
In 1999, base rate revenues were about the same compared to 1998.
In 1998, base rate revenues decreased compared to 1997. Although we sold more
electricity in 1998, our base rate revenues decreased because of lower
conservation surcharge revenues.
Fuel Rates
In 1999, fuel rate revenues increased compared to 1998 mostly because we sold
more electricity.
In 1998, fuel rate revenues decreased compared to 1997. Although we sold more
electricity, the fuel rate was lower mostly because we were able to use a less-
costly mix of generating plants and electricity purchases.
Interchange and Other Sales
"Interchange and other sales" are sales in the PJM (Pennsylvania-New Jersey-
Maryland) Interconnection energy market and to others. The PJM is the operator
of a regional transmission organization as well as a regional power pool with
members that include many wholesale market participants, as well as BGE and
other utility companies. We sell energy to PJM members and to others after we
have satisfied the demand for electricity in our own system.
35
In 1999 and 1998, interchange and other sales revenues decreased compared to the
respective prior year mostly because higher demand for system sales reduced the
amount of energy we had available for off-system sales.
Electric Fuel and Purchased Energy Expenses
1999 1998 1997
- --------------------------------------------------------------------------------
(In millions)
Actual costs $538.0 $514.7 $504.5
Net (deferral) recovery of costs
under electric fuel
rate clause (see Note 1) (70.3) (9.0) 15.2
- --------------------------------------------------------------------------------
Total electric fuel and
purchased energy expenses $467.7 $505.7 $519.7
================================================================================
Actual Costs
In 1999, our actual costs of fuel to generate electricity (nuclear fuel, coal,
gas, or oil) and electricity we bought from others were higher compared to 1998
mostly because the price of electricity we bought from others was higher. The
price of electricity changes based on market conditions and contract terms. This
increase was partially offset by our settlement of a capacity contract with PECO
in 1998.
In 1998, our actual costs increased compared to 1997 mostly because we settled a
capacity contract with PECO.
Electric Fuel Rate Clause
Under the electric fuel rate clause, we defer (include as an asset or liability
in our Consolidated Balance Sheets and exclude from our Consolidated Statements
of Income) the difference between our actual costs of fuel and energy and what
we collect from customers under the fuel rate in a given period. We either bill
or refund our customers that difference in the future. We discuss the
calculation of the fuel rate and its future discontinuance in Note 1.
In 1999 and 1998, our actual costs of fuel and energy were higher than the fuel
rate revenues we collected from our customers. The increase in the 1999 deferral
reflects higher purchased power costs, especially during record-setting summer
peak loads.
Electric Operations and Maintenance Expenses
In 1999, electric operations and maintenance expenses were about the same
compared to 1998. In 1999, operations and maintenance expenses include the costs
for system restoration activities related to Hurricane Floyd of $7.5 million and
a major winter ice storm. This was offset by lower employee benefit costs in
1999 and a 1998 $6.0 million write-off of contributions to a third party for a
low-level radiation waste facility that was never completed.
In 1998, electric operations and maintenance expenses increased $28.7 million
compared to 1997 mostly because of:
. higher nuclear costs,
. higher employee benefit costs, and
. the $6.0 million write-off for the low-level radiation waste facility
discussed above.
Electric Depreciation and Amortization Expense
In 1999, electric depreciation and amortization expense increased $63.4 million
compared to 1998 mostly because of the $75.0 million amortization of the
regulatory asset for the reduction in generation plant provided for in the
Restructuring Order. This increase was partially offset by lower amortization of
deferred electric conservation expenditures due to the write-off of a portion of
these expenditures that will not be recovered under the Restructuring Order. We
discuss the accounting implications of the Restructuring Order further in
Note 4.
In 1998, electric depreciation and amortization expense increased $26.5 million
compared to 1997 mostly because:
. in October 1998, the Maryland PSC authorized us to implement new electric
depreciation rates retroactive to January 1, 1998, which increased
depreciation expense by approximately $13.9 million,
. we had more electric plant in service (as our level of plant in service
changes, the amount of our depreciation and amortization expense changes), and
. we reduced the amortization period for certain computer software beginning in
the first quarter of 1998 from five years to three years.
36
Gas Operations
All BGE industrial and commercial gas customers, and effective November 1, 1999,
all BGE residential customers have the option to purchase gas from other
suppliers. We do not expect the impact of customer choice to have a material
effect on our, and BGE's, financial results.
Gas Revenues
The changes in gas revenues in 1999 and 1998 compared to the respective prior
year were caused by:
1999 1998
- --------------------------------------------------------------------------------
(In millions)
Gas system sales volumes $ 8.0 $(10.8)
Base rates 2.2 14.2
Weather normalization 4.5 10.1
Gas cost adjustments 19.8 (87.6)
- --------------------------------------------------------------------------------
Total change in gas revenues
from gas system sales 34.5 (74.1)
Off-system sales (7.9) 1.8
Other 0.5 0.1
- --------------------------------------------------------------------------------
Total change in gas revenues $27.1 $(72.2)
================================================================================
Gas System Sales Volumes
The percentage changes in our gas system sales volumes, by type of customer, in
1999 and 1998 compared to the respective prior year were:
1999 1998
- --------------------------------------------------------------------------------
Residential 9.2% (11.6)%
Commercial 12.7 (9.5)
Industrial (4.8) (11.3)
In 1999, we sold more gas to residential customers mostly for two reasons:
colder winter weather and an increased number of customers. This was partially
offset by lower usage per customer. We sold more gas to commercial customers
mostly because of higher usage per customer, colder winter weather, and an
increased number of customers. We sold less gas to industrial customers mostly
because of lower usage by Bethlehem Steel and other industrial customers. Usage
by Bethlehem Steel decreased due to a shut-down from June to August for an
upgrade to their facilities.
In 1998, we sold less gas to residential and commercial customers mostly for two
reasons: milder weather and lower usage per customer. This was partially offset
by the increase in the number of customers. We sold less gas to industrial
customers mostly because of lower usage by Bethlehem Steel and other industrial
customers.
Base Rates
In 1999, base rate revenues increased compared to 1998 mostly due to the
increase in our base rates effective March 1, 1998 as discussed below.
In 1998, base rate revenues increased compared to 1997. Although we sold less
gas during 1998, our base rate revenues increased mostly because the Maryland
PSC authorized an increase in our base rates effective March 1, 1998. The change
in rates increased our base rate revenues over the twelve-month period from
March 1998 through February 1999 by approximately $16 million.
On November 17, 1999, we applied for a $36.3 million annual increase in our gas
base rates. The Maryland PSC is currently reviewing our application and is
expected to issue an order by June 2000.
Weather Normalization
Effective March 1, 1998, the Maryland PSC allowed us to implement a monthly
adjustment to our gas revenues to eliminate the effect of abnormal weather
patterns on our gas system sales volumes. This means our monthly gas revenues
will be based on weather that is considered "normal" for the month and,
therefore, will not be affected by actual weather conditions.
Gas Cost Adjustments
We charge our gas customers for the natural gas they purchase from us using gas
cost adjustment clauses set by the Maryland PSC. These clauses operate similarly
to the electric fuel rate clause described in the "Electric Fuel Rate Clause"
section. However, under market based rates, our actual cost of gas is compared
to a market index (a measure of the market price of gas in a given period). The
difference between our actual cost and the market index is shared equally
between shareholders and customers, and does not significantly impact earnings.
We also discuss this in Note 1.
Delivery service customers, including Bethlehem Steel, are not subject to the
gas cost adjustment clauses because we are not selling gas to them. We charge
these customers fees to recover the fixed costs for the transportation service
we provide. These fees are the same as the base rate charged for gas sales and
are included in gas system sales volumes.
In 1999, gas cost adjustment revenues increased compared to the same period of
1998 mostly because we sold more gas at a higher price.
In 1998, gas cost adjustment revenues decreased compared to 1997 mostly because
we sold less gas.
37
Off-System Sales
Off-system gas sales are low-margin direct sales of gas to wholesale suppliers
of natural gas outside our service territory. Off-system gas sales, which occur
after we have satisfied our customers' demand, are not subject to gas cost
adjustments. The Maryland PSC approved an arrangement for part of the margin
from off-system sales to benefit customers (through reduced costs) and the
remainder to be retained by BGE (which benefits shareholders). Changes in off-
system sales do not significantly impact earnings.
In 1999, revenues from off-system gas sales decreased compared to 1998 mostly
because we sold less gas off-system.
In 1998, revenues from off-system gas sales increased compared to 1997 mostly
because we sold more gas off-system.
Gas Purchased For Resale Expenses
1999 1998 1997
- --------------------------------------------------------------------------------
(In millions)
Actual costs $221.8 $212.2 $291.6
Net recovery (deferral) of
costs under gas adjustment
clauses (see Note 1) 8.8 (3.6) 0.5
- --------------------------------------------------------------------------------
Total gas purchased for
resale expenses $230.6 $208.6 $292.1
================================================================================
Actual Costs
Actual costs include the cost of gas purchased for resale to our customers and
for off-system sales. Actual costs do not include the cost of gas purchased by
delivery service customers.
In 1999, actual gas costs increased compared to 1998 mostly because we sold more
gas.
In 1998, actual gas costs decreased compared to 1997 mostly because we sold less
gas.
Gas Adjustment Clauses
We charge customers for the cost of gas sold through gas adjustment clauses
(determined by the Maryland PSC), as discussed under "Gas Cost Adjustments"
earlier in this section.
In 1999, actual gas costs were lower than the fuel rate revenues we collected
from our customers.
In 1998, actual gas costs were higher than the fuel rate revenues we collected
from our customers.
Gas Operations and Maintenance Expenses
In 1999, gas operations and maintenance expenses were about the same compared to
1998.
In 1998, gas operations and maintenance expenses increased $3.9 million compared
to 1997 mostly because of higher employee benefit costs.
Gas Depreciation and Amortization Expense
In 1999, gas depreciation and amortization expense was about the same compared
to 1998.
In 1998, gas depreciation and amortization expense increased $6.1 million
compared to 1997 mostly because:
. we had more gas plant in service, and
. we reduced the amortization period for certain computer software beginning
in the first quarter of 1998 from five years to three years.
38
Diversified Businesses
Our diversified businesses engage primarily in energy services. We list each of
our diversified businesses in the "Introduction" section. We describe our
diversified businesses in more detail under "Item 1. Business - Diversified
Businesses."
Diversified Business Earnings Per Share of Common Stock
1999 1998 1997
- --------------------------------------------------------------------------------
Energy services
Power marketing $ .23 $ .05 $ -
Power projects .26 .30 .25
Other (.05) (.01) (.05)
- --------------------------------------------------------------------------------
Total energy services earnings
per share before nonrecurring
charges included in operations .44 .34 .20
Other diversified businesses
earnings (losses) per share before
nonrecurring charges included
in operations .01 (.07) .14
- --------------------------------------------------------------------------------
Total diversified business earnings
per share before nonrecurring
charges included in operations .45 .27 .34
Nonrecurring charges included in
operations:
Write-downs of power projects
(see Note 3) (.12) - -
Write-off of energy services
investment (see Note 2) - (.04) -
Write-down of financial
investment (see Note 3) (.11) - -
Write-downs of real estate and
senior-living investments
(see Note 2 and Note 3) (.04) (.10) (.31)
- --------------------------------------------------------------------------------
Total earnings per share $ .18 $ .13 $ .03
================================================================================
Our 1999 diversified business earnings increased $8.1 million, or $.05 per
share, compared to 1998. Our 1998 diversified business earnings increased $15.7
million, or $.10 per share, compared to 1997.
We discuss factors affecting the earnings of our diversified businesses below.
Energy Services
Power Marketing
In 1999, earnings from our power marketing business increased compared to 1998
because of increased transaction margins and volume.
In 1998, earnings from our power marketing business increased compared to 1997
because of increased power marketing activities in 1998, which was Constellation
Power Source's first full year of operations.
Constellation Power Source uses the mark-to-market method of accounting. We
discuss the mark-to-market method of accounting and Constellation Power Source's
activities in Note 1.
As a result of the nature of its business activities, Constellation Power
Source's revenue and earnings will fluctuate. We cannot predict these
fluctuations, but the effect on our revenues and earnings could be material. The
primary factors that cause these fluctuations are:
. the number and size of new transactions,
. the magnitude and volatility of changes in commodity prices and interest
rates, and
. the number and size of open commodity and derivative positions Constellation
Power Source holds or sells.
Constellation Power Source's management uses its best estimates to determine the
fair value of commodity and derivative positions it holds and sells. These
estimates consider various factors including closing exchange and
over-the-counter price quotations, time value, volatility factors, and credit
exposure. However, it is possible that future market prices could vary from
those used in recording assets and liabilities from power marketing and trading
activities, and such variations could be material. In 1999, assets and
liabilities from energy trading activities (as shown in our Consolidated Balance
Sheets) increased because of greater business activity during the period.
In March 1998, we formed Orion Power Holdings, Inc. (Orion) with Goldman, Sachs
Capital Partners II L.P., an affiliate of Goldman, Sachs & Co., to acquire
electric generating plants in the United States and Canada. Our energy services
businesses own a minority interest in Orion. To date, our energy services
businesses have funded $104 million in equity and have a commitment to
contribute an additional $121 million to Orion.
39
Power Projects
In 1999, earnings from our power projects business decreased compared to 1998
mostly because of three factors:
. In 1999, our power projects business recorded a $14.2 million after-tax, or
$.09 per share, write-off of two geothermal power projects. These write-offs
occurred because the expected future cash flows from the projects are less
than the investment in the projects. For the first project, this resulted
from the inability to restructure certain project agreements. For the second
project, we experienced a declining water temperature of the geothermal
resource used by one of the plants for production.
. In 1999, our power projects business recorded a $4.5 million after-tax, or
$.03 per share, write-down to reflect the fair value of our investment in a
power project as a result of our international exit strategy as discussed
later in this section.
. In 1998, our power projects business recorded a $10.4 million after-tax, or
$.07 per share, gain for its share of earnings in a partnership. The
partnership recognized a gain on the sale of its ownership interest in a
power purchase agreement.
In 1998, earnings from our power projects business increased compared to 1997
mostly because Constellation Power recorded a $10.4 million after-tax gain for
its share of earnings in a partnership as discussed above.
California Power Purchase Agreements
Constellation Power and subsidiaries and Constellation Investments have $301.8
million invested in 14 projects that sell electricity in California under power
purchase agreements called "Interim Standard Offer No. 4" agreements. In 1999,
earnings from these projects, excluding any write-offs, were $34.4 million, or
$.23 per share, compared to $41.3 million, or $.28 per share in 1998.
Under these agreements, the electricity rates change from fixed rates to
variable rates beginning in 1996 and continuing through 2000. The projects which
already have had rate changes have lower revenues under variable rates than they
did under fixed rates. When the remaining projects transition to variable rates,
we expect their revenues also to be lower than they are under fixed rates.
As of December 31, 1999, ten projects had already transitioned to variable
rates. The remaining four projects will transition between February and December
2000. The projects which transitioned in 1999 contributed $6.2 million, or $.04
per share to 1999 earnings. Those changing over in 2000 contributed $28.0
million, or $.19 per share to 1999 earnings. We expect earnings from the
projects changing over in 2000 to contribute $17.4 million, or $.12 per share to
2000 earnings.
Our power projects business continues to pursue alternatives for some of these
projects including:
. repowering the projects to reduce operating costs,
. changing fuels to reduce operating costs,
. renegotiating the power purchase agreements to improve the terms,
. restructuring financing to improve existing terms, and
. selling its ownership interests in the projects.
We evaluate the carrying amount of our investment in these projects for
impairment using the methodology discussed in Note 1. Constellation Power's
management uses its best estimates to determine if there has been an impairment
of these investments and considers various factors including forward price
curves for energy, fuel costs, and operating costs. However, it is possible that
future estimates of market prices and project costs could vary from those used
in evaluating these assets, and the impact of such variations could be material.
We also describe these projects and the transition process in Note 10.
International Projects
At December 31, 1999, Constellation Power had invested about $254.1 million in
10 power projects in Latin America compared to $269.7 million invested in Latin
America in 1998. These investments include:
. the purchase of a 51% interest in a Panamanian electric distribution
company for approximately $90 million in 1998 by an investment group in
which subsidiaries of Constellation Power hold an 80% interest, and
. approximately $98 million for the purchase of existing electric generation
facilities and the construction of an electric generation facility in
Guatemala.
40
In December 1999, we decided to exit the international portion of our power
projects business as part of our strategy to improve our competitive position.
As a result, we recorded a $4.5 million after-tax write-down of our investment
in a generating company in Bolivia to reflect the current fair value of this
investment. We expect to complete our exit strategy by the end of 2000. We
discuss our strategy further in the "Strategy" section.
Other Energy Services
In 1999, earnings from our other energy services businesses decreased compared
to 1998 mostly because of lower gross margins at our energy products and
services business.
In 1998, earnings from our other energy services businesses increased compared
to 1997 due to improved results from our energy products and services business.
Earnings would have been higher except we recorded a $5.5 million after-tax, or
$.04 per share, write-off of our investment in, and certain of our product
inventory from, an automated electric distribution equipment company. We
recorded this write-off because of that company's inability to raise capital and
sell its products.
Other Diversified Businesses
In 1999, earnings from our other diversified businesses increased compared to
1998 mostly because of higher earnings from our real estate and senior-living
facilities business. This increase was partially offset by lower earnings from
our financial investments business. In 1999, earnings from our real estate and
senior-living facilities business increased compared to 1998 mostly because of:
. a $15.4 million after-tax write-down of its investment in Church Street
Station, an entertainment, dining, and retail complex in Orlando, Florida
in 1998, and
. an increase in earnings from its investment in Corporate Office Properties
Trust (COPT) in 1999. We discuss the investment in COPT below.
This increase was partially offset by a $5.8 million after-tax, or $.04 per
share, write-down of certain senior-living facilities related to the proposed
sale of these facilities in 1999 as discussed below.
In 1999, our senior-living facilities business entered into an agreement to sell
all but one of its senior-living facilities to Sunrise Assisted Living, Inc.
Under the terms of the agreement, Sunrise was to acquire 12 of our existing
senior-living facilities, three facilities under construction, and several sites
under development for $72.2 million in cash and $16.0 million in debt
assumption. We could not reach an agreement on financing issues that
subsequently arose, and the agreement was terminated in November 1999. As a
result, our senior-living facilities business engaged a third-party management
company to manage its senior-living facilities portfolio including the three
facilities now under construction, scheduled to be completed in the first half
of 2000.
In 1999, Constellation Real Estate Group, Inc. (CREG) sold Church Street
Station, for $11.5 million, the approximate book value of the complex.
In 1999, our financial investments business announced that it would exchange its
shares of common stock in Capital Re, an insurance company, for common stock of
ACE Limited (ACE), another insurance company, as part of a business combination
whereby ACE would acquire all of the outstanding capital stock of Capital Re.
Through September 30, 1999, our financial investments business wrote down its
$94.2 million investment in Capital Re stock by $20.9 million after-tax, or $.14
per share, to reflect the market value of this investment. The agreement between
ACE and Capital Re was subsequently revised on a more favorable basis for
Capital Re to include both cash and ACE stock. In December 1999, the transaction
was finalized and our financial investments business recorded a $4.9 million
after-tax, or $.03 per share, gain on this investment to reflect the closing
price of the business combination. This net write-down of Capital Re was
partially offset by better market performance of other financial investments in
1999 compared to 1998.
In 1998, earnings from our other diversified businesses decreased compared to
1997 mostly due to lower earnings from our real estate and senior-living
facilities and financial investments businesses. Earnings from our real estate
and senior-living facilities business decreased mostly due to:
. a $15.4 million after-tax write-down of its investment in Church Street
Station,
. lower earnings from various real estate and senior-living facilities
projects, and
. a $4.0 million after-tax gain on the sale of two senior- living facilities
projects reflected in 1997 results.
41
In addition, in 1998, our real estate and senior-living facilities business
exchanged certain assets and liabilities in return for a 41.9% equity interest
in COPT, a real estate investment trust.
In 1998, earnings from our financial investments business decreased compared to
1997 mostly because of:
. better market performance for its investments in 1997, and
. a $6.0 million after-tax gain on the sale of stock held by a financial
limited partnership reflected in 1997 results.
We discuss our real estate projects, the write-downs of our real estate
projects, the COPT transaction, and our financial investments further in Note 3.
Most of CREG's remaining real estate projects are in the Baltimore-Washington
corridor. The area has had a surplus of available land in recent years and as a
result these projects have been economically hurt.
Constellation Real Estate's projects have continued to incur carrying costs and
depreciation over the years. Additionally, this business has been charging
interest payments to expense rather than capitalizing them for some undeveloped
land where development activities have stopped. These carrying costs,
depreciation, and interest expenses have decreased earnings and are expected to
continue to do so.
Cash flow from real estate operations has not been enough to make the monthly
loan payments on some of these projects. Cash shortfalls have been covered by
cash obtained from the cash flows of other diversified subsidiaries.
We consider market demand, interest rates, the availability of financing, and
the strength of the economy in general when making decisions about our real
estate projects. If we were to decide to sell our real estate projects, we could
have write-downs. In addition, if we were to sell our real estate projects in
the current market, we would have losses which could be material, although the
amount of the losses is hard to predict. Depending on market conditions, we
could also have material losses on any future sales.
Our current real estate strategy is to hold each real estate project until we
can realize a reasonable value for it. We evaluate strategies for all our
businesses, including real estate, on an ongoing basis. We anticipate that
competing demands for our financial resources and changes in the utility
industry will cause us to evaluate thoroughly all business strategies on a
regular basis so we use capital and other resources in a manner that is most
beneficial.
Under accounting rules, we are required to write down the value of a real estate
project to market value in either of two cases. The first is if we change our
intent about a project from an intent to hold to an intent to sell and the
market value of that project is below book value. The second is if the expected
future cash flow from the project is less than the investment in the project.
Consolidated Nonoperating Income and Expenses
Other Income and Expenses
In September 1995, we signed an agreement to merge with Potomac Electric Power
Company after all necessary regulatory approvals were received. In December
1997, both companies mutually terminated the merger agreement. Accordingly, in
1997, we wrote off $57.9 million of costs related to the merger. This write-off
reduced after-tax earnings by $37.5 million, or $.25 per share.
Fixed Charges
In 1999, fixed charges decreased $7.7 million compared to 1998 mostly because we
had less BGE preference stock outstanding.
In 1998, fixed charges increased $4.0 million compared to 1997 mostly because we
had more debt outstanding. Our fixed charges would have been higher except we
had less BGE preference stock outstanding and lower interest rates in 1998
compared to 1997.
Income Taxes
In 1999, income taxes increased $8.2 million compared to 1998 because we had
higher taxable income from both our utility operations and our diversified
businesses.
In 1998, income taxes increased $20.2 million compared to 1997 because we had
higher taxable income from both our utility operations and our diversified
businesses.
Please refer to Note 4 for a discussion of tax law changes. These changes are
designed, in part, to tax Maryland electric generating facilities on a more
comparable basis with electric generation in other states.
42
Financial Condition
Cash Flows
1999 1998 1997
- --------------------------------------------------------------------------------
(In millions)
Cash provided by (used in):
Operating Activities $679.0 $799.8 $696.3
Investing Activities (615.1) (711.3) (520.8)
Financing Activities (144.9) (77.4) (79.6)
In 1999 and 1998, cash provided by operations changed compared to the respective
prior year mostly because of changes in working capital requirements.
In 1999, we used less cash for investing activities compared to 1998 mostly due
to lower investments in international power projects and in the real estate and
senior-living facilities business. This was partially offset by:
. our energy services businesses increased the investment in Orion Power
Holdings, Inc. by $97.7 million,
. our power projects business increased its investment in domestic power
projects, primarily related to the 800 megawatts of peaking capacity as
discussed in the "Capital Requirements of our Diversified Businesses"
section, and
. BGE increased its construction expenditures by $46.5 million.
In 1998, net cash used in investing activities increased compared to 1997 mostly
because of the additional investments in international power projects. This was
partially offset by a $33.8 million decrease in utility construction
expenditures.
Total utility construction expenditures, including the allowance for funds used
during construction, were $385.9 million in 1999 as compared to $339.4 million
in 1998 and $373.2 million in 1997.
In 1999, we used more cash for financing activities compared to 1998 mostly
because we repaid more long-term debt and issued less long-term debt and common
stock. This was partially offset by a decrease in the redemption of BGE
preference stock and higher net short-term borrowings in 1999 compared to 1998.
In 1998, cash used in financing activities was about the same compared to 1997.
In 1998, we issued more long-term debt and common stock, and had contributions
from minority interests of approximately $86 million related to the acquisition
of a distribution company in Panama. This was offset by the repayment of short-
term borrowings that matured, sinking fund requirements, and early redemption of
higher cost securities.
Security Ratings
Independent credit-rating agencies rate Constellation Energy and BGE's fixed-
income securities. The ratings indicate the agencies' assessment of each
company's ability to pay interest, distributions, dividends, and principal on
these securities. These ratings affect how much it will cost each company to
sell these securities. The better the rating, the lower the cost of the
securities to each company when they sell them. Constellation Energy and BGE's
securities ratings at the date of this report are:
Standard Moody's Duff & Phelps'
& Poors Investors Credit
Rating Group Service Rating Co.
- --------------------------------------------------------------------------------
Constellation Energy
Unsecured Debt A- A3 A
BGE
Mortgage Bonds AA- A1 AA-
Unsecured Debt A A2 A+
Trust Originated
Preferred Securities
and Preference Stock A- "a2" A
43
Capital Resources
Our business requires a great deal of capital. Our actual consolidated capital
requirements for the years 1997 through 1999, along with estimated annual
amounts for the years 2000 through 2002, are shown in the table below. For the
year ended December 31, 1999, the ratio of earnings to fixed charges for
Constellation Energy was 2.87. The ratio of earnings to fixed charges for BGE
was 3.45 and the ratio of earnings to combined fixed charges and preferred and
preference dividend requirements for BGE was 3.14.
Investment requirements for 2000 through 2002 include estimates of funding for
existing and anticipated projects. We continuously review and modify those
estimates. Actual investment requirements may vary from the estimates included
in the table below because of a number of factors including:
. regulation, legislation, and competition,
. BGE load requirements,
. environmental protection standards,
. the type and number of projects selected for development,
. the effect of market conditions on those projects,
. the cost and availability of capital, and
. the availability of cash from operations.
Our estimates are also subject to additional factors. Please see the "Forward
Looking Statements" section.
No earlier than July 1, 2000, and upon receipt of all regulatory approvals, all
of BGE's generation assets will be transferred to nonregulated subsidiaries of
Constellation Energy. The discussion and table for capital requirements below
include these generation assets as part of the utility business.
1997 1998 1999 2000 2001 2002
- -----------------------------------------------------------------------------------------------------------------------------
(In millions)
Utility Business Capital Requirements:
Construction expenditures (excluding AFC)
Electric $ 238 $ 239 $ 283 $ 329 $ 332 $ 312
Gas 89 55 59 63 61 61
Common 38 35 34 25 23 23
- -----------------------------------------------------------------------------------------------------------------------------
Total construction expenditures 365 329 376 417 416 396
AFC 8 10 10 4 4 4
Nuclear fuel (uranium purchases and processing charges) 44 50 49 50 48 48
Deferred conservation expenditures 27 16 1 - - -
Retirement of long-term debt and redemption of preference stock 243 222 342 401 281 151
- -----------------------------------------------------------------------------------------------------------------------------
Total utility business capital requirements 687 627 778 872 749 599
- -----------------------------------------------------------------------------------------------------------------------------
Diversified Business Capital Requirements:
Investment requirements 156 325 278 764 1,001 755
Retirement of long-term debt 188 232 189 284 367 2
- -----------------------------------------------------------------------------------------------------------------------------
Total diversified business capital requirements 344 557 467 1,048 1,368 757
- -----------------------------------------------------------------------------------------------------------------------------
Total capital requirements $1,031 $1,184 $1,245 $1,920 $2,117 $1,356
=============================================================================================================================
Capital Requirements of Our Utility Business
Our estimates of future electric construction expenditures do not include costs
to build more generating units to meet load requirements for BGE customers.
Electric construction expenditures include improvements to generating plants and
to our transmission and distribution facilities, and costs for replacing the
steam generators and renewing the operating licenses at Calvert Cliffs. The
operating licenses expire in 2014 for Unit 1 and in 2016 for Unit 2. If we do
not replace the steam generators, we may not be able to operate the Calvert
Cliffs units beyond 2014 and 2016. We expect the steam generator replacements to
occur during the 2002 refueling outage for Unit 1 and during the 2003 refueling
outage for Unit 2. We discuss the license extension process further in the
"Current Issues" section. We estimate these Calvert Cliffs costs to be:
. $40 million in 2000,
. $66 million in 2001,
. $88 million in 2002, and
. $60 million in 2003.
44
Additionally, our estimates of future electric construction expenditures include
the costs of complying with Environmental Protection Agency (EPA) and State of
Maryland nitrogen oxides emissions (NOx) reduction regulations as follows:
. $63 million in 2000,
. $52 million in 2001, and
. $4 million in 2002.
We discuss the NOx regulations and timing of expenses further in Note 10.
Our utility operations provided about 99% in 1999, 108% in 1998, and 105% in
1997 of the cash needed to meet its capital requirements, excluding cash needed
to retire debt and redeem preference stock.
During the three years from 2000 through 2002, we expect our existing utility
business to provide about 115% of the cash needed to meet the capital
requirements for these operations, excluding cash needed to retire debt. The
table for capital requirements includes the requirements for BGE fossil and
nuclear generation under "Utility Business Capital Requirements-Electric"
through 2002 even though these assets are to be transferred to nonregulated
subsidiaries on or about July 1, 2000.
We will continue to have cash requirements for:
. working capital needs including the payments of interest, distributions,
and dividends,
. capital expenditures, and
. the retirement of debt and redemption of preference stock.
When BGE cannot meet utility capital requirements internally, BGE sells debt and
preference stock. BGE also sells securities when market conditions permit it to
refinance existing debt or preference stock at a lower cost. The amount of cash
BGE needs and market conditions determine when and how much BGE sells.
Future funding for capital expenditures, the retirement of debt, and payments of
interest and dividends is expected from internally generated funds, commercial
paper issuances, available capacity under credit facilities, and/or the issuance
of long-term debt, trust securities, or preference stock.
At December 31, 1999, the Federal Energy Regulatory Commission has authorized
BGE to issue up to $700 million of short-term borrowings, including commercial
paper. In addition, BGE maintains $123 million in annual committed bank lines of
credit and has $60 million in bank revolving credit agreements to support the
commercial paper program as discussed in Note 7. In addition, BGE has access to
interim lines of credit as required from time to time to support its outstanding
commercial paper.
Capital Requirements of Our Diversified Businesses
Our energy services businesses will require additional funding for:
. growing its power marketing business,
. developing and acquiring power projects, and
. constructing cooling system projects.
Our energy services businesses' investment requirements include the planned
construction of 800 megawatts of peaking capacity in the Mid-Atlantic/Mid-West
region by the summer of 2001 and an additional 4,300 megawatts of peaking and
combined cycle production facilities scheduled for completion in 2002 and
beyond.
Our investment requirements also include our energy services businesses'
commitment to contribute up to an additional $121 million in equity to Orion. To
date, our energy services businesses have funded $104 million in equity to
Orion.
Our energy services businesses have met their capital requirements in the past
through borrowing, cash from their operations, and from time to time equity
contributions from BGE.
Future funding for the expansion of our energy services businesses is expected
from internally generated funds, commercial paper issuances and long-term debt
financing by Constellation Energy, and from time to time equity contributions
from Constellation Energy. BGE Home Products & Services may also meet capital
requirements through sales of receivables.
At December 31, 1999, Constellation Energy has a commercial paper program where
it can issue up to $500 million in short-term notes to fund its diversified
businesses. To support its commercial paper program, Constellation Energy
maintains $35 million in annual committed bank lines of credit and has a $135
million revolving credit agreement, under which it can also issue letters of
credit. In addition, Constellation Energy has access to interim lines of credit
as required from time to time to support its outstanding commercial paper.
ComfortLink has a revolving credit agreement totaling $50 million to provide
liquidity for short-term financial needs.
If we can get a reasonable value for our real estate projects, additional cash
may be obtained by selling them. Our ability to sell or liquidate assets will
depend on market conditions, and we cannot give assurances that these sales or
liquidations could be made. We discuss the real estate business and market in
the "Other Diversified Businesses" section.
We discuss our short-term borrowings in Note 7 and long-term debt in Note 8.
45
Market Risk
We are exposed to market risk, including changes in interest rates, certain
commodity prices, equity prices, and foreign currency. To manage our market
risk, we may enter into various derivative instruments including swaps, forward
contracts, futures contracts, and options. Effective July 1, 2000, we will be
subject to additional market risk associated with the purchase and sale of
energy as discussed in the "Current Issues" section. In this section, we discuss
our current market risk and the related use of derivative instruments.
Interest Rate Risk
We are exposed to changes in interest rates as a result of financing through our
issuance of variable-rate and fixed-rate debt. The following table provides
information about our obligations that are sensitive to interest rate changes:
Principal Payments and Interest Rate Detail by Contractual Maturity Date
Fair value at
2000 2001 2002 2003 2004 Thereafter Total Dec. 31, 1999
- ----------------------------------------------------------------------------------------------------------------------
(In millions)
Long-term debt
Variable-rate debt $201.9 $166.0 $ 0.9 $ 7.8 $ 5.4 $ 272.8 $ 654.8 $ 654.8
Average interest rate 6.68% 6.39% 8.32% 7.42% 7.41% 4.80% 5.84%
Fixed-rate debt $484.4 $482.8 $154.6 $289.4 $154.6 $1,173.7 $2,739.5 $2,637.3
Average interest rate 7.16% 7.08% 7.31% 6.52% 5.78% 6.83% 6.87%
Commodity Price Risk
We are exposed to the impact of market fluctuations in the price and
transportation costs of natural gas, electricity, and other trading commodities.
Currently, our gas business and energy services businesses use derivative
instruments to manage changes in their respective commodity prices.
Gas Business
Our gas business may enter into gas futures, options, and swaps to hedge its
price risk under our market based rate incentive mechanism and our off-system
gas sales program. We discuss this further in Note 1. At December 31, 1999 and
1998, our exposure to commodity price risk for our gas business was not
material.
Energy Services Businesses
With respect to our energy services businesses, Constellation Power Source
manages its commodity price risk inherent in its power marketing activities on a
portfolio basis, subject to established trading and risk management policies.
Commodity price risk arises from the potential for changes in the value of
energy commodities and related derivatives due to: changes in commodity prices,
volatility of commodity prices, and fluctuations in interest rates. A number of
factors associated with the structure and operation of the electricity market
significantly influence the level and volatility of prices for electricity and
related derivative products.
These factors include:
. seasonal changes in the demand for electricity,
. hourly fluctuations in demand due to weather conditions,
. available generation resources,
. transmission availability and reliability within and between regions, and
. procedures used to maintain the integrity of the physical electricity
system during extreme conditions.
These factors can affect energy commodity and derivative prices in different
ways and to different degrees. These effects may vary throughout the country and
result from regional differences in:
. weather conditions,
. market liquidity,
. capability and reliability of the physical electricity system, and
. the nature and extent of electricity deregulation.
Constellation Power Source uses various methods, including a value at risk
model, to measure its exposure to market risk. Value at risk is a statistical
model that attempts to predict risk of loss based on historical market price and
volatility data. Constellation Power Source calculates value at risk using a
variance/covariance technique that models option positions using a linear
approximation of their value. Additionally, Constellation Power Source estimates
variances and correlation using historical market movements over the most recent
rolling three-month period.
46
The value at risk amount represents the potential loss in the fair value of
assets and liabilities from trading activities over a one-day holding period
with a 99.6% confidence level. Using this confidence level, Constellation Power
Source would expect a one-day change in fair value greater than or equal to the
daily value at risk at least once per year. Constellation Power Source's value
at risk was $7.2 million as of December 31, 1999 compared to $6.0 million as of
December 31, 1998. The average, high, and low value at risk for the year ended
December 31, 1999 was $4.8 million, $7.2 million and $1.8 million, respectively.
Constellation Power Source's calculation includes all assets and liabilities
from its power marketing and trading activities, including energy commodities
and derivatives that do not require cash settlements. We believe that this
represents a more complete calculation of our value at risk.
Due to the inherent limitations of statistical measures such as value at risk,
the relative immaturity of the competitive market for electricity and related
derivatives, and the seasonality of changes in market prices, the value at risk
calculation may not reflect the full extent of our commodity price risk
exposure. Additionally, actual changes in the value of options may differ from
the value at risk calculated using a linear approximation inherent in our
calculation method. As a result, actual changes in the fair value of assets and
liabilities from power marketing and trading activities could differ from the
calculated value at risk and such changes could have a material impact on our
financial results. Please refer to the "Forward Looking Statements" section
below.
We discuss Constellation Power Source's business in the "Power Marketing"
section and in Note 1.
The commodity price risk for our remaining energy services businesses was not
material at December 31, 1999 and 1998.
Equity Price Risk
We are exposed to price fluctuations in equity markets primarily through our
financial investments business and our nuclear decommissioning trust fund. We
are required by the NRC to maintain a trust to fund the costs of decommissioning
Calvert Cliffs. At December 31, 1999 and 1998, equity price risk was not
material. We discuss our nuclear decommissioning trust fund in more detail in
Note 1. We also describe our financial investments in more detail in Note 3.
Foreign Currency Risk
We are exposed to foreign currency risk primarily through our power projects
business. Our power projects business has $254.1 million invested in 10
international power generation and distribution projects as of December 31,
1999. To manage our exposure to foreign currency risk, the majority of our
contracts are denominated in or indexed to the U.S. dollar. At December 31, 1999
and 1998, foreign currency risk was not material. We discuss our international
projects in the "Power Projects" section.
- --------------------------------------------------------------------------------
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
The information required by this item with respect to market risk is set forth
in Item 7 of Part II of this Form 10-K under the heading "Market Risk".
47
Item 8. Financial Statements and Supplementary Data
Report of Management
The management of the Companies is responsible for the information and
representations in the Companies' financial statements. The Companies prepare
the financial statements in accordance with generally accepted accounting
principles based upon available facts and circumstances and management's best
estimates and judgments of known conditions.
The Companies maintain accounting systems and related systems of internal
controls designed to provide reasonable assurance that the financial records are
accurate and that the Companies' assets are protected. The Companies' staff of
internal auditors, which reports directly to the Chairman of the Board, conducts
periodic reviews to maintain the effectiveness of internal control procedures.
PricewaterhouseCoopers LLP, independent accountants, audit the financial
statements and express their opinion on them. They perform their audit in
accordance with generally accepted auditing standards.
The Audit Committee of the Board of Directors, which consists of four outside
Directors, meets periodically with management, internal auditors, and
PricewaterhouseCoopers LLP to review the activities of each in discharging their
responsibilities. The internal audit staff and PricewaterhouseCoopers LLP have
free access to the Audit Committee.
/s/ Christian H. Poindexter /s/ David A. Brune
- --------------------------- -----------------------
Christian H. Poindexter David A. Brune
Chairman of the Board Chief Financial Officer
and Chief Executive Officer
Report of Independent Accountants
To the Shareholders of Constellation Energy Group, Inc. and Baltimore Gas and
Electric Company:
In our opinion, the consolidated financial statements listed in the index
appearing under Item 14(a) 1. present fairly, in all material respects, the
financial position of Constellation Energy Group, Inc. and Subsidiaries and of
Baltimore Gas and Electric Company and Subsidiaries at December 31, 1999 and
1998, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 1999 in conformity with accounting
principles generally accepted in the United States. In addition, in our opinion,
the financial statement schedule listed in the index appearing under Item 14(a)
2. of this Form 10-K present fairly, in all material respects, the information
set forth therein when read in conjunction with the related consolidated
financial statements. These financial statements and the financial statement
schedule are the responsibility of the Companies' management; our responsibility
is to express an opinion on these financial statements and financial statement
schedule based on our audits. We conducted our audits of these statements in
accordance with auditing standards generally accepted in the United States,
which require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for the opinion expressed above.
We have also previously audited, in accordance with auditing standards generally
accepted in the United States, the consolidated balance sheets and statement of
capitalization of Baltimore Gas and Electric Company and Subsidiaries as of
December 31, 1997, 1996 and 1995, and the related consolidated statements of
income, comprehensive income, cash flows, common shareholders' equity and income
taxes for the years ended December 31, 1996 and 1995 (none of which are
presented herein); and we expressed unqualified opinions on those consolidated
financial statements. In our opinion, the information set forth in the Summary
of Operations and Summary of Financial Condition of Constellation Energy Group,
Inc. included in the Selected Financial Data for each of the five years in the
period ended December 31, 1999, and the information set forth in the Summary of
Operations and Summary of Financial Condition of Baltimore Gas and Electric
Company included in the Selected Financial Data for each of the five years in
the period ended December 31, 1999, is fairly stated, in all material respects,
in relation to the consolidated financial statements from which it has been
derived.
/s/ PricewaterhouseCoopers LLP
- ------------------------------
PricewaterhouseCoopers LLP
Baltimore, Maryland
January 19, 2000
48
Consolidated Statements of Income
Constellation Energy Group, Inc. and Subsidiaries
Year Ended December 31, 1999 1998 1997
- -----------------------------------------------------------------------------------------------------------------
(In millions, except per share amounts)
Revenues
Electric $2,258.8 $2,219.2 $2,191.7
Gas 476.5 449.4 521.6
Diversified businesses 1,050.9 689.5 594.3
- ---------------------------------------------------------------------------------------------------------------
Total revenues 3,786.2 3,358.1 3,307.6
Operating Expenses
Electric fuel and purchased energy 467.7 505.7 519.7
Gas purchased for resale 230.6 208.6 292.1
Operations 546.0 554.1 518.3
Maintenance 186.2 177.5 178.5
Diversified businesses--selling, general, and administrative 918.7 574.6 515.7
Depreciation and amortization 449.8 377.1 342.9
Taxes other than income taxes 227.3 219.4 216.8
- -----------------------------------------------------------------------------------------------------------------
Total operating expenses 3,026.3 2,617.0 2,584.0
- -----------------------------------------------------------------------------------------------------------------
Income from Operations 759.9 741.1 723.6
Other Income (Expense)
Write-off of merger costs (see Note 2) - - (57.9)
Other 7.9 5.7 5.1
- -----------------------------------------------------------------------------------------------------------------
Total other income (expense) 7.9 5.7 (52.8)
- -----------------------------------------------------------------------------------------------------------------
Income Before Fixed Charges and Income Taxes 767.8 746.8 670.8
Fixed Charges
Interest expense (net) 241.5 240.9 230.0
BGE preference stock dividends 13.5 21.8 28.7
- -----------------------------------------------------------------------------------------------------------------
Total fixed charges 255.0 262.7 258.7
- -----------------------------------------------------------------------------------------------------------------
Income Before Income Taxes 512.8 484.1 412.1
Income Taxes 186.4 178.2 158.0
- -----------------------------------------------------------------------------------------------------------------
Income Before Extraordinary Item 326.4 305.9 254.1
Extraordinary Loss, Net of Income Taxes of $30.4 (see Note 4) (66.3) - -
- -----------------------------------------------------------------------------------------------------------------
Net Income $ 260.1 $ 305.9 $ 254.1
=================================================================================================================
Earnings Applicable to Common Stock $ 260.1 $ 305.9 $ 254.1
=================================================================================================================
Average Shares of Common Stock Outstanding 149.6 148.5 147.7
Earnings Per Common Share and Earnings Per Common Share
--Assuming Dilution Before Extraordinary Item $ 2.18 $ 2.06 $ 1.72
Extraordinary Loss (.44) - -
- -----------------------------------------------------------------------------------------------------------------
Earnings Per Common Share and Earnings Per Common Share
--Assuming Dilution $ 1.74 $ 2.06 $ 1.72
=================================================================================================================
Consolidated Statements of Comprehensive Income
Constellation Energy Group, Inc. and Subsidiaries
Year Ended December 31, 1999 1998 1997
- -----------------------------------------------------------------------------------------------------------------
(In millions)
Net Income $ 260.1 $ 305.9 $ 254.1
Other comprehensive income/(loss), net of taxes (6.2) 1.2 (0.8)
- -----------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 253.9 $ 307.1 $ 253.3
=================================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
49
Consolidated Balance Sheets
Constellation Energy Group, Inc. and Subsidiaries
At December 31, 1999 1998
- --------------------------------------------------------------------------------
(In millions)
Assets
Current Assets
Cash and cash equivalents $ 92.7 $ 173.7
Accounts receivable (net of allowance for uncollectibles
of $34.8 and $35.4 respectively) 578.5 422.7
Trading securities 136.5 119.7
Assets from energy trading activities 312.1 133.0
Fuel stocks 94.9 85.4
Materials and supplies 149.1 145.1
Prepaid taxes other than income taxes 72.4 68.8
Other 54.0 21.4
- --------------------------------------------------------------------------------
Total current assets 1,490.2 1,169.8
- --------------------------------------------------------------------------------
Investments and Other Assets
Real estate projects and investments 310.1 353.9
Power projects 785.4 743.1
Financial investments 145.4 198.0
Nuclear decommissioning trust fund 217.9 181.4
Net pension asset 99.5 108.0
Other 422.9 243.3
- --------------------------------------------------------------------------------
Total investments and other assets 1,981.2 1,827.7
- --------------------------------------------------------------------------------
Utility Plant
Plant in service
Electric 7,088.6 6,890.3
Gas 962.0 921.3
Common 569.5 552.8
- --------------------------------------------------------------------------------
Total plant in service 8,620.1 8,364.4
Accumulated depreciation (3,466.1) (3,087.5)
- --------------------------------------------------------------------------------
Net plant in service 5,154.0 5,276.9
Construction work in progress 222.3 223.0
Nuclear fuel (net of amortization) 133.8 132.5
Plant held for future use 13.0 24.3
- --------------------------------------------------------------------------------
Net utility plant 5,523.1 5,656.7
- --------------------------------------------------------------------------------
Deferred Charges
Regulatory assets (net) 637.4 565.7
Other 51.9 55.1
- --------------------------------------------------------------------------------
Total deferred charges 689.3 620.8
- --------------------------------------------------------------------------------
Total Assets $9,683.8 $9,275.0
================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
50
Consolidated Balance Sheets
Constellation Energy Group, Inc. and Subsidiaries
At December 31, 1999 1998
- --------------------------------------------------------------------------------
(In millions)
Liabilities and Capitalization
Current Liabilities
Short-term borrowings $ 371.5 $ -
Current portions of long-term debt and preference stock 808.3 541.7
Accounts payable 365.1 270.5
Customer deposits 40.6 35.5
Liabilities from energy trading activities 163.8 99.0
Dividends declared 66.1 66.1
Accrued taxes 19.2 6.5
Accrued interest 55.3 58.6
Accrued vacation costs 35.3 34.7
Other 78.2 45.3
- --------------------------------------------------------------------------------
Total current liabilities 2,003.4 1,157.9
- --------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes 1,288.8 1,309.1
Postretirement and postemployment benefits 269.8 217.0
Deferred investment tax credits 109.6 118.0
Decommissioning of federal uranium enrichment facilities 27.2 30.8
Other 226.6 142.6
- --------------------------------------------------------------------------------
Total deferred credits and other liabilities 1,922.0 1,817.5
- --------------------------------------------------------------------------------
Capitalization
Long-term debt 2,575.4 3,128.1
BGE preference stock not subject to mandatory redemption 190.0 190.0
Common shareholders' equity 2,993.0 2,981.5
- --------------------------------------------------------------------------------
Total capitalization 5,758.4 6,299.6
- --------------------------------------------------------------------------------
Commitments, Guarantees, and Contingencies (see Note 10)
Total Liabilities and Capitalization $9,683.8 $9,275.0
================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
51
Consolidated Statements of Cash Flows
Constellation Energy Group, Inc. and Subsidiaries
Year Ended December 31, 1999 1998 1997
- -----------------------------------------------------------------------------------------------------------------
(In millions)
Cash Flows From Operating Activities
Net income $ 260.1 $ 305.9 $ 254.1
Adjustments to reconcile to net cash provided by operating activities
Extraordinary loss 66.3 - -
Depreciation and amortization 505.9 429.4 396.8
Deferred income taxes 13.0 17.5 7.4
Investment tax credit adjustments (8.6) (8.8) (7.5)
Deferred fuel costs (61.1) (8.3) 18.3
Accrued pension and postemployment benefits 36.1 41.6 (18.0)
Write-off of merger costs - - 57.9
Write-downs of real estate investments 8.3 23.7 70.8
Write-down of financial investment 26.2 - -
Write-downs of power projects 28.5 - -
Equity in earnings of affiliates and joint ventures (net) (7.6) (54.5) (42.5)
Changes in assets from energy trading activities (179.1) (123.6) (9.4)
Changes in liabilities from energy trading activities 64.8 90.4 8.6
Changes in other current assets (216.4) 18.3 (54.7)
Changes in other current liabilities 121.0 77.0 42.6
Other 21.6 (8.8) (28.1)
- -----------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 679.0 799.8 696.3
- -----------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Utility construction and other capital expenditures (436.2) (406.1) (443.9)
Contributions to nuclear decommissioning trust fund (17.6) (17.6) (17.6)
Merger costs - - (20.9)
Purchases of marketable equity securities (27.3) (33.3) (23.0)
Sales of marketable equity securities 34.9 32.8 46.5
Other financial investments 13.7 14.6 (0.4)
Real estate projects and investments 49.3 21.5 24.2
Power projects (171.1) (252.5) (44.3)
Other (60.8) (70.7) (41.4)
- -----------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (615.1) (711.3) (520.8)
- -----------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Proceeds from issuance of
Short-term borrowings 2,801.9 1,962.2 2,719.0
Long-term debt 302.8 831.3 622.0
Common stock 9.6 51.8 -
Repayment of short-term borrowings (2,430.4) (2,278.3) (2,736.1)
Reacquisition of long-term debt (584.4) (355.2) (343.3)
Redemption of preference stock (7.0) (127.9) (104.5)
Common stock dividends paid (251.1) (246.0) (239.2)
Other 13.7 84.7 2.5
- -----------------------------------------------------------------------------------------------------------------
Net cash used in financing activities (144.9) (77.4) (79.6)
- -----------------------------------------------------------------------------------------------------------------
Net (Decrease) Increase in Cash and Cash Equivalents (81.0) 11.1 95.9
Cash and Cash Equivalents at Beginning of Year 173.7 162.6 66.7
- -----------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 92.7 $ 173.7 $ 162.6
=================================================================================================================
Other Cash Flow Information
Cash paid during the year for:
Interest (net of amounts capitalized) $ 245.3 $ 236.7 $ 224.2
Income taxes $ 165.6 $ 164.3 $ 171.2
Noncash Investing and Financing Activities:
In 1998, Corporate Office Properties Trust (COPT) assumed approximately $62
million of Constellation Real Estate Group's (CREG) debt and issued to CREG
7.0 million common shares and 985,000 convertible preferred shares. In
exchange, COPT received 14 operating properties and two properties under
development from CREG.
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
52
Consolidated Statements of Common Shareholders' Equity
Constellation Energy Group, Inc. and Subsidiaries
Accumulated
Other
Common Stock Retained Comprehensive Total
Years Ended December 31, 1999, 1998, and 1997 Shares Amount Earnings (Loss) Income Amount
- ------------------------------------------------------------------------------------------------------------------------------------
(Dollar amounts in millions, number of shares in thousands)
Balance at December 31, 1996 147,667 $1,429.9 $1,419.1 $5.7 $2,854.7
Net income 254.1 254.1
Common stock dividends declared ($1.63 per share) (240.7) (240.7)
Other 3.1 3.1
Net unrealized loss on securities (1.2) (1.2)
Deferred taxes on net unrealized loss on securities 0.4 0.4
- ------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 147,667 1,433.0 1,432.5 4.9 2,870.4
Net income 305.9 305.9
Common stock dividend declared ($1.67 per share) (248.1) (248.1)
Common stock issued 1,579 51.8 51.8
Other 0.3 0.3
Net unrealized gain on securities 1.8 1.8
Deferred taxes on net unrealized gain on securities (0.6) (0.6)
- ------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 149,246 1,485.1 1,490.3 6.1 2,981.5
Net income 260.1 260.1
Common stock dividend declared ($1.68 per share) (251.3) (251.3)
Common stock issued 310 9.6 9.6
Other (0.7) (0.7)
Net unrealized loss on securities (9.6) (9.6)
Deferred taxes on net unrealized loss on securities 3.4 3.4
- ------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 149,556 $1,494.0 $1,499.1 $(0.1) $2,993.0
====================================================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
53
Consolidated Statements of Capitalization
Constellation Energy Group, Inc. and Subsidiaries
At December 31, 1999 1998
- --------------------------------------------------------------------------------------------------------------------------
(In millions)
Long-Term Debt
First Refunding Mortgage Bonds of BGE
Floating rate series, due April 15, 1999 $ - $ 125.0
8.40% Series, due October 15, 1999 - 91.1
5 1/2% Series, due July 15, 2000 124.3 125.0
8 3/8% Series, due August 15, 2001 122.3 122.3
7 1/4% Series, due July 1, 2002 124.5 124.5
5 1/2% Installment Series, due July 15, 2002 8.5 9.1
6 1/2% Series, due February 15, 2003 124.8 124.8
6 1/8% Series, due July 1, 2003 124.9 124.9
5 1/2% Series, due April 15, 2004 125.0 125.0
Remarketed floating rate series, due September 1, 2006 125.0 125.0
7 1/2% Series, due January 15, 2007 123.5 123.5
6 5/8% Series, due March 15, 2008 124.9 124.9
7 1/2% Series, due March 1, 2023 109.9 125.0
7 1/2% Series, due April 15, 2023 84.1 84.1
- --------------------------------------------------------------------------------------------------------------------------
Total First Refunding Mortgage Bonds of BGE 1,321.7 1,554.2
- --------------------------------------------------------------------------------------------------------------------------
Other long-term debt of BGE
Medium-term notes, Series B 60.0 60.0
Medium-term notes, Series C 101.0 116.0
Medium-term notes, Series D 128.0 215.0
Medium-term notes, Series E 200.0 200.0
Medium-term notes, Series G 200.0 140.0
Medium-term notes, Series H 177.0 -
Pollution control loan, due July 1, 2011 36.0 36.0
Port facilities loan, due June 1, 2013 48.0 48.0
Adjustable rate pollution control loan, due July 1, 2014 20.0 20.0
5.55% Pollution control revenue refunding loan, due July 15, 2014 47.0 47.0
Economic development loan, due December 1, 2018 35.0 35.0
6.00% Pollution control revenue refunding loan, due April 1, 2024 75.0 75.0
Variable rate pollution control loan, due June 1, 2027 8.8 8.8
- --------------------------------------------------------------------------------------------------------------------------
Total other long-term debt of BGE 1,135.8 1,000.8
- --------------------------------------------------------------------------------------------------------------------------
BGE obligated mandatorily redeemable trust
preferred securities of subsidiary trust holding
solely 7.16% debentures of BGE 250.0 250.0
- --------------------------------------------------------------------------------------------------------------------------
Long-term debt of diversified businesses
Loans under revolving credit agreements 33.0 74.0
Mortgage and construction loans
7.90% mortgage note, due September 12, 2000 8.0 8.3
8.00% mortgage note, due July 31, 2001 0.1 0.1
8.00% mortgage note, due October 30, 2003 1.9 1.8
Variable rate mortgage notes and construction loans, due through 2004 112.0 149.5
4.25% mortgage note, due March 15, 2009 4.6 5.1
9.65% mortgage note, due February 1, 2028 9.6 9.6
8.00% mortgage note, due November 1, 2033 6.6 5.8
Unsecured notes 511.0 616.0
- --------------------------------------------------------------------------------------------------------------------------
Total long-term debt of diversified businesses 686.8 870.2
- --------------------------------------------------------------------------------------------------------------------------
Unamortized discount and premium (10.6) (12.4)
Current portion of long-term debt (808.3) (534.7)
- --------------------------------------------------------------------------------------------------------------------------
Total long-term debt $2,575.4 $3,128.1
- --------------------------------------------------------------------------------------------------------------------------
continued on next page
See Notes to Consolidated Financial Statements.
54
Consolidated Statements of Capitalization
Constellation Energy Group, Inc. and Subsidiaries
At December 31, 1999 1998
- --------------------------------------------------------------------------------------------------------------------------
(In millions)
BGE Preference Stock
Cumulative, $100 par value, 6,500,000 shares authorized
Redeemable preference stock
7.85%, 1991 Series $ - $ 7.0
Current portion of redeemable preference stock - (7.0)
- --------------------------------------------------------------------------------------------------------------------------
Total redeemable preference stock - -
- --------------------------------------------------------------------------------------------------------------------------
Preference stock not subject to mandatory redemption
7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003 40.0 40.0
6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003 50.0 50.0
6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004 40.0 40.0
6.99%, 1995 Series, 600,000 shares outstanding, not callable prior to October 1, 2005 60.0 60.0
- --------------------------------------------------------------------------------------------------------------------------
Total preference stock not subject to mandatory redemption 190.0 190.0
- --------------------------------------------------------------------------------------------------------------------------
Common Shareholders' Equity
Common stock without par value, 250,000,000 shares authorized; 149,556,416 and
149,245,641 shares issued and outstanding at December 31, 1999 and
1998, respectively. (At December 31, 1999 166,893 shares were reserved
for the Employee Savings Plan and 12,061,756 shares were reserved for the
Shareholder Investment Plan.) 1,494.0 1,485.1
Retained earnings 1,499.1 1,490.3
Accumulated other comprehensive (loss) income (0.1) 6.1
- --------------------------------------------------------------------------------------------------------------------------
Total common shareholders' equity 2,993.0 2,981.5
- --------------------------------------------------------------------------------------------------------------------------
Total Capitalization $5,758.4 $6,299.6
==========================================================================================================================
See Notes to Consolidated Financial Statements.
55
Consolidated Statements of Income Taxes
Constellation Energy Group, Inc. and Subsidiaries
Year Ended December 31, 1999 1998 1997
- -----------------------------------------------------------------------------------------------------------------
(Dollar amounts in millions)
Income Taxes
Current $182.0 $169.5 $158.1
- -----------------------------------------------------------------------------------------------------------------
Deferred
Change in tax effect of temporary differences 9.6 14.2 (1.0)
Change in income taxes recoverable through future rates - 3.9 8.0
Deferred taxes credited (charged) to shareholders' equity 3.4 (0.6) 0.4
- -----------------------------------------------------------------------------------------------------------------
Deferred taxes charged to expense 13.0 ` 17.5 7.4
Investment tax credit adjustments (8.6) (8.8) (7.5)
- -----------------------------------------------------------------------------------------------------------------
Income taxes per Consolidated Statements of Income $186.4 $178.2 $158.0
=================================================================================================================
Reconciliation of Income Taxes Computed at Statutory
Federal Rate to Total Income Taxes
Income before income taxes (excluding BGE preference stock dividends) $526.3 $505.9 $440.8
Statutory federal income tax rate 35% 35% 35%
- -----------------------------------------------------------------------------------------------------------------
Income taxes computed at statutory federal rate 184.2 177.1 154.3
Increases (decreases) in income taxes due to
Depreciation differences not normalized on regulated activities 15.3 13.6 13.9
Allowance for equity funds used during construction (2.2) (2.2) (1.9)
Amortization of deferred investment tax credits (8.6) (8.8) (7.5)
Tax credits flowed through to income (3.2) (0.3) (0.5)
Amortization of deferred tax rate differential on regulated activities (3.0) (2.3) (2.3)
State income taxes 8.9 9.8 6.2
Other (5.0) (8.7) (4.2)
- -----------------------------------------------------------------------------------------------------------------
Total income taxes $186.4 $178.2 $158.0
=================================================================================================================
Effective federal income tax rate 35.4% 35.2% 35.8%
At December 31, 1999 1998
- --------------------------------------------------------------------------------
(Dollar amounts in millions)
Deferred Income Taxes
Deferred tax liabilities
Accelerated depreciation $ 962.7 $1,009.9
Allowance for funds used during construction 202.3 204.5
Income taxes recoverable through future rates 35.7 88.4
Deferred termination and postemployment costs 14.7 32.3
Deferred fuel costs 25.8 4.5
Leveraged leases 19.9 22.6
Percentage repair allowance 35.0 36.8
Conservation expenditures 4.7 18.9
Energy trading activities 71.4 33.4
Deferred electric generation-related regulatory assets 100.3 -
Other 187.9 182.6
- --------------------------------------------------------------------------------
Total deferred tax liabilities 1,660.4 1,633.9
- --------------------------------------------------------------------------------
Deferred tax assets
Accrued pension and postemployment benefit costs 63.6 54.3
Deferred investment tax credits 38.3 41.3
Capitalized interest and overhead 48.3 46.6
Contributions in aid of construction 49.1 45.6
Nuclear decommissioning liability 25.4 22.8
Energy trading activities 15.1 20.3
Other 131.8 93.9
- --------------------------------------------------------------------------------
Total deferred tax assets 371.6 324.8
- --------------------------------------------------------------------------------
Deferred tax liability, net $1,288.8 $1,309.1
================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
56
Consolidated Statements of Income
Baltimore Gas and Electric Company and Subsidiaries
Year Ended December 31, 1999 1998 1997
- -----------------------------------------------------------------------------------------------------------------
(In millions)
Revenues
Electric $2,259.5 $2,219.2 $2,191.7
Gas 485.3 449.4 521.6
Diversified businesses 283.5 689.5 594.3
- -----------------------------------------------------------------------------------------------------------------
Total revenues 3,028.3 3,358.1 3,307.6
Operating Expenses
Electric fuel and purchased energy 486.8 505.7 519.7
Gas purchased for resale 233.7 208.6 292.1
Operations 543.9 554.1 518.3
Maintenance 184.9 177.5 178.5
Diversified businesses--selling, general, and administrative 222.1 574.6 515.7
Depreciation and amortization 427.9 377.1 342.9
Taxes other than income taxes 224.7 219.4 216.8
- -----------------------------------------------------------------------------------------------------------------
Total operating expenses 2,324.0 2,617.0 2,584.0
- -----------------------------------------------------------------------------------------------------------------
Income from Operations 704.3 741.1 723.6
Other Income (Expense)
Write-off of merger costs (see Note 2) - - (57.9)
Allowance for equity funds used during construction 6.2 6.3 5.3
Equity in earnings of Safe Harbor Water Power Corporation 5.1 5.0 5.0
Net other expense (2.9) (5.6) (5.2)
- -----------------------------------------------------------------------------------------------------------------
Total other income (expense) 8.4 5.7 (52.8)
- -----------------------------------------------------------------------------------------------------------------
Income Before Fixed Charges and Income Taxes 712.7 746.8 670.8
Fixed Charges
Interest expense (net) 210.1 247.9 241.2
Capitalized interest (0.4) (3.6) (8.4)
Allowance for borrowed funds used during construction (3.8) (3.4) (2.8)
- -----------------------------------------------------------------------------------------------------------------
Total fixed charges 205.9 240.9 230.0
- -----------------------------------------------------------------------------------------------------------------
Income Before Income Taxes 506.8 505.9 440.8
Income Taxes
Current 192.1 169.5 158.1
Deferred (5.2) 17.5 7.4
Investment tax credit adjustments (8.5) (8.8) (7.5)
- -----------------------------------------------------------------------------------------------------------------
Total income taxes 178.4 178.2 158.0
- -----------------------------------------------------------------------------------------------------------------
Income Before Extraordinary Item 328.4 327.7 282.8
Extraordinary Loss, Net of Income Taxes of $30.4 (see Note 4) (66.3) - -
- -----------------------------------------------------------------------------------------------------------------
Net Income 262.1 327.7 282.8
Preference Stock Dividends 13.5 21.8 28.7
- -----------------------------------------------------------------------------------------------------------------
Earnings Applicable to Common Stock $ 248.6 $ 305.9 $ 254.1
=================================================================================================================
Consolidated Statements of Comprehensive Income
Baltimore Gas and Electric Company and Subsidiaries
Year Ended December 31, 1999 1998 1997
- -----------------------------------------------------------------------------------------------------------------
(In millions)
Net Income $ 262.1 $ 327.7 $ 282.8
Other comprehensive income/(loss), net of taxes (3.4) 1.2 (0.8)
- -----------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 258.7 $ 328.9 $ 282.0
=================================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
57
Consolidated Balance Sheets
Baltimore Gas and Electric Company and Subsidiaries
At December 31, 1999 1998
- --------------------------------------------------------------------------------
(In millions)
Assets
Current Assets
Cash and cash equivalents $ 23.5 $ 173.7
Accounts receivable (net of allowance for uncollectibles
of $13.0 and $35.4 respectively) 316.1 422.7
Trading securities - 119.7
Assets from energy trading activities - 133.0
Fuel stocks 94.9 85.4
Materials and supplies 139.1 145.1
Prepaid taxes other than income taxes 72.4 68.8
Other 9.0 21.4
- --------------------------------------------------------------------------------
Total current assets 655.0 1,169.8
- --------------------------------------------------------------------------------
Investments and Other Assets
Real estate projects and investments - 353.9
Power projects - 743.1
Financial investments - 198.0
Nuclear decommissioning trust fund 217.9 181.4
Net pension asset 99.8 108.0
Safe Harbor Water Power Corporation 34.5 34.4
Senior living facilities - 93.5
Other 61.6 115.4
- --------------------------------------------------------------------------------
Total investments and other assets 413.8 1,827.7
- --------------------------------------------------------------------------------
Utility Plant
Plant in service
Electric 7,088.6 6,890.3
Gas 962.0 921.3
Common 569.5 552.8
- --------------------------------------------------------------------------------
Total plant in service 8,620.1 8,364.4
Accumulated depreciation (3,466.1) (3,087.5)
- --------------------------------------------------------------------------------
Net plant in service 5,154.0 5,276.9
Construction work in progress 222.3 223.0
Nuclear fuel (net of amortization) 133.8 132.5
Plant held for future use 13.0 24.3
- --------------------------------------------------------------------------------
Net utility plant 5,523.1 5,656.7
- --------------------------------------------------------------------------------
Deferred Charges
Regulatory assets (net) 637.4 565.7
Other 43.3 55.1
- --------------------------------------------------------------------------------
Total deferred charges 680.7 620.8
- --------------------------------------------------------------------------------
Total Assets $7,272.6 $9,275.0
================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
58
Consolidated Balance Sheets
Baltimore Gas and Electric Company and Subsidiaries
At December 31, 1999 1998
- --------------------------------------------------------------------------------------------------------------------------
(In millions)
Liabilities and Capitalization
Current Liabilities
Short-term borrowings $ 129.0 $ -
Current portions of long-term debt and preference stock 523.9 541.7
Accounts payable 222.8 270.5
Customer deposits 40.6 35.5
Liabilities from energy trading activities - 99.0
Dividends declared 3.3 66.1
Accrued taxes 9.2 6.5
Accrued interest 48.2 58.6
Accrued vacation costs 35.7 34.7
Other 65.8 45.3
- --------------------------------------------------------------------------------------------------------------------------
Total current liabilities 1,078.5 1,157.9
- --------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes 1,032.0 1,309.1
Postretirement and postemployment benefits 231.0 217.0
Deferred investment tax credits 109.6 118.0
Decommissioning of federal uranium enrichment facilities 27.2 30.8
Other 42.9 142.6
- --------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 1,442.7 1,817.5
- --------------------------------------------------------------------------------------------------------------------------
Long-term Debt
First refunding mortgage bonds of BGE 1,321.7 1,554.2
Other long-term debt of BGE 1,135.8 1,000.8
Company obligated mandatorily redeemable trust preferred
securities of subsidiary trust holding solely 7.16%
debentures of BGE 250.0 250.0
Long-term debt of diversified businesses 33.0 870.2
Unamortized discount and premium (10.6) (12.4)
Current portion of long-term debt (523.9) (534.7)
- --------------------------------------------------------------------------------------------------------------------------
Total long-term debt 2,206.0 3,128.1
- --------------------------------------------------------------------------------------------------------------------------
Redeemable Preference Stock - 7.0
Current portion of redeemable preference stock - (7.0)
- --------------------------------------------------------------------------------------------------------------------------
Total redeemable preference stock - -
- --------------------------------------------------------------------------------------------------------------------------
Preference Stock Not Subject to Mandatory Redemption 190.0 190.0
Common Shareholder's Equity
Common stock 1,494.0 1,485.1
Retained earnings 861.4 1,490.3
Accumulated other comprehensive income - 6.1
- --------------------------------------------------------------------------------------------------------------------------
Total common shareholder's equity 2,355.4 2,981.5
- --------------------------------------------------------------------------------------------------------------------------
Total capitalization 4,751.4 6,299.6
- --------------------------------------------------------------------------------------------------------------------------
Commitments, Guarantees, and Contingencies (see Note 10)
Total Liabilities and Capitalization $7,272.6 $9,275.0
==========================================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
59
Consolidated Statements of Cash Flows
Baltimore Gas and Electric Company and Subsidiaries
Year Ended December 31, 1999 1998 1997
- -----------------------------------------------------------------------------------------------------------------------
(In millions)
Cash Flows From Operating Activities
Net income $ 262.1 $ 327.7 $ 282.8
Adjustments to reconcile to net cash provided by operating activities
Extraordinary loss 66.3 - -
Depreciation and amortization 480.4 429.4 396.8
Deferred income taxes (5.2) 17.5 7.4
Investment tax credit adjustments (8.5) (8.8) (7.5)
Deferred fuel costs (61.1) (8.3) 18.3
Accrued pension and postemployment benefits 35.5 41.6 (18.0)
Write-off of merger costs - - 57.9
Write-downs of real estate investments - 23.7 70.8
Allowance for equity funds used during construction (6.2) (6.3) (5.3)
Equity in earnings of affiliates and joint ventures (net) 29.1 (54.5) (42.5)
Changes in assets from energy trading activities (133.0) (123.6) (9.4)
Changes in liabilities from energy trading activities 99.0 90.4 8.6
Changes in other current assets (15.1) 18.3 (54.7)
Changes in other current liabilities 22.7 77.0 42.6
Other 16.7 (3.3) (21.8)
- -----------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 782.7 820.8 726.0
- -----------------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Utility construction expenditures (including AFC) (385.9) (339.4) (373.2)
Allowance for equity funds used during construction 6.2 6.3 5.3
Nuclear fuel expenditures (49.2) (50.5) (43.6)
Deferred conservation expenditures (1.1) (16.2) (27.1)
Contributions to nuclear decommissioning trust fund (17.6) (17.6) (17.6)
Merger costs - - (20.9)
Purchases of marketable equity securities (9.2) (33.3) (23.0)
Sales of marketable equity securities 6.0 32.8 46.5
Other financial investments 6.7 14.6 (0.4)
Real estate projects and investments 22.0 21.5 24.2
Power projects (17.9) (252.5) (44.3)
Other (20.7) (77.0) (46.7)
- -----------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (460.7) (711.3) (520.8)
- -----------------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Proceeds from issuance of
Short-term borrowings 2,504.1 1,962.2 2,719.0
Long-term debt 257.2 831.3 622.0
Common stock 9.6 51.8 -
Repayment of short-term borrowings (2,375.1) (2,278.3) (2,736.1)
Reacquisition of long-term debt (466.3) (355.2) (343.3)
Redemption of preference stock (7.0) (127.9) (104.5)
Common stock dividends paid (251.1) (246.0) (239.2)
Preferred and preference stock dividends paid (13.6) (21.0) (29.7)
Distribution of cash to Constellation Energy (128.2) - -
Other (1.8) 84.7 2.5
- -----------------------------------------------------------------------------------------------------------------------
Net cash used in financing activities (472.2) (98.4) (109.3)
- -----------------------------------------------------------------------------------------------------------------------
Net (Decrease) Increase in Cash and Cash Equivalents (150.2) 11.1 95.9
Cash and Cash Equivalents at Beginning of Year 173.7 162.6 66.7
- -----------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 23.5 $ 173.7 $ 162.6
=======================================================================================================================
Other Cash Flow Information
Cash paid during the year for:
Interest (net of amounts capitalized) $ 200.2 $ 236.7 $ 224.2
Income taxes $ 178.8 $ 164.3 $ 171.2
Noncash Investing and Financing Activities:
In 1998, Corporate Office Properties Trust (COPT) assumed approximately $62
million of Constellation Real Estate Group's (CREG) debt and issued to CREG
7.0 million common shares and 985,000 convertible preferred shares. In
exchange, COPT received 14 operating properties and two properties under
development from CREG.
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
60
Notes to Consolidated Financial Statements
Note 1.
Significant Accounting Policies
Nature of Our Business
On April 30, 1999, Constellation Energy Group, Inc. (Constellation Energy)
became the holding company for Baltimore Gas and Electric Company (BGE) and
BGE's former subsidiary Constellation Enterprises, Inc. BGE's outstanding common
stock automatically became shares of common stock of Constellation Energy. BGE's
debt securities, obligated mandatorily redeemable trust preferred securities,
and preference stock remain securities of BGE.
Constellation Energy's subsidiaries primarily include BGE and a group of energy
services businesses mostly focused on power marketing and merchant generation in
North America.
BGE is an electric and gas public utility company with a service territory that
covers the City of Baltimore and all or part of ten counties in Central
Maryland. We describe our operating segments in Note 2.
References in this report to "we" and "our" are to Constellation Energy and its
subsidiaries, collectively. Reference in this report to the "utility business"
is to BGE.
Consolidation Policy
We use three different accounting methods to report our investments in our
subsidiaries or other companies: consolidation, the equity method, and the cost
method.
Consolidation
We use consolidation when we own a majority of the voting stock of the
subsidiary. This means the accounts of our subsidiaries are combined with our
accounts. We eliminate intercompany balances and transactions when we
consolidate these accounts.
This report is a combined report of Constellation Energy and BGE. The
consolidated financial statements of Constellation Energy include the accounts
of Constellation Energy, BGE and its subsidiaries, Constellation Enterprises,
Inc. and its subsidiaries, and Constellation Nuclear Group, LLC and its
subsidiaries. The consolidated financial statements of BGE include the accounts
of BGE, ComfortLink, and BGE Capital Trust I. As Constellation Enterprises and
its subsidiaries were subsidiaries of BGE prior to April 30, 1999, they are
included in the consolidated financial statements of BGE through that date.
The Equity Method
We usually use the equity method to report investments, corporate joint
ventures, partnerships, and affiliated companies (including power projects)
where we hold a 20% to 50% voting interest. Under the equity method, we report:
. our interest in the entity as an investment in our Consolidated Balance
Sheets, and
. our percentage share of the earnings from the entity in our Consolidated
Statements of Income.
The only time we do not use this method is if we can exercise control over the
operations and policies of the company. If we have control, accounting rules
require us to use consolidation.
BGE reports its investment in Safe Harbor Water Power Corporation (Safe Harbor)
under the equity method. Safe Harbor is a producer of hydroelectric power.
BGE owns two-thirds of Safe Harbor's total capital stock, including one-half of
the voting stock, and a two-thirds interest in its retained earnings. This
investment is included in "Investments and Other Assets - Other" in our
Consolidated Balance Sheets.
The Cost Method
We usually use the cost method if we hold less than a 20% voting interest in an
investment. Under the cost method, we report our investment at cost in our
Consolidated Balance Sheets. The only time we do not use this method is when we
can exercise significant influence over the operations and policies of the
company. If we have significant influence, accounting rules require us to use
the equity method.
Regulation of Utility Business
The Maryland Public Service Commission (Maryland PSC) provides the final
determination of the rates we charge our customers for our regulated businesses.
Generally, we use the same accounting policies and practices used by
nonregulated companies for financial reporting under generally accepted
accounting principles. However, sometimes the Maryland PSC orders an accounting
treatment different from that used by nonregulated companies to determine the
rates we charge our customers. When this happens, we must defer certain utility
expenses and income in our Consolidated Balance Sheets as regulatory assets and
liabilities. We have recorded these regulatory assets and liabilities in our
Consolidated Balance Sheets in accordance with Statement of Financial Accounting
Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of
Regulation. We summarize and discuss our regulatory assets and liabilities
further in Note 5.
In 1997, the Financial Accounting Standards Board (FASB) through its Emerging
Issues Task Force (EITF) issued EITF 97-4, Deregulation of the Pricing of
Electricity -Issues Related to the Application of FASB Statements No. 71 and
101. The EITF concluded that a company should cease to apply SFAS No. 71 when
either legislation is passed or a regulatory body issues an order that contains
sufficient detail
61
to determine how the transition plan will affect the deregulated portion of the
business. Additionally, a company would continue to recognize regulatory assets
and liabilities in the Consolidated Balance Sheets to the extent that the
transition plan provides for their recovery.
On November 10, 1999, the Maryland PSC issued a Restructuring Order that we
believe provided sufficient details of the transition plan to competition for
BGE's electric generation business to require BGE to discontinue the application
of SFAS No. 71 for that portion of its business. Accordingly, in the fourth
quarter of 1999, we adopted the provisions of SFAS No. 101, Regulated
Enterprises - Accounting for the Discontinuation of FASB Statement No. 71 and
EITF No. 97-4 for BGE's electric generation business. BGE's transmission and
distribution business continues to meet the requirements of SFAS No. 71 as that
business remains regulated. We discuss this further in Note 4.
Utility Revenues
We record utility revenues in our Consolidated Statements of Income when we
provide service to customers.
Fuel and Purchased Energy Costs
We incur costs for:
. the fuel we use to generate electricity,
. purchases of electricity from others, and
. natural gas that we resell.
These costs are shown in our Consolidated Statements of Income as "Electric fuel
and purchased energy" and "Gas purchased for resale." We discuss each of these
separately below.
Fuel Used to Generate Electricity and Purchases of Electricity From Others
Until July 1, 2000, we will continue to recover our costs of electric fuel under
the electric fuel rate clause set by the Maryland PSC. Under the electric fuel
rate clause, we charge our electric customers for:
. the fuel we use to generate electricity (nuclear fuel, coal, gas, or oil),
and
. the net cost of purchases and sales of electricity.
We charge the actual costs of these items to customers with no profit to us. To
do this, we must keep track of what we spend and what we collect from customers
under the fuel rate in a given period. Usually these two amounts are not the
same because there is a difference between the time we spend the money and the
time we collect it from our customers.
Under the electric fuel rate clause, we currently defer (include
as an asset or liability in our Consolidated Balance Sheets and exclude from our
Consolidated Statements of Income) the difference between our actual costs of
fuel and energy and what we collect from customers under the fuel rate in a
given period. We either bill or refund our customers that difference in the
future. We discuss this and the impact of the Restructuring Order on BGE's
electric fuel rate clause further in Note 5.
We calculate the electric fuel rate using three factors:
. the mix of generating plants we used over the last 24 months,
. the latest three-month average fuel cost for each generating unit, and
. the net cost of purchases and sales of electricity over the last 24 months.
Historically, we were able to change the fuel rate only if the calculated rate
was more than 5% above or below the rate in effect. The fuel rate was affected
most by the amount of electricity generated at our Calvert Cliffs Nuclear Power
Plant (Calvert Cliffs) because the cost of nuclear fuel is cheaper than coal,
gas, or oil. As a result of the Restructuring Order, the fuel rate is frozen at
its current level until July 1, 2000, at which time it will be discontinued. We
will continue to defer the difference between our actual costs of fuel and
energy and what we collect from customers under the fuel rate through June 30,
2000. After that date, earnings will be affected by the changes in the cost of
fuel and energy. In addition, any accumulated difference between our actual
costs of fuel and energy and the amounts collected from customers under the
electric fuel rate clause will be collected from our customers over a period to
be determined by the Maryland PSC.
Extended outages at Calvert Cliffs increase fuel costs.
Any increase in fuel costs, including extended outages at Calvert Cliffs through
June 30, 2000, may result in fuel rate proceedings before the Maryland PSC. In
these proceedings, the Maryland PSC would consider whether any portion of the
extra fuel costs should be paid by BGE instead of passed on to customers.
We also report two other items as "Electric fuel and purchased energy" in our
Consolidated Statements of Income:
. amortization of nuclear fuel (described under "Utility Plant" later in this
note). We amortize nuclear fuel based on the energy produced over the life of
the fuel. We pay quarterly fees to the Department of Energy for the future
disposal of spent nuclear fuel, and accrue these fees based on the kilowatt-
hours of electricity sold. We bill our customers for nuclear fuel as
described earlier in this note, and
. amortization of deferred costs of decommissioning and decontaminating the
Department of Energy's uranium enrichment facilities. We discuss these
costs further in Note 5.
62
Natural Gas
We charge our gas customers for the natural gas they purchase from us using "gas
cost adjustment clauses" set by the Maryland PSC. These clauses operate
similarly to the electric fuel rate clause described earlier in this Note.
However, the Maryland PSC approved a modification of the gas cost adjustment
clauses to provide a market based rates incentive mechanism. Under market based
rates our actual cost of gas is compared to a market index (a measure of the
market price of gas in a given period). The difference between our actual cost
and the market index is shared equally between shareholders and customers.
Risk Management
We engage in risk management activities in our gas business and in our
diversified businesses. We separately describe these activities for each
business below.
Gas Business
We use basis swaps in the winter months (November through March) to hedge our
price risk associated with natural gas purchases under our market based rates
incentive mechanism. We also use fixed-to-floating and floating-to-fixed swaps
to hedge our price risk associated with our off-system gas sales. The fixed
portion represents a specific dollar amount that we will pay or receive and the
floating portion represents a fluctuating amount based on a published index that
we will receive or pay. Our gas business internal guidelines do not permit the
use of swap agreements for any purpose other than to hedge price risk.
BGE's off-system gas activities represent trading activities under EITF 98-10,
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities. Accordingly, we use mark-to-market accounting to record these
transactions.
We defer, as unrealized gains or losses, the changes in fair value of the swap
agreements under the market based rates incentive mechanism and the customers'
portion of off-system gas sales in our Consolidated Balance Sheets. When amounts
are paid under the agreements, we report the payments as gas costs in our
Consolidated Statements of Income. We report the changes in fair value for the
shareholders' portion of off-system gas sales in earnings as a component of gas
costs.
Diversified Businesses
Our subsidiary, Constellation Power Source, engages in power marketing
activities, which include trading electricity, other energy commodities, and
related derivatives (such as futures, forwards, options, and swaps).
Constellation Power Source uses the mark-to-market method of accounting for its
trading activities.
Under the mark-to-market method of accounting, we report:
. commodity positions and derivatives at fair value as "Assets from energy
trading activities" or "Liabilities from energy trading activities" in our
Consolidated Balance Sheets, and
. changes in fair value as components of "Diversified business revenues" in
our Consolidated Statements of Income.
Taxes
We summarize our income taxes in our Consolidated Statements of Income Taxes. As
you read this section, it may be helpful to refer to those statements.
Income Tax Expense
We have two categories of income taxes in our Consolidated Statements of
Income--current and deferred. We describe each of these below.
Our current income tax expense consists solely of regular tax less applicable
tax credits.
Our deferred income tax expense is equal to the changes in the net deferred
income tax liability, excluding amounts charged or credited to common
shareholders' equity. Our deferred income tax expense is increased or reduced
for changes to the "Income taxes recoverable through future rates (net)"
regulatory asset (described later in this Note) during the year.
Investment Tax Credits
We have deferred the investment tax credit associated with our regulated utility
business in our Consolidated Balance Sheets. The investment tax credit is
amortized evenly to income over the life of each property. We reduce income tax
expense in our Consolidated Statements of Income for the investment tax credit
and other tax credits associated with our nonregulated diversified businesses,
other than leveraged leases.
63
Deferred Income Tax Assets and Liabilities
We must report some of our revenues and expenses differently for our financial
statements than we do for income tax purposes. The tax effects of the
differences in these items are reported as deferred income tax assets or
liabilities in our Consolidated Balance Sheets. We measure the assets and
liabilities using income tax rates that are currently in effect.
A portion of our total deferred income tax liability relates to our utility
business, but has not been reflected in the rates we charge our customers. We
refer to this portion of the liability as "Income taxes recoverable through
future rates (net)." We have recorded that portion of the net liability as a
regulatory asset in our Consolidated Balance Sheets. We discuss this further in
Note 5.
State and Local Taxes
Through December 31, 1999, we paid Maryland public service company franchise tax
instead of state income tax on our utility revenue from sales in Maryland. We
include the franchise tax in "Taxes other than income taxes" in our Consolidated
Statements of Income.
As discussed in Note 4, the tax legislation made comprehensive changes to the
state and local taxation of electric and gas utilities.
Inventory
We report the majority of our fuel stocks and materials and supplies at average
cost.
Real Estate Projects and Investments
In Note 3, we summarize the real estate projects and investments that are in our
Consolidated Balance Sheets. The projects and investments consist of:
. land under development in the Baltimore-Washington corridor,
. a mixed-use planned-unit development, and
. an equity interest in Corporate Office Properties Trust, a real estate
investment trust.
The costs incurred to acquire and develop properties are included as part of the
cost of the properties.
Financial Investments and Trading Securities
In Note 3, we summarize the financial investments that are in our Consolidated
Balance Sheets.
SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities,
applies particular requirements to some of our investments in debt and equity
securities. We report those investments at fair value, and we use specific
identification to determine their cost for computing realized gains or losses.
We classify these investments as either trading securities or available-for-sale
securities, which we describe separately below. We report investments that are
not covered by SFAS No. 115 at their cost.
Trading Securities
Our diversified businesses classify some of their investments in marketable
equity securities and financial limited partnerships as trading securities. We
include any unrealized gains or losses on these securities in "Diversified
business revenues" in our Consolidated Statements of Income.
Available-for-Sale Securities
We classify our investments in the nuclear decommissioning trust fund as
available-for-sale securities. We include any unrealized gains or losses on the
trust assets as a change in the decommissioning reserve. We describe the nuclear
decommissioning trust and the reserve under the heading "Decommissioning Costs"
later in this note.
In addition, our diversified businesses classify some of their investments in
marketable equity securities as available-for-sale securities. We include any
unrealized gains or losses on these securities in "Accumulated other
comprehensive (loss) income" in our Consolidated Statements of Common
Shareholders' Equity and in the Consolidated Statements of Capitalization. We
also include our diversified businesses' portion of unrealized gains or losses
on securities of equity-method (described earlier in this note) investees in our
Consolidated Statements of Common Shareholders' Equity.
Evaluation of Assets for Impairment
SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of, applies particular requirements to some of
our assets that have long lives (some examples are utility property and
equipment and real estate). We determine if those assets are impaired by
comparing their undiscounted expected future cash flows to their carrying amount
in our accounting records. We recognize an impairment loss if the undiscounted
expected future cash flows are less than the carrying amount of the asset. See
Note 4 for further discussion.
64
Utility Plant, Depreciation, Amortization, and Decommissioning
Utility Plant
Utility plant is the term we use to describe our utility business property and
equipment that is in use, being held for future use, or under construction. We
summarize utility plant in our Consolidated Balance Sheets. We report our
utility plant at its original cost, unless impaired under the provisions of SFAS
No. 121. Our original cost includes:
. material and labor,
. contractor costs,
. construction overhead costs (where applicable), and
. an allowance for funds used during construction (described later in this
note).
We charge retired or otherwise-disposed-of utility plant to accumulated
depreciation.
We own an undivided interest in the Keystone and Conemaugh electric generating
plants in Western Pennsylvania, as well as in the transmission line that
transports the plants' output to the joint owners' service territories. Our
ownership interests in these plants are 20.99% in Keystone and 10.56% in
Conemaugh. These ownership interests represented a net investment of $156
million at December 31, 1999 and $152 million at December 31, 1998. We report
these properties in the same accounts we use for our other utility plant
(described above).
Depreciation Expense
Generally, we compute depreciation by applying composite, straight-line rates
(approved by the Maryland PSC) to the average investment in classes of
depreciable property. We depreciate vehicles based on their estimated useful
lives.
Amortization Expense
Amortization is an accounting process of reducing an amount in our Consolidated
Balance Sheets evenly over a period of time. When we reduce amounts in our
Consolidated Balance Sheets, we increase amortization expense in our
Consolidated Statements of Income. An amount is considered fully amortized when
it has been reduced to zero.
Decommissioning Costs
We must accumulate a reserve for the costs that we expect to incur in the future
to decommission the radioactive portion of Calvert Cliffs. We do this based on a
sinking fund methodology. The Maryland PSC authorized us to record
decommissioning expense based on a facility-specific cost estimate so we can
accumulate a decommissioning reserve of $521 million in 1993 dollars by the end
of Calvert Cliffs' service life in 2016, adjusted to reflect expected inflation.
We have reported the decommissioning reserve in "Accumulated depreciation" in
our Consolidated Balance Sheets. The total reserve was $287.5 million at
December 31, 1999 and $244.0 million at December 31, 1998.
To fund the costs we expect to incur to decommission the plant, we established
an external decommissioning trust in accordance with Nuclear Regulatory
Commission (NRC) regulations. We report the assets in the trust in "Nuclear
decommissioning trust fund" in our Consolidated Balance Sheets. The NRC requires
utilities to provide financial assurance that they will accumulate sufficient
funds to pay for the cost of nuclear decommissioning based upon either a generic
NRC formula or a facility-specific decommissioning cost estimate. We use the
facility-specific cost estimate for funding these costs and providing the
required financial assurance.
Allowance for Funds Used During Construction and Capitalized Interest
Allowance for Funds Used During Construction (AFC)
We finance utility construction projects with borrowed funds and equity funds.
We are allowed by the Maryland PSC to record the costs of these funds as part of
the cost of construction projects in our Consolidated Balance Sheets. We do this
through the AFC, which we calculate using a rate authorized by the Maryland PSC.
We bill our customers for the AFC plus a return after the utility plant is
placed in service.
The AFC rates are 9.04% for gas plant, 9.35% for common plant, and 9.40% for
electric plant. We compound AFC annually.
Capitalized Interest
With the issuance of the Restructuring Order, we ceased accruing AFC for
electric generation-related construction projects and began using SFAS No. 34,
Capitalizing Interest Costs, to calculate the cost during construction of debt
funds used to finance our electric generation-related construction projects.
Our diversified businesses capitalize interest costs incurred to finance real
estate developed for internal use and certain power projects.
65
Long-Term Debt
We defer (include as an asset or liability in our Consolidated Balance Sheets
and exclude from our Consolidated Statements of Income) all costs related to the
issuance of long-term debt. These costs include underwriters' commissions,
discounts or premiums, and other costs such as legal, accounting, and regulatory
fees, and printing costs. We amortize these costs over the life of the debt.
When we incur gains or losses on debt that we retire prior to maturity in our
regulated utility business, we amortize those gains or losses over the remaining
original life of the debt.
Cash Flows
For the purpose of reporting our cash flows, we define cash equivalents as
highly liquid investments that mature in three months or less.
Use of Accounting Estimates
Management makes estimates and assumptions when preparing financial statements
under generally accepted accounting principles. These estimates and assumptions
affect various matters, including:
. our reported amounts of assets and liabilities in our Consolidated Balance
Sheets at the dates of the financial statements,
. our disclosure of contingent assets and liabilities at the dates of the
financial statements, and
. our reported amounts of revenues and expenses in our Consolidated
Statements of Income during the reporting periods.
These estimates involve judgments with respect to, among other things, future
economic factors that are difficult to predict and are beyond management's
control. As a result, actual amounts could differ from these estimates.
Reclassifications
We have reclassified certain prior-year amounts for comparative purposes. These
reclassifications did not affect consolidated net income for the years
presented.
Accounting Standards Issued
In July 1999, the FASB issued SFAS No. 137 that delays the effective date for
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, by
one year. Therefore, we must adopt the provisions of SFAS No. 133 in our
financial statements for the quarter ended March 31, 2001. We have not
determined the effects of SFAS No. 133 on our financial results.
- --------------------------------------------------------------------------------
Note 2.
Information by Operating Segment
We have three reportable operating segments--Electric, Gas, and Energy Services:
. Our Electric business generates, purchases, and sells electricity,
. Our Gas business purchases, transports, and sells natural gas, and
. Our Energy Services businesses consist of certain diversified businesses
that:
- develop, own, and operate power projects,
- provide power marketing and risk management services,
- provide nuclear consulting services,
- sell natural gas through mass marketing efforts,
- sell and service electric and gas appliances, heating and air
conditioning systems, and engage in home improvements, and
- provide cooling services to commercial customers in Baltimore.
Our remaining diversified businesses:
. engage in financial investments, and
. develop, own, and manage real estate and senior-living facilities.
These reportable segments are strategic businesses based principally upon
regulations, products, and services that require different technology and
marketing strategies. The segments have the same accounting policies as those
described in the summary of significant accounting policies in Note 1. The
Company evaluates the performance of these segments based on net income. We
account for intersegment revenues using market prices. A summary of information
by operating segment is shown later in this note.
We are realigning our organization combining all of our domestic merchant energy
businesses. We have not determined the impact of this reorganization on our
operating segments, but such changes will impact our operating segments in the
future.
66
Energy Other Unallocated
Electric Gas Services Diversified Corporate
Business Business Businesses Businesses Items (a) Eliminations Consolidated
- -----------------------------------------------------------------------------------------------------------------------------------
(In millions)
1999
Unaffiliated revenues $2,258.8 $476.5 $ 937.0 $113.9 $ - $ - $3,786.2
Intersegment revenues 1.2 11.6 30.4 (0.4) - (42.8) -
- -----------------------------------------------------------------------------------------------------------------------------------
Total revenues 2,260.0 488.1 967.4 113.5 - (42.8) 3,786.2
Depreciation and amortization 376.4 44.9 23.1 5.2 0.2 - 449.8
Equity in income of equity-
method investees (b) 5.1 - - - - - 5.1
Net interest expense 162.4 24.4 24.6 31.1 0.4 (1.4) 241.5
Income tax expense (benefit) 149.2 18.1 34.8 (12.1) (0.9) (2.7) 186.4
Extraordinary loss 66.3 - - - - - 66.3
Net income (loss) (c) 198.8 33.0 50.6 (19.3) (1.7) (1.3) 260.1
Segment assets 6,312.6 915.3 1,681.2 743.2 129.2 (97.7) 9,683.8
Utility construction expenditures 322.1 63.8 - - - - 385.9
1998
Unaffiliated revenues $2,219.2 $449.4 $ 524.1 $165.4 $ - $ - $3,358.1
Intersegment revenues 1.6 1.7 12.0 0.5 - (15.8) -
- -----------------------------------------------------------------------------------------------------------------------------------
Total revenues 2,220.8 451.1 536.1 165.9 - (15.8) 3,358.1
Depreciation and amortization 313.0 45.4 9.2 9.3 0.2 - 377.1
Equity in income of equity-
method investees (b) 5.0 - - - - - 5.0
Net interest expense 164.9 23.6 16.0 38.6 (1.9) (0.3) 240.9
Income tax expense (benefit) 146.6 13.4 34.1 (15.8) (0.1) - 178.2
Net income (loss) (d) 259.6 26.1 43.4 (24.2) (0.1) 1.1 305.9
Segment assets 6,342.8 934.6 1,315.0 811.6 (14.0) (115.0) 9,275.0
Utility construction expenditures 279.0 60.4 - - - - 339.4
1997
Unaffiliated revenues $2,191.7 $521.6 $ 399.4 $194.9 $ - $ - $3,307.6
Intersegment revenues 0.3 - 0.6 9.7 - (10.6) -
- -----------------------------------------------------------------------------------------------------------------------------------
Total revenues 2,192.0 521.6 400.0 204.6 - (10.6) 3,307.6
Depreciation and amortization 286.5 39.3 6.9 9.9 0.3 - 342.9
Equity in income of equity-
method investees (b) 5.0 - - - - - 5.0
Net interest expense 160.7 20.3 10.1 32.5 6.4 - 230.0
Income tax expense (benefit) 135.7 13.9 23.8 (13.5) (1.9) - 158.0
Net income (loss) (e) 224.0 25.6 27.5 (21.1) (3.6) 1.7 254.1
Segment assets 6,404.4 907.7 700.9 885.4 10.7 (9.1) 8,900.0
Utility construction expenditures 278.7 94.5 - - - - 373.2
(a) We do not allocate certain items presented in the table for Constellation
Energy Group and a holding company for our diversified businesses.
(b) Our Energy Services and our Other Diversified businesses record their equity
in the income of equity method investees in their unaffiliated revenues.
(c) Our Electric business recorded costs of $4.9 million after-tax related to
Hurricane Floyd as discussed in the "Electric Operations and Maintenance
Expenses" section of Management's Discussion and Analysis. Our Other Diversified
businesses recorded a $16.0 million write-down of its investment in Capital Re
stock to reflect the market value of this investment as discussed in Note 3 and
a $5.8 million write-down of certain senior-living facilities as discussed in
the "Other Diversified Businesses" section of Management's Discussion and
Analysis. In addition, our Energy Services businesses recorded $18.7 million in
write-downs of certain power projects as discussed in Note 3.
(d) Our Energy Services businesses recorded $10.4 million for its share of
earnings in a partnership as discussed in Note 3 and a $5.5 million write-off of
an energy services investment as discussed in the "Other Energy Services"
section of Management's Discussion and Analysis. In addition, our Other
Diversified businesses recorded a $15.4 million write-down of a real estate
project as discussed in Note 3.
(e) Our Electric business recorded a $37.5 million write-off related to the
terminated merger with Potomac Electric Power Company as discussed in the "Other
Income and Expenses" section of Management's Discussion and Analysis. In
addition, our Other Diversified businesses recorded a $46.0 million write-down
of two real estate projects as discussed in Note 3.
67
Note 3.
Investments
Real Estate Projects and Investments
Real estate projects and investments held by Constellation Real Estate Group
(CREG), consist of the following:
At December 31, 1999 1998
- --------------------------------------------------------------------------------
(In millions)
Properties under development $197.8 $210.6
Rental and operating properties
(net of accumulated depreciation) 9.2 38.9
Equity interest in real estate
investment trust 103.1 104.0
Other real estate ventures - 0.4
- --------------------------------------------------------------------------------
Total real estate projects
and investments $310.1 $353.9
================================================================================
In 1999, CREG sold Church Street Station --an entertainment, dining, and retail
complex in Orlando, Florida --for $11.5 million, the approximate book value of
the complex.
In 1998, CREG recorded a $15.4 million after-tax write-down of the investment in
Church Street Station that occurred because the fair value of the project
declined based upon competitive bids.
In 1998, CREG entered into an agreement with Corporate Office Properties Trust
(COPT), a real estate investment trust based in Philadelphia, under which COPT
assumed approximately $62 million of CREG's outstanding debt, paid CREG
approximately $22.8 million in cash, and issued to CREG approximately 7.0
million common shares representing a 41.9% equity interest in COPT and 985,000
convertible preferred shares. Each convertible preferred share yields 5.5% per
year, and is convertible after two years from the date of the agreement into
1.8748 common shares.
In exchange, COPT received 14 operating properties and two properties under
development from CREG as well as certain other assets, options, and first
refusal rights. These options and first refusal rights are related to
approximately 91 acres of identified properties which are adjacent to operating
properties acquired by COPT. At December 31, 1999, 48 acres remain under these
options and first refusal rights and have terms that range from 1 to 4 years.
In 1997, CREG recorded the following write-downs of real estate projects:
. a $14.1 million after-tax write-down of the investment in Church Street
Station that occurred because CREG decided to sell rather than keep the
project, and
. a $31.9 million after-tax write-down of the investment in Piney Orchard--a
mixed-use, planned-unit development-- that occurred because the expected
future cash flow from the project was less than CREG's investment in the
project.
Power Projects
Power projects held by our diversified businesses consist of the following:
At December 31, 1999 1998
- --------------------------------------------------------------------------------
(In millions)
Domestic
East $ 55.7 $ 46.0
West 475.6 427.4
International
South America 12.3 21.6
Central America 241.8 248.1
- --------------------------------------------------------------------------------
Total power projects $785.4 $743.1
================================================================================
Our Domestic-West power projects include investments of $301.8 million in 1999
and $310.6 in 1998 that sell electricity in California under power purchase
agreements called "Interim Standard Offer No. 4" agreements. We discuss these
projects further in Note 10.
In 1999, our power projects business recorded a $14.2 million after-tax
write-off of two geothermal power projects. These write-offs occurred because
the expected future cash flows from the projects are less than the investment in
the projects. For the first project, this resulted from the inability to
restructure certain project agreements. For the second project, we experienced a
declining water temperature of the geothermal resource used by one of the plants
for production.
In 1999, we recorded a $4.5 million after-tax write-down to reflect the fair
value of our investment in a generating company in Bolivia as a result of our
international exit strategy.
In 1998, our power projects business recorded $10.4 million after-tax gain for
its share of earnings in a partnership. The partnership recognized a gain on the
sale of its ownership interest in a power sales contract.
68
Financial Investments
Financial investments held by Constellation Investments, Inc. consist of the
following:
At December 31, 1999 1998
- --------------------------------------------------------------------------------
(In millions)
Insurance company $ - $102.5
Marketable equity securities 84.2 25.3
Financial limited partnerships 35.8 41.9
Leveraged leases 25.4 28.3
- --------------------------------------------------------------------------------
Total financial investments $145.4 $198.0
================================================================================
In 1999, our financial investments business announced that it would exchange its
shares of common stock in Capital Re, an insurance company, for common stock of
ACE Limited (ACE), another insurance company, as part of a business combination
whereby ACE would acquire all of the outstanding capital stock of Capital Re.
Through September 30, 1999, our financial investments business wrote-down its
$94.2 million investment in Capital Re stock by $20.9 million after-tax to
reflect the market value of this investment. The agreement between ACE and
Capital Re was subsequently revised on a more favorable basis for Capital Re to
include both cash and ACE stock. In December 1999, the transaction was finalized
and our financial investments business recorded a $4.9 million after-tax gain on
this investment to reflect the closing price of the business combination. As a
result of this business combination, this investment no longer qualifies as an
equity-method investment. Accordingly, in 1999, we have included this investment
in the marketable equity securities amount above.
Investments Classified as Available-for-Sale
We classify our investments in the nuclear decommissioning trust fund as
available-for-sale. In addition, we classify some of our diversified businesses'
marketable equity securities (shown above) as available-for-sale. This means we
do not expect to hold them to maturity and we do not consider them trading
securities.
We show the fair values, gross unrealized gains and losses, and amortized cost
bases for all of our available-for-sale securities, exclusive of $6.2 million in
1998 of unrealized net gains on securities held by Capital Re as an equity
method investee, in the following tables.
Amortized Unrealized Unrealized Fair
At December 31, 1999 Cost Basis Gains Losses Value
- --------------------------------------------------------------------------------
(In millions)
Marketable equity
securities $167.1 $42.8 $(2.1) $207.8
Corporate debt and
U.S. Government
agency 14.4 - - 14.4
State municipal bonds 74.2 - (0.8) 73.4
- --------------------------------------------------------------------------------
Totals $255.7 $42.8 $(2.9) $295.6
================================================================================
Amortized Unrealized Unrealized Fair
At December 31, 1998 Cost Basis Gains Losses Value
- --------------------------------------------------------------------------------
(In millions)
Marketable equity
securities $ 82.9 $24.2 $(0.4) $106.7
Corporate debt and
U.S. Government
agency 12.7 0.4 - 13.1
State municipal bonds 64.8 2.7 - 67.5
- --------------------------------------------------------------------------------
Totals $160.4 $27.3 $(0.4) $187.3
================================================================================
The above tables include $40.5 million in 1999 and $23.9 million in 1998 of
unrealized net gains associated with the nuclear decommissioning trust fund
which are reflected as a change in the nuclear decommissioning trust fund on the
Consolidated Balance Sheets.
Gross and net realized gains and losses on available-for-sale securities were as
follows:
Year Ended December 31, 1999 1998 1997
- --------------------------------------------------------------------------------
(In millions)
Gross realized gains $11.7 $ 4.2 $ 9.3
Gross realized losses (38.8) (0.7) (0.6)
- --------------------------------------------------------------------------------
Net realized (losses) gains $(27.1) $ 3.5 $ 8.7
- --------------------------------------------------------------------------------
The Corporate debt securities, U.S. Government agency obligations, and state
municipal bonds mature on the following schedule:
At December 31, 1999 Amount
- --------------------------------------------------------------------------------
(In millions)
Less than 1 year $ 1.0
1-5 years 46.4
5-10 years 21.8
More than 10 years 18.6
- --------------------------------------------------------------------------------
Total maturities of debt securities $ 87.8
- --------------------------------------------------------------------------------
69
Note 4.
Rate Matters and Accounting Impacts of Deregulation
On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition
Act of 1999 (the "Act") and accompanying tax legislation that will significantly
restructure Maryland's electric utility industry and modify the industry's tax
structure. In the Restructuring Order discussed below, the Maryland PSC
addressed the major provisions of the Act.
The tax legislation made comprehensive changes to the state and local taxation
of electric and gas utilities. Effective January 1, 2000, the Maryland public
service franchise tax will be altered to generally include a tax equal to .062
cents on each kilowatt-hour of electricity and .402 cents on each therm of
natural gas delivered for final consumption in Maryland. The Maryland 2%
franchise tax on electric and natural gas utilities will continue to apply to
transmission and distribution revenue. Additionally, all electric and natural
gas utility results will become subject to the Maryland corporate income tax.
Beginning July 1, 2000, the tax legislation also provides for a two-year
phase-in of a 50% reduction in the local personal property taxes on machinery
and equipment used to generate electricity for resale and a 60% corporate income
tax credit for real property taxes paid on those facilities.
On November 10, 1999, the Maryland PSC issued a Restructuring Order that
resolves the major issues surrounding electric restructuring, accelerates the
timetable for customer choice, and addresses the major provisions of the Act.
The Restructuring Order also resolves the electric restructuring proceeding
(transition costs, customer price protections, and unbundled rates for electric
services) and a petition filed in September 1998 by the Office of People's
Counsel (OPC) to lower our electric base rates. The major provisions of the
Restructuring Order are:
. All customers, except a few commercial and industrial companies that have
signed contracts with BGE, will be able to choose their electric energy
supplier beginning July 1, 2000. BGE will provide a standard offer service
for customers that do not select an alternative supplier. In either case,
BGE will continue to deliver electricity to all customers in areas
traditionally served by BGE.
. BGE's current electric base rates are frozen at their current levels until
July 1, 2000.
. BGE will reduce residential base rates by approximately 6.5% on average,
about $54 million a year, beginning July 1, 2000. These rates will not change
before July 2006.
. Commercial and industrial customers will have up to four service options
that will fix electric energy rates and transition charges for a period
that generally ranges from four to six years.
. Electric delivery service rates will be frozen for a four year period for
commercial and industrial customers. The generation and transmission
components of rates will be frozen for different time periods depending on
the service options selected by those customers.
. BGE will be allowed to recover $528 million after-tax of its potentially
stranded investments and utility restructuring costs through a competitive
transition charge on customers' bills. Residential customers will pay this
charge for six years. Commercial and industrial customers will pay in a
lump sum or over the four to six-year period, depending on the service
option selected by each customer.
. Generation-related regulatory assets and nuclear decommissioning costs will
be included in delivery service rates effective July 1, 2000 and will be
recovered on a basis approximating their existing amortization schedules.
. Starting July 1, 2000, BGE will unbundle rates to show separate components
for delivery service, transition charges, standard offer services
(generation), transmission, universal service, and taxes.
. On July 1, 2000, BGE will transfer, at book value, its ten Maryland-based
fossil and nuclear power plants and its partial ownership interest in two
coal plants and a hydroelectric plant in Pennsylvania to nonregulated
subsidiaries of Constellation Energy.
. BGE will reduce its generation assets, as described later in this section,
by $150 million pre-tax during the period July 1, 1999 - June 30, 2000 to
mitigate a portion of its potentially stranded investments.
. Universal service will be provided for low-income customers without
increasing their bills. BGE will provide its share of a statewide fund
totaling $34 million annually.
70
As discussed in Note 1, EITF 97-4 requires that a company should cease applying
SFAS No. 71 when either legislation is passed or a regulatory body issues an
order that contains sufficient detail to determine how the transition plan will
affect the deregulated portion of the business. Additionally, a company would
continue to recognize regulatory assets and liabilities in the Consolidated
Balance Sheets to the extent that the transition plan provides for their
recovery.
We believe that the Restructuring Order provided sufficient details of the
transition plan to competition for BGE's electric generation business to require
BGE to discontinue the application of SFAS No. 71 for that portion of its
business. Accordingly, in the fourth quarter of 1999, we adopted the provisions
of SFAS No. 101 and EITF 97-4 for BGE's electric generation business.
SFAS No. 101 requires the elimination of the effects of rate regulation that
have been recognized as regulatory assets and liabilities pursuant to SFAS No.
71. However, EITF 97-4 requires that regulatory assets and liabilities that will
be recovered in the regulated portion of the business continue to be classified
as regulatory assets and liabilities. The Restructuring Order provides for the
creation of a single, new generation-related regulatory asset to be recovered
through BGE's regulated transmission and distribution business. We discuss this
further in Note 5.
Pursuant to SFAS No. 101, the book value of property, plant, and equipment may
not be adjusted unless those assets are impaired under the provisions of SFAS
No. 121. The process of evaluating and measuring impairment under the provisions
of SFAS No. 121 involves two steps. First, we must compare the net book value of
each generating plant to the estimated undiscounted future net operating cash
flows from that plant. An electric generating plant is considered impaired when
its undiscounted future net operating cash flows are less than its net book
value. Second, we compute the fair value of each plant that is determined to be
impaired based on the present value of that plant's estimated future net
operating cash flows discounted using an interest rate that considers the risk
of operating that facility in a competitive environment. To the extent that the
net book value of each impaired electric generation plant exceeds its fair
value, we must record a write-down.
Under the Restructuring Order, BGE will recover $528 million after-tax of its
potentially stranded investments and utility restructuring costs through the
competitive transition charge component of its customer rates beginning July 1,
2000. This recovery mostly relates to the stranded costs associated with Calvert
Cliffs, whose book value is substantially higher than its estimated fair value.
However, Calvert Cliffs is not considered impaired under the provisions of SFAS
No. 121 since its estimated future undiscounted cash flows exceed its book
value. Accordingly, BGE did not record any impairment write-down related to
Calvert Cliffs. However, we recognized after-tax impairment losses totaling
$115.8 million associated with certain of our fossil plants under the provisions
of SFAS No. 121.
BGE has contracts to purchase electric capacity and energy that are expected to
be uneconomic upon the deregulation of electric generation. Therefore, we
recorded a $34.2 million after-tax charge based on the net present value of the
excess of estimated contract costs over the market-based revenues to recover
these costs over the remaining terms of the contracts. In addition, BGE has
deferred certain energy conservation expenditures that will not be recovered
through its transmission and distribution business under the Restructuring
Order. Accordingly, we recorded a $10.3 million after-tax charge to eliminate
the regulatory asset previously established for these deferred expenditures.
At December 31, 1999, the total charge for BGE's electric generating plants that
are impaired, losses on uneconomic purchased capacity and energy contracts, and
deferred energy conservation expenditures was approximately $160.3 million after
tax.
BGE recorded approximately $94.0 million of the $160.3 million on its balance
sheet. This consisted of a $150.0 million regulatory asset of its regulated
transmission and distribution business, net of approximately $56.0 million of
associated deferred income taxes. The regulatory asset will be amortized as it
is recovered from ratepayers through June 30, 2000. This will accomplish the
$150 million reduction of its generation plants required by the Restructuring
Order.
We recorded an after-tax, extraordinary charge against earnings for
approximately $66.3 million related to the remaining portion of the $160.3
million described above that will not be recovered under the Restructuring
Order.
71
Note 5.
Regulatory Assets (net)
As discussed in Note 1, the Maryland PSC provides the final determination of the
rates we charge our customers for our regulated businesses. Generally, we use
the same accounting policies and practices used by nonregulated companies for
financial reporting under generally accepted accounting principles. However,
sometimes the Maryland PSC orders an accounting treatment different from that
used by nonregulated companies to determine the rates we charge our customers.
When this happens, we must defer certain utility expenses and income in our
Consolidated Balance Sheets as regulatory assets and liabilities. We then record
them in our Consolidated Statements of Income (using amortization) when we
include them in the rates we charge our customers.
We summarize regulatory assets and liabilities in the following table, and we
discuss each of them separately below.
At December 31, 1999 1998
- --------------------------------------------------------------------------------
(In millions)
Generation plant reduction
recoverable in current rates $ 75.0 $ -
Electric generation-related
regulatory asset 286.6 -
Income taxes recoverable through
future rates (net) 110.4 252.6
Deferred postretirement and
postemployment benefit costs 41.9 90.0
Deferred nuclear expenditures - 73.3
Deferred conservation expenditures 12.9 53.4
Deferred costs of decommissioning
federal uranium enrichment facilities - 38.5
Deferred environmental costs 31.3 33.4
Deferred fuel costs (net) 73.8 12.7
Other (net) 5.5 11.8
- --------------------------------------------------------------------------------
Total regulatory assets (net) $637.4 $565.7
================================================================================
Generation Plant Reduction Recoverable in Current Rates
As a condition of the Maryland PSC's consolidation of the September 3, 1998
Office of People's Counsel petition to lower electric base rates with BGE's
electric restructuring transition proposal, we agreed to make our rates subject
to refund effective July 1, 1999. Under the Restructuring Order, BGE's rates are
frozen through June 30, 2000. However, BGE was required to record a reduction to
its generation plant of $150 million which it will recover through its current
rates between July 1, 1999 and June 30, 2000. BGE recorded a $150 million
regulatory asset for the required generation plant reduction that will be
amortized as it is recovered from ratepayers through June 30, 2000.
Electric Generation-Related Regulatory Asset
With the issuance of the Restructuring Order, BGE no longer met the requirements
for the application of SFAS No. 71 for the electric generation portion of its
business. In accordance with SFAS No. 101 and EITF 97-4, all individual
generation-related regulatory assets and liabilities must be eliminated from our
balance sheet unless these regulatory assets and liabilities will be recovered
in the regulated portion of the business. Pursuant to the Restructuring Order,
BGE wrote-off all of its individual, generation-related regulatory assets and
liabilities. A single, new generation-related regulatory asset was established
for amounts to be collected through BGE's regulated transmission and
distribution business. The new regulatory asset will be amortized on a basis
that approximates the pre-existing individual regulatory asset amortization
schedules.
Income Taxes Recoverable Through Future Rates (net)
As described in Note 1, income taxes recoverable through future rates is the
portion of our net deferred income tax liability that is applicable to our
utility business, but has not been reflected in the rates we charge our
customers. These income taxes represent the tax effect of temporary differences
in depreciation and the allowance for equity funds used during construction,
offset by differences in deferred tax rates and deferred taxes on deferred
investment tax credits. We amortize these amounts as the temporary differences
reverse.
In 1999, the electric generation-related portion of this regulatory asset is
included in the electric generation-related regulatory asset discussed earlier
in this note.
72
Deferred Postretirement and Postemployment Benefit Costs
Deferred postretirement and postemployment benefit costs are the costs we
recorded under SFAS No. 106 (for postretirement benefits) and No. 112 (for
postemployment benefits) in excess of the costs we included in the rates we
charge our customers. We began amortizing these costs over a 15-year period in
1998. We discuss these costs further in Note 6.
In 1999, we reclassified the electric generation-related portion of this
regulatory asset to the electric generation-related regulatory asset discussed
earlier in this note.
Deferred Nuclear Expenditures
Deferred nuclear expenditures are the net unamortized balance of certain
operations and maintenance costs at Calvert Cliffs. These expenditures consist
of:
. costs incurred from 1979 through 1982 for inspecting and repairing seismic
pipe supports,
. expenditures incurred from 1989 through 1994 associated with nonrecurring
phases of certain nuclear operations projects, and
. expenditures incurred during 1990 for investigating leaks in the
pressurizer heater sleeves.
In 1999, these expenditures were reclassified to the electric generation-related
regulatory asset discussed earlier in this note.
Deferred Conservation Expenditures
Deferred conservation expenditures include two components:
. operations costs (labor, materials, and indirect costs) associated with
conservation programs approved by the Maryland PSC, which we are amortizing
over periods of four to five years in accordance with the Maryland PSC's
orders, and
. revenues we collected from customers in 1996 in excess of our profit limit
under the conservation surcharge.
In 1999, we wrote-off a portion of the unamortized electric conservation
expenditures that will not be recovered under the Restructuring Order as
discussed in Note 4.
Deferred Costs of Decommissioning Federal Uranium Enrichment Facilities
Deferred costs of decommissioning federal uranium enrichment facilities are the
unamortized portion of our required contributions to a fund for decommissioning
and decontaminating the Department of Energy's uranium enrichment facilities. We
are required, along with other domestic utilities, by the Energy Policy Act of
1992 to make contributions to the fund. The contributions are generally payable
over 15 years with escalation for inflation and are based upon the proportionate
amount of uranium enriched by the Department of Energy for each utility. We are
amortizing these costs over the contribution period as a cost of fuel. We also
discuss this in Note 1.
In 1999, these expenditures were reclassified to the electric generation-related
regulatory asset discussed earlier in this note.
Deferred Environmental Costs
Deferred environmental costs are the estimated costs of investigating and
cleaning up contaminated sites we own.
We discuss this further in Note 10. We are amortizing $21.6 million of these
costs (the amount we had incurred through October 1995) over a 10-year period in
accordance with the Maryland PSC's November 1995 order.
Deferred Fuel Costs
As described in Note 1, deferred fuel costs are the difference between our
actual costs of electric fuel, net purchases and sales of electricity, and
natural gas and our fuel rate revenues collected from customers. We reduce
deferred fuel costs as we collect them from or refund them to our customers.
We show our deferred fuel costs in the following table.
At December 31, 1999 1998
- --------------------------------------------------------------------------------
(In millions)
Electric $60.0 $(11.5)
Gas 13.8 24.2
- --------------------------------------------------------------------------------
Deferred fuel costs (net) $73.8 $ 12.7
================================================================================
Under the Restructuring Order, BGE's electric fuel rate clause will be
discontinued effective July 1, 2000. After that date, earnings will be affected
by the changes in the cost of fuel and energy. In addition, any accumulated
difference between our actual costs of fuel and energy and the amounts collected
from customers under the electric fuel rate clause will be collected from our
customers over a period to be determined by the Maryland PSC.
73
Note 6.
Pension, Postretirement, Other Postemployment, and Employee Savings
Plan Benefits
We offer pension, postretirement, other postemployment, and employee savings
plan benefits. We describe each of these separately below.
Pension Benefits
We sponsor several defined benefit pension plans for our employees. A defined
benefit plan specifies the amount of benefits a plan participant is to receive
using information about the participant. Our employees do not contribute to
these plans. Generally, we calculate the benefits under these plans based on
age, years of service, and pay.
Sometimes we amend the plans retroactively. These retroactive plan amendments
require us to recalculate benefits related to participants' past service. We
amortize the change in the benefit costs from these plan amendments on a
straight-line basis over the average remaining service period of active
employees.
In 1999, our Board of Directors approved the following amendments:
. eligible participants will be allowed to choose between an enhanced version
of the current benefit formula and a new pension equity plan (PEP) formula.
Pension benefits for eligible employees hired after December 31, 1999 will
be based on a PEP formula, and
. pension and survivor benefits were increased for participants who retired
prior to January 1, 1994 and for their surviving spouses.
The financial impacts of the amendments are included in the tables in this
section.
Also during 1999, our Board of Directors approved a Targeted Voluntary Special
Early Retirement Program (TVSERP) to provide enhanced early retirement benefits
to certain eligible participants in targeted jobs that elect to retire on June
1, 2000. The financial impacts of the TVSERP will be reflected in the second
quarter of 2000.
We fund the plans by contributing at least the minimum amount required under
Internal Revenue Service regulations. We calculate the amount of funding using
an actuarial method called the projected unit credit cost method. The assets in
all of the plans at December 31, 1999 were mostly marketable equity and fixed
income securities, and group annuity contracts.
Postretirement Benefits
We sponsor defined benefit postretirement health care and life insurance plans
which cover nearly all Constellation Energy and BGE employees, and certain
employees of our subsidiaries. Generally, we calculate the benefits under these
plans based on age, years of service, and pension benefit levels. We do not fund
these plans.
For nearly all of the health care plans, retirees make contributions to cover a
portion of the plan costs. Contributions for employees who retire after June 30,
1992 are calculated based on age and years of service. The amount of retiree
contributions increases based on expected increases in medical costs. For the
life insurance plan, retirees do not make contributions to cover a portion of
the plan costs.
Effective January 1, 1993, we adopted SFAS No. 106, Employers' Accounting for
Postretirement Benefits Other Than Pensions. The adoption of that statement
caused:
. a transition obligation, which we are amortizing over 20 years, and
. an increase in annual postretirement benefit costs.
For our diversified businesses, we expense all postretirement benefit costs. For
our utility business, we accounted for the increase in annual postretirement
benefit costs under two Maryland PSC rate orders:
. in an April 1993 rate order, the Maryland PSC allowed us to expense
one-half and defer, as a regulatory asset (see Note 5), the other half of
the increase in annual postretirement benefit costs related to our electric
and gas businesses, and
. in a November 1995 rate order, the Maryland PSC allowed us to expense all
of the increase in annual postretirement benefit costs related to our gas
business.
Beginning in 1998, the Maryland PSC authorized us to:
. expense all of the increase in annual postretirement benefit costs related
to our electric business, and
. amortize the regulatory asset for postretirement benefit costs related to
our electric and gas businesses over 15 years.
74
Obligations, Assets, and Funded Status
We show the change in the benefit obligations, plan assets, and funded status of
the pension and postretirement benefit plans in the following table:
Pension Postretirement
Benefits Benefits
1999 1998 1999 1998
- --------------------------------------------------------------------------------
(In millions)
Change in benefit obligation
Benefit obligation at
January 1 $1,031.3 $ 902.0 $383.1 $320.3
Service cost 26.1 21.6 8.6 6.6
Interest cost 65.3 63.0 24.4 23.4
Plan participants'
contributions - - 2.0 2.0
Actuarial (gain) loss (93.0) 102.9 (34.2) 48.9
Plan amendments 44.6 - (5.0) -
Benefits paid (57.6) (58.2) (20.2) (18.1)
- --------------------------------------------------------------------------------
Benefit obligation at
December 31 $1,016.7 $1,031.3 $358.7 $383.1
================================================================================
Pension Postretirement
Benefits Benefits
1999 1998 1999 1998
- --------------------------------------------------------------------------------
(In millions)
Change in plan assets
Fair value of plan assets at
January 1 $ 985.5 $912.3 $ - $ -
Actual return on
plan assets 139.4 116.9 - -
Employer contribution 17.6 14.5 18.2 16.1
Plan participants'
contributions - - 2.0 2.0
Benefits paid (57.6) (58.2) (20.2) (18.1)
- --------------------------------------------------------------------------------
Fair value of plan assets
at December 31 $1,084.9 $985.5 $ - $ -
================================================================================
Pension Postretirement
Benefits Benefits
1999 1998 1999 1998
- --------------------------------------------------------------------------------
(In millions)
Funded Status
Funded status at
December 31 $ 68.2 $(45.8) $(358.7) $(383.1)
Unrecognized net
actuarial (gain) loss (27.2) 137.6 23.6 59.7
Unrecognized prior
service cost 59.0 16.9 (0.1) -
Unrecognized
transition obligation - - 143.4 159.3
Unamortized net asset from
adoption of SFAS No. 87 (0.5) (0.7) - -
- --------------------------------------------------------------------------------
Prepaid (accrued) benefit
cost $ 99.5 $108.0 $(191.8) $(164.1)
================================================================================
Net Periodic Benefit Cost
We show the components of net periodic pension benefit cost in the following
table:
Year Ended December 31, 1999 1998 1997
- --------------------------------------------------------------------------------
(In millions)
Components of net periodic
pension benefit cost
Service cost $ 26.1 $ 21.6 $ 16.8
Interest cost 65.3 63.0 61.3
Expected return on plan assets (76.6) (72.1) (66.9)
Amortization of transition
obligation (0.2) (0.2) (0.2)
Amortization of prior service cost 2.5 2.5 2.5
Recognized net actuarial loss 10.1 5.6 4.6
Amount capitalized as
construction cost (4.2) (3.8) (2.5)
- --------------------------------------------------------------------------------
Net periodic pension benefit cost $ 23.0 $ 16.6 $ 15.6
================================================================================
75
We show the components of net periodic postretirement benefit cost in the
following table:
Year Ended December 31, 1999 1998 1997
- --------------------------------------------------------------------------------
(In millions)
Components of net periodic
postretirement benefit cost
Service cost $ 8.6 $ 6.6 $ 5.4
Interest cost 24.4 23.4 21.8
Amortization of transition
obligation 11.0 11.4 11.4
Recognized net actuarial loss 1.9 0.2 0.1
Amount capitalized as
construction cost (9.4) (8.1) (7.6)
Amount deferred - - (7.2)
- --------------------------------------------------------------------------------
Net periodic postretirement
benefit cost $36.5 $33.5 $23.9
================================================================================
Assumptions
We made the assumptions below to calculate our pension and postretirement
benefit obligations.
Pension Postretirement
Benefits Benefits
At December 31, 1999 1998 1999 1998
- --------------------------------------------------------------------------------
Discount rate 7.25% 6.50% 7.25% 6.50%
Expected return on
plan assets 9.00 9.00 N/A N/A
Rate of compensation
increase 4.00 4.00 4.00 4.00
We assumed the health care inflation rates to be:
. in 1999, 6.0% for both Medicare-eligible retirees and retirees not covered
by Medicare, and
. in 2000, 7.0% for Medicare-eligible retirees and 8.5% for retirees not
covered by Medicare.
After 2000, we assumed both inflation rates will decrease by 0.5% annually to a
rate of 5.5% in the years 2003 and 2006, respectively. After these dates, the
inflation rate will remain at 5.5%.
A one-percent increase in the health care inflation rate from the assumed rates
would increase the accumulated postretirement benefit obligation by
approximately $46.7 million as of December 31, 1999 and would increase the
combined service and interest costs of the postretirement benefit cost by
approximately $5.4 million annually.
A one-percent decrease in the health care inflation rate from the assumed rates
would decrease the accumulated postretirement benefit obligation by
approximately $37.4 million as of December 31, 1999 and would decrease the
combined service and interest costs of the postretirement benefit cost by
approximately $4.2 million annually.
Other Postemployment Benefits
We provide the following postemployment benefits:
. health and life insurance benefits to our employees and certain employees
of our subsidiaries who are found to be disabled under our Disability
Insurance Plan, and
. income replacement payments for employees found to be disabled before
November 1995 (payments for employees found to be disabled after that date
are paid by an insurance company, and the cost is paid by employees).
The liability for these benefits totaled $46.5 million as of December 31, 1999
and $52.9 million as of December 31, 1998.
Effective December 31, 1993, we adopted SFAS No. 112, Employers' Accounting for
Postemployment Benefits. We deferred, as a regulatory asset (see Note 5), the
postemployment benefit liability attributable to our utility business as of
December 31, 1993, consistent with the Maryland PSC's orders for postretirement
benefits (described earlier in this note). We began to amortize the regulatory
asset over 15 years beginning in 1998. The Maryland PSC authorized us to reflect
this change in our current electric and gas base rates to recover the higher
costs in 1998.
We assumed the discount rate for other postemployment benefits to be 5.5% in
1999 and 4.5% in 1998.
Employee Savings Plan Benefits
We also sponsor a defined contribution savings plan that is offered to all
eligible Constellation Energy and BGE employees, and certain employees of our
subsidiaries. In a defined contribution plan, the benefits a participant is to
receive result from regular contributions to a participant account. Under this
plan, we make matching contributions to participant accounts. We made matching
contributions to this plan of:
. $10.4 million in 1999,
. $10.1 million in 1998, and
. $8.5 million in 1997.
76
Note 7.
Short-Term Borrowings
Our short-term borrowings may include bank loans, commercial paper notes, and
bank lines of credit. Short-term borrowings mature within one year from the date
of issuance. We pay commitment fees to banks for providing us lines of credit.
When we borrow under the lines of credit, we pay market interest rates.
Constellation Energy
At December 31, 1999, Constellation Energy had $242.5 million outstanding
consisting entirely of commercial paper notes. At December 31, 1998, no
short-term borrowings were outstanding since Constellation Energy was not
established until April 30, 1999 as discussed in Note 1.
In 1999, Constellation Energy arranged a $135 million revolving credit agreement
for short-term financial needs, including letters of credit. This agreement also
supports Constellation Energy's commercial paper notes. This facility replaced a
similar facility at one of Constellation Energy's diversified businesses. At
December 31, 1999, letters of credit totaling $23.1 million were issued under
this facility.
In addition, Constellation Energy had unused committed bank lines of credit
totaling $35 million and interim lines totaling $125 million supporting its
commercial paper notes at December 31, 1999.
The weighted average effective interest rate for Constellation Energy's
commercial paper notes was 5.68% for the year ended December 31, 1999.
BGE
At December 31, 1999, BGE had $129.0 million outstanding consisting entirely of
commercial paper notes. At December 31, 1998, BGE had no short-term borrowings
outstanding.
At December 31, 1999, BGE had unused committed bank lines of credit totaling
$123 million supporting the commercial paper notes compared to $113 million at
December 31, 1998. These amounts do not include unused revolving credit
agreements of $60 million at December 31, 1999 and $100 million at December 31,
1998 that are discussed in Note 8.
The weighted average effective interest rates for BGE's commercial paper notes
were 5.25% for the year ended December 31, 1999 and 5.65% for 1998.
- --------------------------------------------------------------------------------
Note 8.
Long-Term Debt
Long-term debt matures in one year or more from the date of issuance. We
summarize our long-term debt in the Consolidated Statements of Capitalization.
As you read this section, it may be helpful to refer to those statements.
BGE
BGE's First Refunding Mortgage Bonds
BGE's first refunding mortgage bonds are secured by a mortgage lien on nearly
all of its assets, including all utility properties and franchises and its
subsidiary capital stock. Capital stock pledged under the mortgage is that of
Safe Harbor Water Power Corporation and Constellation Enterprises, Inc. When BGE
transfers its generating assets to subsidiaries of Constellation Energy, these
assets will remain subject to the lien of BGE's mortgage. However, BGE will
remain liable for this debt after the assets are transferred.
BGE is required to make an annual sinking fund payment each August 1 to the
mortgage trustee. The amount of the payment is equal to 1% of the highest
principal amount of bonds outstanding during the preceding 12 months. The
trustee uses these funds to retire bonds from any series through repurchases or
calls for early redemption. However, the trustee cannot call the following bonds
for early redemption:
. 5 1/2% Installment Series, due 2002 . 6 1/8% Series, due 2003
. 5 1/2% Series, due 2000 . 5 1/2% Series, due 2004
. 8 3/8% Series, due 2001 . 7 1/2% Series, due 2007
. 7 1/4% Series, due 2002 . 6 5/8% Series, due 2008
. 6 1/2% Series, due 2003
Holders of the Remarketed Floating Rate Series Due September 1, 2006 have the
option to require BGE to repurchase their bonds at face value on September 1 of
each year. BGE is required to repurchase and retire at par any bonds that are
not remarketed or purchased by the remarketing agent. BGE also has the option to
redeem all or some of these bonds at face value each September 1.
77
BGE's Other Long-Term Debt
We show the weighted-average interest rates and maturity dates for BGE's fixed-
rate medium-term notes outstanding at December 31, 1999 in the following table.
Weighted-Average
Series Interest Rate Maturity Dates
- --------------------------------------------------------------------------------
B 8.10% 2000-2006
C 7.33 2000-2003
D 6.66 2001-2006
E 6.66 2006-2012
G 6.08 2001-2008
Some of the medium-term notes include a "put option." These put options allow
the holders to sell their notes back to BGE on the put option dates at a price
equal to 100% of the principal amount. The following is a summary of medium-term
notes with put options.
Series E Notes Principal Put Option Dates
- --------------------------------------------------------------------------------
(In millions)
6.75%, due 2012 $60.0 June 2002 and 2007
6.75%, due 2012 25.0 June 2004 and 2007
6.73%, due 2012 25.0 June 2004 and 2007
BGE has $60 million of revolving credit agreements with several banks that are
available through 2000. At December 31, 1999, BGE had no outstanding borrowings
under these agreements. These banks charge us commitment fees based on the daily
average of the unborrowed amount, and we pay market interest rates on any
borrowings. These agreements also support BGE's commercial paper notes, as
described in Note 7.
BGE Obligated Mandatorily Redeemable Trust Preferred Securities
On June 15, 1998, BGE Capital Trust I (Trust), a Delaware business trust
established by BGE, issued 10,000,000 Trust Originated Preferred Securities
(TOPrS) for $250 million ($25 liquidation amount per preferred security) with a
distribution rate of 7.16%.
The Trust used the net proceeds from the issuance of the common securities and
the preferred securities to purchase a series of 7.16% Deferrable Interest
Subordinated Debentures due June 30, 2038 (debentures) from BGE in the aggregate
principal amount of $257.7 million with the same terms as the TOPrS. The Trust
must redeem the TOPrS at $25 per preferred security plus accrued but unpaid
distributions when the debentures are paid at maturity or upon any earlier
redemption. BGE has the option to redeem the debentures at any time on or after
June 15, 2003 or at any time when certain tax or other events occur.
The interest paid on the debentures, which the Trust will use to make
distributions on the TOPrS, is included in "Interest Expense" in the
Consolidated Statements of Income and is deductible for income tax purposes.
BGE fully and unconditionally guarantees the TOPrS based on its various
obligations relating to the trust agreement, indentures, debentures, and the
preferred security guarantee agreement.
The debentures are the only assets of the Trust. The Trust is wholly owned by
BGE because it owns all the common securities of the Trust that have general
voting power.
For the payment of dividends and in the event of liquidation of BGE, the
debentures are ranked prior to preference stock and common stock.
Diversified Businesses
Revolving Credit Agreements
ComfortLink has a $50 million unsecured revolving credit agreement that matures
September 26, 2001. Under the terms of the agreement, ComfortLink has the option
to obtain loans at various rates for terms up to nine months. ComfortLink pays a
facility fee on the total amount of the commitment.
At December 31, 1999, ComfortLink had $33 million outstanding under this
agreement.
Mortgage and Construction Loans
Our diversified businesses' mortgage and construction loans have varying terms.
The following mortgage notes require monthly principal and interest payments:
. 7.90%, due in 2000 . 9.65%, due in 2028
. 8.00%, due in 2001 . 8.00%, due in 2033
. 4.25%, due in 2009
The 8.00% mortgage note due in 2003 requires interest payments until maturity.
The variable rate mortgage notes and construction loans require periodic payment
of principal and interest.
Unsecured Notes
The unsecured notes mature on the following schedule:
Amount
- --------------------------------------------------------------------------------
(In millions)
7.125%, due March 13, 2000 $ 15.0
7.55%, due April 22, 2000 35.0
7.50%, due May 5, 2000 139.0
7.43%, due September 9, 2000 30.0
5.43% due October 15, 2000 5.0
7.66%, due May 5, 2001 135.0
5.67%, due May 5, 2001 152.0
- --------------------------------------------------------------------------------
Total unsecured notes at December 31, 1999 $511.0
================================================================================
78
Maturities of Long-Term Debt
All of our long-term borrowings mature on the following schedule (includes
sinking fund requirements):
Diversified
Year BGE Businesses
- --------------------------------------------------------------------------------
(In millions)
2000 $ 401.9 $284.4
2001 282.2 366.6
2002 154.0 1.5
2003 286.8 10.4
2004 154.0 6.0
Thereafter 1,428.6 17.9
- --------------------------------------------------------------------------------
Total long-term debt
at December 31, 1999 $2,707.5 $686.8
================================================================================
At December 31, 1999, BGE had long-term loans totaling $255.0 million that
mature after 2002 (including $110.0 million of medium-term notes discussed in
this Note under "BGE's Other Long-Term Debt") that lenders could potentially
require us to repay early. Of this amount, $145.0 million could be repaid in
2000, $60.0 million in 2002, and $50.0 million thereafter. At December 31, 1999,
$122.0 million is classified as current portion of long-term debt as a result of
these provisions.
Weighted Average Interest Rates for Variable Rate Debt
Our weighted average interest rates for variable rate debt were:
Year Ended December 31, 1999 1998
- --------------------------------------------------------------------------------
BGE
Floating rate series mortgage bonds 5.41% 5.90%
Remarketed floating rate
series mortgage bonds 5.19 5.70
Medium-term notes, Series D 5.29 5.74
Medium-term notes, Series G 5.38 .-
Medium-term notes, Series H 5.64 .-
Pollution control loan 3.22 3.48
Port facilities loan 3.24 3.61
Adjustable rate pollution control loan 3.59 3.75
Economic development loan 3.26 3.59
Variable rate pollution control loan 3.30 3.45
Diversified Businesses
Loans under credit agreement 5.68 6.02
Mortgage and construction loans 6.65 8.17
- --------------------------------------------------------------------------------
Note 9.
Leases
There are two types of leases--operating and capital. Capital leases qualify as
sales or purchases of property and are reported in the Consolidated Balance
Sheets. Capital leases are not material in amount. All other leases are
operating leases and are reported in the Consolidated Statements of Income. We
present information about our operating leases below.
Outgoing Lease Payments
We, as lessee, lease some facilities and equipment used in our businesses. The
lease agreements expire on various dates and have various renewal options. We
expense all lease payments associated with our regulated utility operations.
Lease expense was:
. $12.2 million in 1999,
. $10.5 million in 1998, and
. $9.5 million in 1997.
At December 31, 1999, we owed future minimum payments for long-term,
noncancelable, operating leases as follows:
Year (In millions)
- --------------------------------------------------------------------------------
2000 $ 8.2
2001 6.1
2002 4.5
2003 3.2
2004 2.4
Thereafter 9.7
- --------------------------------------------------------------------------------
Total future minimum lease payments $34.1
================================================================================
79
Note 10.
Commitments, Guarantees, and Contingencies
Commitments
We have made substantial commitments in connection with our utility construction
program for future years. In addition, our electric business has entered into
two long-term contracts for the purchase of electric generating capacity and
energy. The contracts expire in 2001 and 2013. We made payments under these
contracts of:
. $67.8 million in 1999,
. $70.7 million in 1998, and
. $65.6 million in 1997.
At December 31, 1999, we estimate our future payments for capacity and energy
that we are obligated to buy under these contracts to be:
Year (In millions)
- --------------------------------------------------------------------------------
2000 $ 69.7
2001 37.1
2002 13.9
2003 13.8
2004 13.6
Thereafter 113.4
- --------------------------------------------------------------------------------
Total estimated future payments for
capacity and energy under long-term contracts $261.5
================================================================================
Portions of these contracts are expected to be uneconomic upon the deregulation
of electric generation. Therefore, we recorded a charge and accrued a
corresponding liability based on the net present value of the excess of
estimated contract costs over the market based revenues to recover these costs
over the remaining terms of the contracts as discussed in Note 4. At December
31, 1999, the accrued portion of these contracts was $47.5 million.
Some of our diversified businesses have committed to contribute additional
capital and to make additional loans to some affiliates, joint ventures, and
partnerships in which they have an interest. At December 31, 1999, the total
amount of investment requirements committed to by our diversified businesses was
$174.2 million. This amount includes $121 million for our energy services
businesses commitment to Orion Power Holdings, Inc.
BGE and BGE Home Products & Services have agreements to sell on an ongoing basis
an undivided interest in a designated pool of customer receivables. Under the
agreements, BGE can sell up to a total of $40 million, and BGE Home Products &
Services can sell up to a total of $50 million. Under the terms of the
agreements, the buyer of the receivables has limited recourse against BGE and
has no recourse against BGE Home Products & Services. BGE and BGE Home Products
& Services have recorded reserves for credit losses. At December 31, 1999, BGE
had sold $28.2 million and BGE Home Products & Services had sold $43.3 million
of receivables under these agreements.
Guarantees
Constellation Energy has issued guarantees in an amount up to $69.2 million
related to credit facilities and contractual performance of certain of its
diversified subsidiaries. However, the actual subsidiary liabilities related to
these guarantees totaled $21.7 million at December 31, 1999.
BGE guarantees two-thirds of certain debt of Safe Harbor Water Power
Corporation. The maximum amount of our guarantee is $23 million. At December 31,
1999, Safe Harbor Water Power Corporation had outstanding debt of $20.4 million,
of which $13.6 million is guaranteed by BGE.
At December 31, 1999, our remaining diversified businesses had guaranteed
outstanding loans and letters of credit of certain power projects and real
estate projects totaling $48.8 million. Our diversified businesses also
guarantee certain other borrowings of various power projects and real estate
projects.
We assess the risk of loss from these guarantees to be minimal.
80
Environmental Matters
Clean Air
The Clean Air Act of 1990 contains two titles designed to reduce emissions of
sulfur dioxides and nitrogen oxides (NOx) from electric generating
stations--Title IV and Title I.
Title IV primarily addresses emissions of sulfur dioxides. Compliance is
required in two phases:
. Phase I became effective January 1, 1995. We met the requirements of this
phase by installing flue gas desulfurization systems, switching fuels, and
retiring some units.
. Phase II became effective January 1, 2000. We met the compliance
requirements through a combination of switching fuels and allowance
trading.
Title I addresses emissions of NOx. The Maryland Department of the Environment
(MDE) has issued regulations, effective October 18, 1999, which require up to
65% NOx emissions reductions by May 1, 2000. We have entered into a settlement
agreement with the MDE since we cannot meet this deadline. Under the terms of
the settlement agreement, BGE will install emissions reduction equipment at two
sites by May 2002. In the meantime, we are taking steps to control NOx emissions
at our generating plants.
The Environmental Protection Agency (EPA) issued a final rule in September 1998
that requires up to 85% NOx emissions reduction by 22 states including Maryland
and Pennsylvania. Maryland will meet the requirements of the rule by 2003.
Based on the MDE and EPA regulations, we currently estimate that the additional
controls needed at our generating plants to meet the MDE's 65% NOx emission
reduction requirements will cost approximately $135 million. Through December
31, 1999, we have spent approximately $51 million to meet the MDE's 65%
reduction requirements. We estimate the additional cost for EPA's 85% reduction
requirements to be approximately $35 million by 2003.
In July 1997, the EPA published new National Ambient Air Quality Standards for
very fine particulates and revised standards for ozone attainment. In 1999,
these new standards were successfully challenged in court. The EPA is expected
to appeal the 1999 court rulings to the Supreme Court. While these standards may
require increased controls at our fossil generating plants in the future,
implementation will be delayed for several years. We cannot estimate the cost of
these increased controls at this time because the states, including Maryland and
Pennsylvania, still need to determine what reductions in pollutants will be
necessary to meet the new federal standards.
Waste Disposal
The EPA and several state agencies have notified us that we are considered a
potentially responsible party with respect to the cleanup of certain
environmentally contaminated sites owned and operated by others. We cannot
estimate the cleanup costs for all of these sites.
We can, however, estimate that our current 15.43% share of the reasonably
possible cleanup costs at one of these sites, Metal Bank of America (a metal
reclaimer in Philadelphia), could be as much as $4.9 million higher than amounts
we have recorded as a liability on our Consolidated Balance Sheets. This
estimate is based on a Record of Decision issued by the EPA.
On July 12, 1999, the EPA notified us, along with nineteen other entities, that
we may be a potentially responsible party at the 68th Street Dump/Industrial
Enterprises Site, also known as the Robb Tyler Dump located in Baltimore,
Maryland. The EPA indicated that it is proceeding with plans to conduct a
remedial investigation and feasibility study. This site was proposed for listing
as a federal Superfund site in January 1999, but the listing has not been
finalized. Although our potential liability cannot be estimated, we do not
expect such liability to be material based on our records showing that we did
not send waste to the site.
Also, we are coordinating investigation of several sites where gas was
manufactured in the past. The investigation of these sites includes reviewing
possible actions to remove coal tar. In late December 1996, we signed a consent
order with the MDE that requires us to implement remedial action plans for
contamination at and around the Spring Gardens site, located in Baltimore,
Maryland. We submitted the required remedial action plans and they have been
approved by the MDE. Based on the remedial action plans, the costs we consider
to be probable to remedy the contamination are estimated to total $47 million in
nominal dollars (including inflation). We have recorded these costs as a
liability on our Consolidated Balance Sheets and have deferred these costs, net
of accumulated amortization and amounts we recovered from insurance companies,
as a regulatory asset. We discuss this further in Note 5. Through December 31,
1999, we have spent approximately $34 million for remediation at this site.
81
We are also required by accounting rules to disclose additional costs we
consider to be less likely than probable costs, but still "reasonably possible"
of being incurred at these sites. Because of the results of studies at these
sites, it is reasonably possible that these additional costs could exceed the
amount we recognized by approximately $14 million in nominal dollars ($7 million
in current dollars, plus the impact of inflation at 3.1% over a period of up to
36 years).
We do not expect the cleanup costs of the remaining sites to have a material
effect on our financial results.
Nuclear Insurance
If there were an accident or an extended outage at either unit of Calvert
Cliffs, it could have a substantial adverse financial effect on us. The primary
contingencies that would result from an incident at Calvert Cliffs could
include:
. physical damage to the plant,
. recoverability of replacement power costs, and
. our liability to third parties for property damage and bodily injury.
We have insurance policies that cover these contingencies, but the policies have
certain industry standard exclusions. Furthermore, the costs that could result
from a covered major accident or a covered extended outage at either of the
Calvert Cliffs units could exceed our insurance coverage limits.
Insurance for Calvert Cliffs and Third Party Claims
For physical damage to Calvert Cliffs, we have $2.75 billion of property
insurance from an industry mutual insurance company. If an outage at either of
the two units at Calvert Cliffs is caused by an insured physical damage loss and
lasts more than 12 weeks, we have insurance coverage for replacement power costs
up to $490.0 million per unit, provided by an industry mutual insurance company.
This amount can be reduced by up to $98.0 million per unit if an outage at both
units of the plant is caused by a single insured physical damage loss. If
accidents at any insured plants cause a shortfall of funds at the industry
mutual insurance company, all policyholders could be assessed, with our share
being up to $21.7 million.
In addition we, as well as others, could be charged for a portion of any third
party claims associated with a nuclear incident at any commercial nuclear power
plant in the country. At December 31, 1999, the limit for third party claims
from a nuclear incident is $9.34 billion under the provisions of the Price
Anderson Act. If third party claims exceed $200 million (the amount of primary
insurance), our share of the total liability for third party claims could be up
to $176.2 million per incident. That amount would be payable at a rate of $20
million per year.
Insurance for Worker Radiation Claims
As an operator of a commercial nuclear power plant in the United States, we are
required to purchase insurance to cover radiation injury claims of certain
nuclear workers. On January 1, 1998, a new insurance policy became effective for
all operators requiring coverage for current operations. Waiving the right to
make additional claims under the old policy was a condition for acceptance under
the new policy. We describe both the old and new policies below.
. Nuclear worker claims reported on or after January 1, 1998 are covered by a
new insurance policy with an annual industry aggregate limit of $200
million for radiation injury claims against all those insured by this
policy.
. All nuclear worker claims reported prior to January 1, 1998 are still
covered by the old insurance policies. Insureds under the old policies,
with no current operations, are not required to purchase the new policy
described above, and may still make claims against the old policies for the
next eight years. If radiation injury claims under these old policies
exceed the policy reserves, all policyholders could be assessed, with our
share being up to $6.3 million.
If claims under these polices exceed the coverage limits, the provisions of the
Price Anderson Act (discussed in this section) would apply.
82
Recoverability of Electric Fuel Costs
Until July 1, 2000, we will continue to recover our cost of fuel and purchased
energy through the electric fuel rate as long as the Maryland PSC finds that,
among other things, we have kept the productive capacity of our generating
plants at a reasonable level. To do this, the Maryland PSC will evaluate the
performance of our generating plants, and will determine if we used all
reasonable and cost-effective maintenance and operating control procedures.
The Maryland PSC, under the Generating Unit Performance Program, measures
annually whether we have maintained the productive capacity of our generating
plants at reasonable levels. To do this, the program uses a system-wide
generating performance target and an individual performance target for each base
load generating unit. In fuel rate hearings, actual generating performance
adjusted for planned outages will be compared first to the system-wide target.
If that target is met, it should mean that the requirements of Maryland law have
been met. If the system-wide target is not met, each unit's adjusted actual
generating performance will be compared to its individual performance target to
determine if the requirements of Maryland law have been met and, if not, to
determine the basis for possibly imposing a penalty on BGE. Even if we meet
these targets, parties to fuel rate hearings may still question whether we used
all reasonable and cost-effective procedures to try to prevent an outage. If the
Maryland PSC decides we were deficient in some way, the Maryland PSC may not
allow us to recover the cost of replacement energy.
The two units at Calvert Cliffs use the cheapest fuel. As a result, the costs of
replacement energy associated with outages at these units can be significant. We
cannot estimate the amount of replacement energy costs that could be challenged
or disallowed in future fuel rate proceedings, but such amounts could be
material.
Under the terms of the Restructuring Order, BGE's electric fuel rate clause will
be discontinued effective July 1, 2000.
We discuss competition and its impact on BGE's generation business further in
Note 4. The discontinuance of BGE's electric fuel rate clause is discussed
further in Note 1.
California Power Purchase Agreements
Constellation Power, Inc. and subsidiaries and Constellation Investments, Inc.
(whose power projects are managed by Constellation Power) have $301.8 million
invested in 14 projects that sell electricity in California under power purchase
agreements called "Interim Standard Offer No. 4" agreements. Under these
agreements, the projects supply electricity to utility companies at:
. a fixed rate for capacity and energy for the first 10 years
of the agreements, and
. a fixed rate for capacity plus a variable rate for energy based on the
utilities' avoided cost for the remaining term of the agreements.
Generally, a "capacity rate" is paid to a power plant for its availability to
supply electricity, and an "energy rate" is paid for the electricity actually
generated. "Avoided cost" generally is the cost of a utility's cheapest
next-available source of generation to service the demands on its system.
We use the term "transitioned" to describe when the 10-year periods for fixed
energy rates have expired for these power generation projects and they began
supplying electricity at variable rates. The four remaining projects that have
not transitioned will do so by December 2000.
The projects that have already transitioned to variable rates have had lower
revenues under variable rates than they did under fixed rates. Once the
remaining projects have transitioned to variable rates, we expect the revenues
from those projects also to be lower than they are under fixed rates.
We discuss the earnings for these projects in the "Diversified Businesses"
section of Management's Discussion and Analysis.
83
Note 11.
Fair Market Value of Financial Instruments
The fair value of a financial instrument represents the amount at which the
instrument could be exchanged in a current transaction between willing parties,
other than in a forced sale or liquidation. Significant differences can occur
between the fair value and carrying amount of financial instruments that are
recorded at historical amounts. We used the following methods and assumptions in
estimating fair value disclosures for financial instruments:
. Cash and cash equivalents, net accounts receivable, other current assets,
certain current liabilities, short-term borrowings, current portions of
long-term debt and preference stock, and certain deferred credits and other
liabilities: The amounts reported in the Consolidated Balance Sheets
approximate fair value.
. Investments and other assets where it was practicable to estimate fair
value: The fair value is based on quoted market prices where available.
. Fixed-rate long-term debt, and redeemable preference stock: The fair value
is based on quoted market prices where available or by discounting
remaining cash flows at current market rates. The carrying amount of
variable-rate long-term debt approximates fair value.
We show the carrying amounts and fair values of financial instruments included
in our Consolidated Balance Sheets in the following table, and we describe some
of the items separately below:
At December 31, 1999 1998
- --------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- --------------------------------------------------------------------------------
(In millions)
Investments and other
assets for which it is:
Practicable to
estimate fair value $ 313.3 $ 313.3 $ 213.0 $ 213.0
Not practicable to
estimate fair value 46.7 N/A 56.5 N/A
Fixed-rate long-term debt 2,728.9 2,637.3 2,954.7 3,076.6
Redeemable preference
stock - - 7.0 7.2
It was not practicable to estimate the fair value of investments held by our
diversified businesses in:
. several financial partnerships that invest in nonpublic debt and equity
securities, and
. several partnerships that own solar powered energy production facilities.
This is because the timing and amount of cash flows from these investments are
difficult to predict. We report these investments at their original cost in our
Consolidated Balance Sheets.
The investments in financial partnerships totaled $35.8 million at December 31,
1999 and $41.9 million at December 31, 1998, representing ownership interests up
to 10%. The total assets of all of these partnerships totaled $5.9 billion at
December 31, 1998 (which is the latest information available).
The investments in solar powered energy production facility partnerships totaled
$10.9 million at December 31, 1999 and 1998, representing ownership interests up
to 13%. The total assets of all of these partnerships totaled $31.3 million at
December 31, 1998 (which is the latest information available).
Guarantees
It was not practicable to determine the fair value of certain loan guarantees of
Constellation Energy and its subsidiaries. Constellation Energy guaranteed
outstanding debt of $16.5 million at December 31, 1999. BGE guaranteed
outstanding debt of $13.6 million at December 31, 1999 and $18.0 million at
December 31, 1998. Our diversified businesses guaranteed outstanding debt
totaling $48.8 million at December 31, 1999 and $59.7 million at December 31,
1998. We do not anticipate that we will need to fund these guarantees.
84
Note 12.
Quarterly Financial Data (Unaudited)
Our quarterly financial information has not been audited but, in management's
opinion, includes all adjustments necessary for a fair presentation. Our utility
business is seasonal in nature with the peak sales periods generally occurring
during the summer and winter months. Accordingly, comparisons among quarters of
a year may not represent overall trends and changes in operations.
1999 Quarterly Data - Constellation Energy
Earnings Earnings
Income Applicable Per Share
From to Common of Common
Revenues Operations Stock Stock
- --------------------------------------------------------------------------------
(In millions, except per-share amounts)
Quarter Ended
March 31 $ 932.3 $198.1 $ 82.8 $0.55
June 30 820.0 163.9 68.0 0.45
September 30 970.4 277.7 136.1 0.91
December 31 1,063.5 120.2 (26.8) (0.18)
- --------------------------------------------------------------------------------
Year Ended
December 31 $3,786.2 $759.9 $260.1 $1.74
================================================================================
1999 Quarterly Data - BGE
Earnings
Income Applicable
From to Common
Revenues Operations Stock
- --------------------------------------------------------------------------------
(In millions)
Quarter Ended
March 31 $ 932.3 $ 198.1 $ 82.8
June 30 669.2 140.9 57.8
September 30 756.0 283.3 151.5
December 31 670.8 82.0 (43.5)
- --------------------------------------------------------------------------------
Year Ended
December 31 $3,028.3 $704.3 $248.6
================================================================================
Constellation Energy's second quarter results include a $3.6 million after-tax
write-down of a financial investment (see Note 3).
Third quarter results include:
Constellation Energy and BGE
. $7.5 million associated with Hurricane Floyd (see the "Electric Operations
and Maintenance Expenses" section of Management's Discussion and Analysis),
. a $37.5 million deferral of revenues collected associated with the
deregulation of our electric generation business (see Note 5),
Constellation Energy
. a $17.3 million after-tax write-down of a financial investment (see Note 3),
. a $6.7 million after-tax write-off of a power project (see Note 3), and
. a $3.4 million after-tax write-down of certain senior-living facilities
(see Note 2).
Fourth quarter results include:
Constellation Energy and BGE
. a $66.3 million extraordinary charge associated with the Restructuring
Order (see Note 4),
. the recognition of the $37.5 million of revenues that were deferred in the
third quarter (see above),
. $75 million in amortization expense for the reduction of our generation
plants associated with the Restructuring Order (see the "Electric
Depreciation and Amortization Expense" section of Management's Discussion
and Analysis),
Constellation Energy
. a $4.9 million after-tax gain on a financial investment (see Note 3),
. $12.0 million after-tax write-downs of certain power projects (see Note 3),
and
. a $2.4 million after-tax write-down of certain senior-living facilities
(see Note 2).
1998 Quarterly Data - Constellation Energy and BGE
Earnings Earnings
Income Applicable Per Share
From to Common of Common
Revenues Operations Stock Stock
- --------------------------------------------------------------------------------
(In millions, except per-share amounts)
Quarter Ended
March 31 $ 866.1 $ 183.4 $ 74.4 $0.50
June 30 767.6 156.2 57.4 0.39
September 30 934.0 320.4 160.9 1.08
December 31 790.4 81.1 13.2 0.09
- --------------------------------------------------------------------------------
Year Ended
December 31 $3,358.1 $741.1 $305.9 $2.06
- --------------------------------------------------------------------------------
Third quarter results include a $10.4 million after-tax gain for earnings in a
partnership (see Note 3).
Fourth quarter results include:
. a $15.4 million after-tax write-off of a real estate investment (see Note
3), and
. a $5.5 million after-tax write-off of an energy services investment (see
the "Other Energy Services" section of Management's Discussion and
Analysis).
The sum of the quarterly earnings per share amounts may not equal the total for
the year due to the effects of rounding.
85
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
- --------------------------------------------------------------------------------
PART III
BGE meets the conditions set forth in General Instruction I(1)(a) and (b) of
Form 10-K for a reduced disclosure format. Accordingly, all items in this
section related to BGE are not presented.
Item 10. Directors and Executive Officers of the Registrant
The information required by this item with respect to directors is set forth on
pages 4 through 8 under "Election of Constellation Energy Directors" in the
Proxy Statement and is incorporated herein by reference.
The information required by this item with respect to executive officers of
Constellation Energy Group, pursuant to instruction 3 of paragraph (b) of Item
401 of Regulation S-K, is set forth in Item 4 of Part I of this Form 10-K under
"Executive Officers of the Registrant".
Item 11. Executive Compensation
The information required by this item is set forth on page 7 under "Directors'
Compensation," on pages 7 though 8 under "Compensation Committee Interlocks and
Insider Participation," on pages 10 through 13 under "Executive Compensation,"
on page 14 under "Common Stock Performance Graph," and on pages 14 through 17
under "Report of Committee on Management on Executive Compensation" in the
Proxy Statement and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The information required by this item regarding security ownership of certain
beneficial owners and management is set forth on page 9 under "Security
Ownership" in the Proxy Statement and is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions
The information required by this item is set forth on pages 7 and 8 under
"Certain Relationships and Transactions", and "Compensation Committee
Interlocks and Insider Participation" in the Proxy Statement and is
incorporated herein by reference.
86
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) The following documents are filed as a part of this Report:
1. Financial Statements:
Report of Independent Accountants dated January 19, 2000 of
PricewaterhouseCoopers LLP
Consolidated Statements of Income--Constellation Energy Group for three years
ended December 31, 1999
Consolidated Statements of Comprehensive Income--Constellation Energy Group
for three years ended December 31, 1999
Consolidated Balance Sheets--Constellation Energy Group at December 31, 1999
and December 31, 1998
Consolidated Statements of Cash Flows--Constellation Energy Group for three
years ended December 31, 1999
Consolidated Statements of Common Shareholders' Equity--Constellation Energy
Group for three years ended December 31, 1999
Consolidated Statements of Capitalization--Constellation Energy Group at
December 31, 1999 and December 31, 1998
Consolidated Statements of Income Taxes--Constellation Energy Group for three
years ended December 31, 1999
Consolidated Statements of Income--Baltimore Gas and Electric Company for
three years ended December 31, 1999
Consolidated Statements of Comprehensive Income--Baltimore Gas and Electric
Company for three years ended December 31, 1999
Consolidated Balance Sheets--Baltimore Gas and Electric Company at December
31, 1999 and December 31, 1998
Consolidated Statements of Cash Flows--Baltimore Gas and Electric Company for
three years ended December 31, 1999
Notes to Consolidated Financial Statements
2. Financial Statement Schedules:
Schedule II--Valuation and Qualifying Accounts
Schedules other than Schedule II are omitted as not applicable or not
required.
3. Exhibits Required by Item 601 of Regulation S-K.
Exhibit
Number
- -------
*2 -- Agreement and Plan of Share Exchange between Baltimore Gas and
Electric Company and Constellation Energy Group, Inc. dated as of
February 19, 1999. (Designated as Exhibit No. 2 in Form S-4 dated
March 3, 1999, File No. 33-64799.)
*3(a) -- Articles of Amendment and Restatement of the Charter of Constellation
Energy Group, Inc. as of April 30, 1999. (Designated as Exhibit No.
99.2 in Form 8-K dated April 30, 1999, File No. 1-1910.)
*3(b) -- Articles Supplementary to the Charter of Constellation Energy Group,
Inc., as of July 19, 1999. (Designated as Exhibit No. 3(a) in Form
10-Q dated August 13, 1999, File No. 1-12869 and 1-1910.)
3(c) -- Certificate of Correction to the Charter of Constellation Energy
Group, Inc. as of September 13, 1999.
*3(d) -- Bylaws of Constellation Energy Group, Inc. amended to July 16, 1999.
(Designated as Exhibit No. 3(b) in Form 10-Q dated August 13, 1999,
File No. 1-12869 and 1-1910.)
*3(e) -- Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit
No. 3 in Form 10-Q dated November 14, 1996, File No. 1-1910.)
3(f) -- By-Laws of BGE, as amended to April 30, 1999.
87
*4(a) -- Indenture between Constellation Energy Group, Inc. and the Bank of
New York, Trustee dated as of March 24, 1999. (Designated as Exhibit
No. 4(a) in Form S-3 dated March 29, 1999, File No. 333-75217.)
*4(b) -- Supplemental Indenture between BGE and Bankers Trust Company, as
Trustee, dated as of June 20, 1995, supplementing, amending and
restating Deed of Trust dated February 1, 1919. (Designated as
Exhibit No. 4 in Form 10-Q dated August 11, 1995, File No. 1-1910.);
and the following Supplemental Indentures between BGE and Bankers
Trust Company, Trustee:
Designated In
-------------------------------
Exhibit
Dated File No. Number
----- -------- -------
*July 15, 1977 2-59772 2-3
(3 Indentures)
*August 15, 1991 33-45259 (Form S-3 Registration) 4(a)(i)
*January 15, 1992 33-45259 (Form S-3 Registration) 4(a)(ii)
*July 1, 1992 1-1910 (Form 8-K Report for January 29, 1993) 4(a)
*February 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(i)
*March 1, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(ii)
*March 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(iii)
*April 15, 1993 1-1910 (Form 10-Q dated May 13, 1993) 4
*July 1, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(a)
*July 15, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(b)
*October 15, 1993 1-1910 (Form 10-Q dated November 12, 1993) 4
*June 15, 1996 1-1910 (Form 10-Q dated August 13, 1996) 4
*4(c) -- Indenture dated July 1, 1985, between BGE and The Bank of New York
(Successor to Mercantile-Safe Deposit and Trust Company), Trustee.
(Designated in Registration File No. 2-98443 as Exhibit 4(a)); as
supplemented by Supplemental Indentures dated as of October 1, 1987
(Designated in Form 8-K, dated November 13, 1987, File No. 1-1910 as
Exhibit 4(a)) and as of January 26, 1993 (Designated in Form 8-K,
dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).)
*4(d) -- Form of Subordinated Indenture between the Company and The Bank of
New York, as Trustee in connection with the issuance of the Junior
Subordinated Debentures (Designated as Exhibit 4(d) in Form S-3 dated
May 28, 1998, File No. 333-53767).
*4(e) -- Form of Supplemental Indenture between the Company and The Bank of
New York, as Trustee in connection with the issuances of the Junior
Subordinated Debentures (Designated as Exhibit 4(e) in Form S-3 dated
May 28, 1998, File No. 333-53767).
*4(f) -- Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) in
Form S-3 dated May 28, 1998, File No. 333-53767).
*4(g) -- Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) in
Form S-3 dated May 28, 1998, File No. 333-53767).
*4(h) -- Form of Amended and Restated Declaration of Trust (including Form of
Preferred Security) (Designated as Exhibit 4(c) in Form S-3 dated May
28, 1998, File No. 333-53767).
10(a) -- Constellation Energy Group, Inc. Executive Benefits Plan, as amended
and restated, with Summary of New Executive Pension Provision.
10(b) -- Executive Annual Incentive Plan of Constellation Energy Group, Inc.,
as amended and restated.
*10(c) -- Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as
amended and restated. (Designated as Exhibit No. 10(a) in Form 10-Q
dated November 12, 1999, File Nos. 1-12869 and 1-1910.)
88
*10(d) -- Constellation Energy Group, Inc. Nonqualified Deferred Compensation
Plan, as amended and restated. (Designated as Exhibit No. 10(b) in
Form 10-Q dated November 12, 1999, File Nos. 1-12869 and 1-1910.)
*10(e) -- Constellation Energy Group, Inc. Deferred Compensation Plan for Non-
Employee Directors. (Designated as Exhibit No. 10(a) in Form 10-Q
dated May 14, 1999, File Nos. 1-12869 and 1-1910.)
*10(f) -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee
Directors, as amended and restated. (Designated as Exhibit No. 10(m)
in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-1910.)
(Terminated effective August 1, 1997.)
10(g) -- Summary of severance arrangement for a Named Executive Officer.
*10(h) -- Grantor Trust Agreement Dated as of April 30, 1999 between
Constellation Energy Group, Inc. and Citibank, N.A. (Designated as
Exhibit No. 10(g) in Form 10-Q dated May 14, 1999, File Nos. 1-12869
and 1-1910.)
*10(i) -- Form of Severance Agreement between Constellation Energy Group, Inc.
and seven key employees. (Designated as Exhibit No. 10(j) in Form 10-
Q dated May 14, 1999, File Nos. 1-12869 and 1-1910.)
*10(j) -- Summary of enhanced retirement benefits for a named executive
officer. (Designated as Exhibit No. 10(l) in Form 10-Q dated May 14,
1999, File Nos. 1-12869 and 1-1910.)
*10(k) -- Grantor Trust Agreement dated as of April 30, 1999 between
Constellation Energy Group, Inc. and T. Rowe Price Trust Company.
(Designated as Exhibit No. 10(e) in Form 10-Q dated May 14, 1999,
File Nos. 1-12869 and 1-1910.)
*10(l) -- Constellation Energy Group, Inc. Long-Term Incentive Plan.
(Designated as Exhibit No. 10(b) in Form 10-Q dated May 14, 1999,
File Nos. 1-12869 and 1-1910.)
12(a) -- Constellation Energy Group, Inc. Computation of Ratio of Earnings to
Fixed Charges.
12(b) -- Baltimore Gas and Electric Company Computation of Ratio of Earnings
to Fixed Charges and Computation of Ratio of Earnings to Combined
Fixed Charges and Preferred and Preference Dividend Requirements.
21 -- Subsidiaries of the Registrant.
23 -- Consent of PricewaterhouseCoopers LLP, Independent Accountants.
27(a) -- Constellation Energy Group, Inc. Financial Data Schedule.
27(b) -- Baltimore Gas and Electric Company Financial Data Schedule.
*99(a) -- BGE 1999 Pro Forma Financial Statement for Generation Asset
Transfer. (Designated as Exhibit No. 99 in Form 8-K dated March 17,
2000 File No. 1-12869 and 1-1910.)
- --------
* Incorporated by Reference.
(b) Reports on Form 8-K:
Date Filed Item Reported
---------- -------------
November 18, 1999 Item 5. Other Events
89
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES AND BALTIMORE GAS AND
ELECTRIC COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
Column A Column B Column C Column D Column E
-------- --------- ------------------- -------------- --------
Additions
-------------------
Balance Charged Charged to Balance
at to costs other at end
beginning and accounts-- (Deductions)-- of
Description of period expenses describe describe period
- ----------- --------- -------- ---------- -------------- --------
(in millions)
Reserves deducted in the
Balance Sheet from the
assets to which they
apply:
Constellation Energy
Accumulated Provision
for Uncollectibles
1999.................. $35.4 $21.5 $ -- $(22.1)(A) $ 34.8
1998.................. 24.1 28.0 -- (16.7)(A) 35.4
1997.................. 18.0 34.4 -- (28.3)(A) 24.1
Valuation Allowance --
Net unrealized (gain)
loss on available for
sale securities
1999.................. (9.4) -- 9.6 (B) -- 0.2
1998.................. (7.6) -- (1.8)(B) -- (9.4)
1997.................. (8.8) -- 1.2 (B) -- (7.6)
Assets from trading
activities reserves
1999.................. (0.6) -- (26.9)(C) -- (27.5)
1998.................. -- -- (0.6)(C) -- (0.6)
BGE
Accumulated Provision
for Uncollectibles
1999.................. 35.4 17.6 -- (40.0)(D) 13.0
1998.................. 24.1 28.0 -- (16.7)(A) 35.4
1997.................. 18.0 34.4 -- (28.3)(A) 24.1
Valuation Allowance --
Net unrealized (gain)
loss on available for
sale securities
1999.................. (9.4) -- (5.3)(B) 14.7(E) --
1998.................. (7.6) -- (1.8)(B) -- (9.4)
1997.................. (8.8) -- 1.2 (B) -- (7.6)
Constellation Energy and
BGE
Valuation Allowance --
Net unrealized (gain)
loss on nuclear
decommissioning trust
fund
1999.................. (23.9) -- (16.6)(F) -- (40.5)
1998.................. (10.0) -- (13.9)(F) -- (23.9)
1997.................. (3.7) -- (6.3)(F) -- (10.0)
Provision for possible
disallowance of
replacement energy
costs
1999.................. -- -- -- -- --
1998.................. -- -- -- -- --
1997.................. 118.0 -- -- (118.0)(G) --
- --------
(A) Represents principally net amounts charged off as uncollectible.
(B) Represents net unrealized (gains)/losses (credited)/charged to accumulated
other comprehensive income.
(C) Represents a reserve from assets for energy trading activities charged to
revenues.
(D) Represents approximately $17 million charged off as uncollectible and
approximately $23 million transferred from BGE to Constellation Energy as a
result of the formation of the holding company.
(E) Represents amount transferred from BGE to Constellation Energy as a result
of the formation of the holding company.
(F) Represents net unrealized gains credited to accumulated depreciation.
(G) Represents removal of a reserve based on actual disallowance of replacement
energy costs.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
90
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, Constellation Energy Group, Inc., the Registrant, has duly caused
this Report to be signed on its behalf by the undersigned, thereunto duly
authorized.
CONSTELLATION ENERGY GROUP, INC.
(Registrant)
Date: March 20, 2000 By /s/ C. H. Poindexter
-------------------------------------
C. H. Poindexter
Chairman of the Board, President,
and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below by the following persons on behalf of
Constellation Energy Group, Inc., the Registrant, and in the capacities and on
the dates indicated.
Signature Title Date
--------- ----- ----
Principal executive officer and director:
By /s/ C. H. Poindexter Chairman of the Board, March 20, 2000
-----------------------------------
C. H. Poindexter President, Chief
Executive Officer, and
Director
Principal financial and accounting officer:
By /s/ D. A. Brune Vice President, Chief March 20, 2000
-----------------------------------
D. A. Brune Financial Officer and
Secretary
Directors:
/s/ H. F. Baldwin Director March 20, 2000
-----------------------------------
H. F. Baldwin
/s/ D. L. Becker Director March 20, 2000
-----------------------------------
D. L. Becker
/s/ J. T. Brady Director March 20, 2000
-----------------------------------
J. T. Brady
/s/ B. B. Byron Director March 20, 2000
-----------------------------------
B. B. Byron
/s/ J. O. Cole Director March 20, 2000
-----------------------------------
J. O. Cole
/s/ D. A. Colussy Director March 20, 2000
-----------------------------------
D. A. Colussy
/s/ E. A. Crooke Director March 20, 2000
-----------------------------------
E. A. Crooke
/s/ J. R. Curtiss Director March 20, 2000
-----------------------------------
J. R. Curtiss
/s/ R. W. Gale Director March 20, 2000
-----------------------------------
R. W. Gale
/s/ J. W. Geckle Director March 20, 2000
-----------------------------------
J. W. Geckle
91
Signature Title Date
--------- ----- ----
/s/ F. A. Hrabowski III Director March 20, 2000
- ---------------------------------------
F. A. Hrabowski III
/s/ N. Lampton Director March 20, 2000
- ---------------------------------------
N. Lampton
/s/ C. R. Larson Director March 20, 2000
- ---------------------------------------
C. R. Larson
/s/ G. V. McGowan Director March 20, 2000
- ---------------------------------------
G. V. McGowan
/s/ G. L. Russell, Jr. Director March 20, 2000
- ---------------------------------------
G. L. Russell, Jr.
/s/ M. A. Shattuck, III Director March 20, 2000
- ---------------------------------------
M. A. Shattuck, III
/s/ M. D. Sullivan Director March 20, 2000
- ---------------------------------------
M. D. Sullivan
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, Baltimore Gas and Electric Company, the Registrant, has duly
caused this Report to be signed on its behalf by the undersigned, thereunto
duly authorized.
BALTIMORE GAS AND ELECTRIC COMPANY
(Registrant)
Date: March 20, 2000 By /s/ C. H. Poindexter
-------------------------------------
C. H. Poindexter
Chairman of the Board, President,
and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below by the following persons on behalf of Baltimore
Gas and Electric Company, the Registrant, and in the capacities and on the
dates indicated.
Signature Title Date
--------- ----- ----
Principal executive officer and director:
By /s/ C. H. Poindexter Chairman of the Board, March 20, 2000
-----------------------------------
C. H. Poindexter President, Chief
Executive Officer, and
Director
Principal financial and accounting officer and director:
By /s/ D. A. Brune Vice President, Chief March 20, 2000
-----------------------------------
D. A. Brune Financial Officer,
Secretary and Director
Directors:
/s/ F. O. Heintz Director March 20, 2000
-----------------------------------
F. O. Heintz
/s/ R. E. Denton Director March 20, 2000
-----------------------------------
R. E. Denton
/s/ T. F. Brady Director March 20, 2000
-----------------------------------
T. F. Brady
92
EXHIBIT INDEX
Exhibit
Number
- -------
*2 -- Agreement and Plan of Share Exchange between Baltimore Gas and
Electric Company and Constellation Energy Group, Inc. dated as of
February 19, 1999. (Designated as Exhibit No. 2 in Form S-4 dated
March 3, 1999, File No. 33-64799.)
*3(a) -- Articles of Amendment and Restatement of the Charter of Constellation
Energy Group, Inc. as of April 30, 1999. (Designated as Exhibit No.
99.2 in Form 8-K dated April 30, 1999, File No. 1-1910.)
*3(b) -- Articles Supplementary to the Charter of Constellation Energy Group,
Inc., as of July 19, 1999. 3(c)--Certificate of Correction to the
Charter of Constellation Energy Group, Inc. as of September 13, 1999.
(Designated as Exhibit No. 3(a) in Form 10-Q dated August 13, 1999,
File No. 1-12869 and 1-1910.)
3(c) -- Certificate of Correction to the Charter of Constellation Energy
Group, Inc. as of September 13, 1999.
*3(d) -- Bylaws of Constellation Energy Group, Inc. amended to July 16, 1999.
(Designated as Exhibit No. 3(b) in Form 10-Q dated August 13, 1999,
File No. 1-12869 and 1-1910.)
*3(e) -- Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit
No. 3 in Form 10-Q dated November 14, 1996, File No. 1-1910.)
3(f) -- By-Laws of BGE, as amended to April 30, 1999.
*4(a) -- Indenture between Constellation Energy Group, Inc. and the Bank of New
York, Trustee dated as of March 24, 1999. (Designated as Exhibit No.
4(a) in Form S-3 dated March 29, 1999, File No. 333-75217.)
*4(b) -- Supplemental Indenture between BGE and Bankers Trust Company, as
Trustee, dated as of June 20, 1995, supplementing, amending and
restating Deed of Trust dated February 1, 1919. (Designated as
Exhibit No. 4 in Form 10-Q dated August 11, 1995, File No. 1-1910.);
and the following Supplemental Indentures between BGE and Bankers
Trust Company, Trustee:
Designated In
-------------------------------
Exhibit
Dated File No. Number
----- -------- -------
*July 15, 1977 2-59772 2-3
(3 Indentures)
*August 15, 1991 33-45259 (Form S-3 Registration) 4(a)(i)
*January 15, 1992 33-45259 (Form S-3 Registration) 4(a)(ii)
*July 1, 1992 1-1910 (Form 8-K Report for January 29, 1993) 4(a)
*February 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(i)
*March 1, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(ii)
*March 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(iii)
*April 15, 1993 1-1910 (Form 10-Q dated May 13, 1993) 4
*July 1, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(a)
*July 15, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(b)
*October 15, 1993 1-1910 (Form 10-Q dated November 12, 1993) 4
*June 15, 1996 1-1910 (Form 10-Q dated August 13, 1996) 4
*4(c) -- Indenture dated July 1, 1985, between BGE and The Bank of New York
(Successor to Mercantile-Safe Deposit and Trust Company), Trustee.
(Designated in Registration File No. 2-98443 as Exhibit 4(a)); as
supplemented by Supplemental Indentures dated as of October 1, 1987
(Designated in Form 8-K, dated November 13, 1987, File No. 1-1910 as
Exhibit 4(a)) and as of January 26, 1993 (Designated in Form 8-K,
dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).)
93
*4(d) -- Form of Subordinated Indenture between the Company and The Bank of
New York, as Trustee in connection with the issuance of the Junior
Subordinated Debentures (Designated as Exhibit 4(d) in Form S-3
dated May 28, 1998, File No. 333-53767).
*4(e) -- Form of Supplemental Indenture between the Company and The Bank of
New York, as Trustee in connection with the issuances of the Junior
Subordinated Debentures (Designated as Exhibit 4(e) in Form S-3
dated May 28, 1998, File No. 333-53767).
*4(f) -- Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) in
Form S-3 dated May 28, 1998, File No. 333-53767).
*4(g) -- Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) in
Form S-3 dated May 28, 1998, File No. 333-53767).
*4(h) -- Form of Amended and Restated Declaration of Trust (including Form of
Preferred Security) (Designated as Exhibit 4(c) in Form S-3 dated May
28, 1998, File No. 333-53767).
10(a) -- Constellation Energy Group, Inc. Executive Benefits Plan, as amended
and restated, with Summary of New Executive Pension Provision.
10(b) -- Executive Annual Incentive Plan of Constellation Energy Group, Inc.,
as amended and restated.
*10(c) -- Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as
amended and restated. (Designated as Exhibit No. 10(a) in Form 10-Q
dated November 12, 1999, File Nos. 1-12869 and 1-1910.)
*10(d) -- Constellation Energy Group, Inc. Nonqualified Deferred Compensation
Plan, as amended and restated. (Designated as Exhibit No. 10(b) in
Form 10-Q dated November 12, 1999, File Nos. 1-12869 and 1-1910.)
*10(e) -- Constellation Energy Group, Inc. Deferred Compensation Plan for Non-
Employee Directors. (Designated as Exhibit No. 10(a) in Form 10-Q
dated May 14, 1999, File Nos. 1-12869 and 1-1910.)
*10(f) -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee
Directors, as amended and restated. (Designated as Exhibit No. 10(m)
in Form 10-Q dated May 14, 1999, File Nos. 1-12869 and 1-1910.)
(Terminated effective August 1, 1997.)
10(g) -- Summary of severance arrangement for a Named Executive Officer.
*10(h) -- Grantor Trust Agreement Dated as of April 30, 1999 between
Constellation Energy Group, Inc. and Citibank, N.A. (Designated as
Exhibit No. 10(g) in Form 10-Q dated May 14, 1999, File Nos. 1-12869
and 1-1910.)
*10(i) -- Form of Severance Agreement between Constellation Energy Group, Inc.
and seven key employees. (Designated as Exhibit No. 10(j) in Form 10-
Q dated May 14, 1999, File Nos. 1-12869 and 1-1910.)
*10(j) -- Summary of enhanced retirement benefits for a named executive
officer. (Designated as Exhibit No. 10(l) in Form 10-Q dated May 14,
1999, File Nos. 1-12869 and 1-1910.)
*10(k) -- Grantor Trust Agreement dated as of April 30, 1999 between
Constellation Energy Group, Inc. and T. Rowe Price Trust Company.
(Designated as Exhibit No. 10(e) in Form 10-Q dated May 14, 1999,
File Nos. 1-12869 and 1-1910.)
*10(l) -- Constellation Energy Group, Inc. Long-Term Incentive Plan.
(Designated as Exhibit No. 10(b) in Form 10-Q dated May 14, 1999,
File Nos. 1-12869 and 1-1910.)
12(a) -- Constellation Energy Group, Inc. Computation of Ratio of Earnings to
Fixed Charges.
12(b) -- Baltimore Gas and Electric Company Computation of Ratio of Earnings
to Fixed Charges and Computation of Ratio of Earnings to Combined
Fixed Charges and Preferred and Preference Dividend Requirements.
94
21 -- Subsidiaries of the Registrant.
23 -- Consent of PricewaterhouseCoopers LLP, Independent Accountants.
27(a) -- Constellation Energy Group, Inc. Financial Data Schedule.
27(b) -- Baltimore Gas and Electric Company Financial Data Schedule.
*99(a) -- BGE 1999 Pro Forma Financial Statement for Generation Asset
Transfer. (Designated as Exhibit No. 99 in Form 8-K dated March 17,
2000 File No. 1-12869 and 1-1910.)
- --------
* Incorporated by Reference.
(b) Reports on Form 8-K:
Date Filed Item Reported
---------- -------------
November 18, 1999 Item 5. Other Events
95