<PAGE>
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): February 15, 2000
<TABLE>
<CAPTION>
Commission IRS Employer
File Number Exact name of registrant as specified in its charter Identification No.
- ----------- ---------------------------------------------------- ------------------
<S> <C> <C>
1-12869 CONSTELLATION ENERGY GROUP, INC. 52-1964611
1-1910 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210
</TABLE>
Maryland
------------------------------------------------------------------
(State or other jurisdiction of incorporation for each registrant)
250 W. Pratt Street, Baltimore, Maryland 21201
--------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
Registrants' telephone number, including area code: (410) 234-5000
39 W. Lexington Street, Baltimore, Maryland 21201
-------------------------------------------------------------
(Former name or former address, if changed since last report)
<PAGE>
ITEM 5. Other Events
- --------------------
The following financial information for the Company for the year ended December
31, 1999 is set forth in this Form 8-K:
Selected Financial Data -- Constellation Energy Group, Inc. and Subsidiaries
Selected Financial Data -- Baltimore Gas and Electric Company and Subsidiaries
Management's Discussion and Analysis of Financial Condition and Results of
Operations
Forward Looking Statements
Report of Management
Report of Independent Accountants
Financial Statements
Constellation Energy Group, Inc. and Subsidiaries
-------------------------------------------------
Consolidated Statements of Income
Consolidated Statements of Comprehensive Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Consolidated Statements of Common Shareholders' Equity
Consolidated Statements of Capitalization
Consolidated Statements of Income Taxes
Baltimore Gas and Electric Company and Subsidiaries
---------------------------------------------------
Consolidated Statements of Income
Consolidated Statements of Comprehensive Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
2
<PAGE>
ITEM 7. Financial Statements and Exhibits
- -----------------------------------------
(c) Exhibit No. 12(a) Constellation Energy Group, Inc.
Computation of Ratio of Earnings to
Fixed Charges.
Exhibit No. 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.
Exhibit No. 23 Consent of PricewaterhouseCoopers LLP,
Independent Accountants.
Exhibit No. 27(a) Constellation Energy Group, Inc.
Financial Data Schedule.
Exhibit No. 27(b) Baltimore Gas and Electric Company
Financial Data Schedule.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each
registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
CONSTELLATION ENERGY GROUP, INC.
----------------------------------
(Registrant)
BALTIMORE GAS AND ELECTRIC COMPANY
----------------------------------
(Registrant)
Date: February 15, 2000 /s/ David A. Brune
----------------------------------
David A. Brune, Vice President on behalf of each
Registrant and as Principal Financial Officer of each Registrant
3
<PAGE>
SELECTED FINANCIAL DATA - CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
<TABLE>
<CAPTION>
1999 1998 1997 1996 1995
- ----------------------------------------------------------------------------------------------------------------
(Dollar amounts in millions, except per share amounts)
<S> <C> <C> <C> <C> <C>
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
</TABLE>
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
4
<PAGE>
SELECTED FINANCIAL DATA - BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
<TABLE>
<CAPTION>
1999 1998 1997 1996 1995
- ----------------------------------------------------------------------------------------------------------
(Dollar amounts in millions, except per share amounts)
<S> <C> <C> <C> <C> <C>
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
</TABLE>
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
5
<PAGE>
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.
6
<PAGE>
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 anticipation of lower electric utility revenues. 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 condition 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
7
<PAGE>
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 electric fuel 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, 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 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. This matter is
pending before the court.
Environmental and Legal Matters
- -------------------------------
You will find details of our environmental matters in Note 10 and in our most
recent Annual Report on Form 10-K under Item 1. Business--Environmental Matters.
You will find details of our legal matters in our most recent Annual Report on
Form 10-K 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.
8
<PAGE>
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.
9
<PAGE>
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 through June 30, 2004.
. 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
10
<PAGE>
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
above, 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 Rate" 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.
11
<PAGE>
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.
<TABLE>
<CAPTION>
30-year
1999 1998 average
- -------------------------------------------------------------------------
<S> <C> <C> <C>
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)%
</TABLE>
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
- ---------------------------------------------------
<TABLE>
<CAPTION>
1999 1998 1997
<S> <C> <C> <C>
- ---------------------------------------------------------------------
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
=====================================================================
</TABLE>
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.
12
<PAGE>
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 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.
13
<PAGE>
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.
14
<PAGE>
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.
15
<PAGE>
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.
16
<PAGE>
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 in our most recent Annual Report on Form
10-K 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 businesses 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.
17
<PAGE>
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 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.
18
<PAGE>
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.
19
<PAGE>
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.
20
<PAGE>
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 Debts A A2 A+
Trust Originated
Preferred Securities
and Preference Stock A- "a2" A
21
<PAGE>
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.
<TABLE>
<CAPTION>
1997 1998 1999 2000 2001 2002
- --------------------------------------------------------------------------------------------------------------------------------
(In millions)
<S> <C> <C> <C> <C> <C> <C>
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
================================================================================================================================
</TABLE>
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.
22
<PAGE>
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.
23
<PAGE>
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 Interests Rate Detail by Contractual Maturity Date
- -------------------------------------------------------------------------
<TABLE>
<CAPTION>
Fair value at
2000 2001 2002 2003 2004 Thereafter Total Dec 31, 1999
- --------------------------------------------------------------------------------------------------------------------------------
(In millions)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
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%
</TABLE>
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.
24
<PAGE>
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.
- --------------------------------------------------------------------------------
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 issued by the Maryland PSC,
. commodity price risk,
. operating our currently regulated generating 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, and
. increased financial requirements of our nonregulated subsidiaries.
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 SEC for more information on these factors.
These forward looking statements represent our estimates and assumptions only as
of the date of this report.
25
<PAGE>
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 accompanying consolidated balance sheets and the related
consolidated statements of income, comprehensive income, cash flows, common
shareholders' equity, capitalization and income taxes present fairly, in all
material respects, the financial position of Constellation Energy Group, Inc.
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, and the accompanying consolidated balance sheets and the
related consolidated statements of income, comprehensive income and cash flows
present fairly, in all material respects, the financial position 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. These financial statements are the
responsibility of the Companies' management; our responsibility is to express an
opinion on these financial statements 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 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
26
<PAGE>
Consolidated Statements of Income - Constellation Energy Group, Inc. and
Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31, 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------
(In millions, except per share amounts)
<S> <C> <C> <C>
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
===================================================================================================================
<CAPTION>
Consolidated Statements of Comprehensive Income - Constellation Energy Group, Inc. and Subsidiaries
Year Ended December 31, 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------
(In millions)
<S> <C> <C> <C>
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
===================================================================================================================
</TABLE>
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
27
<PAGE>
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.
28
<PAGE>
Consolidated Balance Sheets - Constellation Energy Group Inc. and Subsidiaries
<TABLE>
<CAPTION>
At December 31, 1999 1998
- ---------------------------------------------------------------------------------------------------------------
(In millions)
<S> <C> <C>
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
===============================================================================================================
</TABLE>
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
29
<PAGE>
Consolidated Statements of Cash Flows - Constellation Energy Group, Inc. and
Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31, 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------------------------
(In millions)
<S> <C> <C> <C>
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
</TABLE>
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.
30
<PAGE>
Consolidated Statements of Common Shareholders' Equity - Constellation Energy
Group Inc. and Subsidiaries
<TABLE>
<CAPTION>
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)
<S> <C> <C> <C> <C> <C>
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
===========================================================================================================================
</TABLE>
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
31
<PAGE>
Consolidated Statements of Capitalization - Constellation Energy Group, Inc. and
Subsidiaries
<TABLE>
<CAPTION>
At December 31, 1999 1998
- ----------------------------------------------------------------------------------------------------------------------
(In millions)
<S> <C> <C>
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% deferrable interest subordinated
debentures due June 30, 2038 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
- ----------------------------------------------------------------------------------------------------------------------
</TABLE>
continued on next page
See Notes to Consolidated Financial Statements.
32
<PAGE>
Consolidated Statements of Capitalization - Constellation Energy Group, Inc. and
Subsidiaries
<TABLE>
<CAPTION>
At December 31, 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------
(In millions)
<S> <C> <C>
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
=============================================================================================================================
</TABLE>
See Notes to Consolidated Financial Statements.
33
<PAGE>
Consolidated Statements of Income Taxes - Constellation Energy Group, Inc. and
Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31, 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------------------
(Dollar amounts in millions)
<S> <C> <C> <C>
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)
<S> <C> <C>
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
===================================================================================================================
</TABLE>
See Notes to Consolidated Financial Statements.
Certain prior year amounts have been reclassified to confirm with the current
year's presentation.
34
<PAGE>
Consolidated Statements of Income - Baltimore Gas and Electric Company and
Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31, 1999 1998 1997
- -------------------------------------------------------------------------------------------------------
(In millions, except per share amounts)
<S> <C> <C> <C>
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
=======================================================================================================
</TABLE>
Consolidated Statements of Comprehensive Income - Baltimore Gas and
Electric Company and Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31, 1999 1998 1997
- -------------------------------------------------------------------------------------------------------
(In millions, except per share amounts)
<S> <C> <C> <C>
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
=======================================================================================================
</TABLE>
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
35
<PAGE>
<TABLE>
<CAPTION>
Consolidated Balance Sheets - Baltimore Gas and Electric Company and
Subsidiaries
At December 31, 1999 1998
- ------------------------------------------------------------------------------------------
(In millions)
<S> <C> <C>
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
==========================================================================================
</TABLE>
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
36
<PAGE>
<TABLE>
<CAPTION>
Consolidated Balance Sheets - Baltimore Gas and Electric Company and
Subsidiaries
At December 31, 1999 1998
- ------------------------------------------------------------------------------------------
(In millions)
<S> <C> <C>
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 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
==========================================================================================
</TABLE>
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
37
<PAGE>
Consolidated Statements of Cash Flows - Baltimore Gas and Electric Company and
Subsidiaries
<TABLE>
<CAPTION>
Year Ended December 31, 1999 1998 1997
- -------------------------------------------------------------------------------------------------------------------
(In millions)
<S> <C> <C> <C>
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.
</TABLE>
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
38
<PAGE>
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,
. 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 to determine how the transition plan will affect the
deregulated portion of the business. Additionally, a company would continue to
recognize regulated assets and liabilities in the Consolidated Balance Sheets to
the extent that the transition plan provides for their recovery.
39
<PAGE>
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 4.
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.
40
<PAGE>
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.
41
<PAGE>
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,
. senior-living facilities, 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.
42
<PAGE>
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.
43
<PAGE>
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.
44
<PAGE>
<TABLE>
<CAPTION>
Energy Other Unallocated
Electric Gas Services Diversified Corporate
Business Business Businesses Businesses Items (a) Eliminations Consolidated
- ------------------------------------------------------------------------------------------------------------------------------------
(In millions)
<S> <C> <C> <C> <C> <C> <C> <C>
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
</TABLE>
(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.
45
<PAGE>
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.
46
<PAGE>
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:
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
===========================================================
47
<PAGE>
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 through June 30, 2004.
. 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.
48
<PAGE>
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.
49
<PAGE>
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.
50
<PAGE>
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.
51
<PAGE>
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.
52
<PAGE>
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:
<TABLE>
<CAPTION>
Pension Postretirement
Benefits Benefits
1999 1998 1999 1998
- -----------------------------------------------------------------------------------------
(In millions)
<S> <C> <C> <C> <C>
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
=========================================================================================
<CAPTION>
Pension Postretirement
Benefits Benefits
1999 1998 1999 1998
- -----------------------------------------------------------------------------------------
(In millions)
<S> <C> <C> <C> <C>
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 $ - $ -
=========================================================================================
<CAPTION>
Pension Postretirement
Benefits Benefits
1999 1998 1999 1998
- -----------------------------------------------------------------------------------------
(In millions)
<S> <C> <C> <C> <C>
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)
=========================================================================================
</TABLE>
Net Periodic Benefit Cost
- -------------------------
We show the components of net periodic pension benefit cost in the following
table:
<TABLE>
<CAPTION>
Year Ended December 31, 1999 1998 1997
- ------------------------------------------------------------------------------------
(In millions)
<S> <C> <C> <C>
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
====================================================================================
</TABLE>
53
<PAGE>
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.
54
<PAGE>
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.
55
<PAGE>
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
- ----------------------
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
===============================================================================
56
<PAGE>
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
=============================================
57
<PAGE>
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:
<TABLE>
<CAPTION>
Year (In millions)
- -----------------------------------------------------------
<S> <C>
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
===========================================================
</TABLE>
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.
58
<PAGE>
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. While the rule was appealed by several groups including
utilities and states, 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.
59
<PAGE>
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.
60
<PAGE>
Recoverability of Electric Fuel Costs
- -------------------------------------
Until July 1, 2000, we will continue to recover our cost of electric fuel 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.
61
<PAGE>
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:
<TABLE>
<CAPTION>
At December 31, 1999 1998
- --------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
(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
</TABLE>
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.
62
<PAGE>
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
- ------------------------------------------
<TABLE>
<CAPTION>
Earnings Earnings
Income Applicable Per Share
From to Common of Common
Revenues Operations Stock Stock
- ------------------------------------------------------------------------
(In millions, except per-share amounts)
<S> <C> <C> <C> <C>
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
========================================================================
</TABLE>
1999 Quarterly Data - BGE
- -------------------------
<TABLE>
<CAPTION>
Earnings
Income Applicable
From to Common
Revenues Operations Stock
- -------------------------------------------------------------
(In millions)
<S> <C> <C> <C>
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
=============================================================
</TABLE>
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
- --------------------------------------------------
<TABLE>
<CAPTION>
Earnings Earnings
Income Applicable Per Share
From to Common of Common
Revenues Operations Stock Stock
- ------------------------------------------------------------------------
(In millions, except per-share amounts)
<S> <C> <C> <C> <C>
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
========================================================================
</TABLE>
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.
63
<PAGE>
EXHIBIT 12(a)
CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
-------------------------------------------------
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
12 Months Ended
-------------------------------------------------------------------------
December December December December December
1999 1998 1997 1996 1995
------------ ------------ ------------ ------------ ------------
(IN MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C> <C>
Income from Continuing Operations
(Before Extraordinary Charge) $ 326.4 $ 305.9 $ 254.1 $ 272.3 $ 297.4
Taxes on Income, Including Tax Effect for
BGE Preference Stock Dividends 182.5 169.3 145.1 148.3 152.0
------------ ------------ ------------ ------------ ------------
Adjusted Income $ 508.9 $ 475.2 $ 399.2 $ 420.6 $ 449.4
------------ ------------ ------------ ------------ ------------
Fixed Charges:
Interest and Amortization of
Debt Discount and Expense and
Premium on all Indebtedness $ 245.7 $ 255.3 $ 234.2 $ 203.9 $ 206.7
Earnings required for BGE Preference
Stock Dividends 21.0 33.8 45.1 59.4 61.0
Capitalized Interest 2.7 3.6 8.4 15.7 15.0
Interest Factor in Rentals 1.8 1.9 1.9 1.5 2.1
------------ ------------ ------------ ------------ ------------
Total Fixed Charges $ 271.2 $ 294.6 $ 289.6 $ 280.5 $ 284.8
------------ ------------ ------------ ------------ ------------
Earnings (1) $ 777.4 $ 766.2 $ 680.4 $ 685.4 $ 719.2
============ ============ ============ ============ ============
Ratio of Earnings to Fixed Charges 2.87 2.60 2.35 2.44 2.52
</TABLE>
(1) Earnings are deemed to consist of income from continuing operations (before
extraordinary charge) that includes earnings of Constellation Energy's
consolidated subsidiaries, equity in the net income of BGE's unconsolidated
subsidiary, income taxes (including deferred income taxes, investment tax
credit adjustments, and the tax effect of BGE's preference stock dividends),
and fixed charges other than capitalized interest.
<PAGE>
EXHIBIT 12(b)
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
---------------------------------------------------
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND
PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS
<TABLE>
<CAPTION>
12 Months Ended
----------------------------------------------------------------------------
December December December December December
1999 1998 1997 1996 1995
------------ ------------ ------------ ------------ ------------
(IN MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C> <C>
Income from Continuing Operations
(Before Extraordinary Charge) $ 328.4 $ 327.7 $ 282.8 $ 310.8 $ 338.0
Taxes on Income 182.0 181.3 161.5 169.2 172.4
------------ ------------ ------------ ------------ ------------
Adjusted Income $ 510.4 $ 509.0 $ 444.3 $ 480.0 $ 510.4
------------ ------------ ------------ ------------ ------------
Fixed Charges:
Interest and Amortization of
Debt Discount and Expense and
Premium on all Indebtedness $ 206.4 $ 255.3 $ 234.2 $ 203.9 $ 206.7
Capitalized Interest 0.4 3.6 8.4 15.7 15.0
Interest Factor in Rentals 1.0 1.9 1.9 1.5 2.1
------------ ------------ ------------ ------------ ------------
Total Fixed Charges $ 207.8 $ 260.8 $ 244.5 $ 221.1 $ 223.8
------------ ------------ ------------ ------------ ------------
Preferred and Preference
Dividend Requirements: (1)
Preferred and Preference Dividends $ 13.5 $ 21.8 $ 28.7 $ 38.5 $ 40.6
Income Tax Required 7.5 12.0 16.4 20.9 20.4
------------ ------------ ------------ ------------ ------------
Total Preferred and Preference
Dividend Requirements $ 21.0 $ 33.8 $ 45.1 $ 59.4 $ 61.0
------------ ------------ ------------ ------------ ------------
Total Fixed Charges and Preferred
and Preference Dividend Requirements $ 228.8 $ 294.6 $ 289.6 $ 280.5 $ 284.8
============ ============ ============ ============ ============
Earnings (2) $ 717.8 $ 766.2 $ 680.4 $ 685.4 $ 719.2
============ ============ ============ ============ ============
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
Dividend Requirements 3.14 2.60 2.35 2.44 2.52
</TABLE>
(1) Preferred and preference dividend requirements consist of an amount equal
to the pre-tax earnings that would be required to meet dividend
requirements on preferred stock and preference stock.
(2) Earnings are deemed to consist of income from continuing operations (before
extraordinary charge) that includes earnings of BGE's consolidated
subsidiaries, equity in the net income of BGE's unconsolidated subsidiary,
income taxes (including deferred income taxes and investment tax credit
adjustments), and fixed charges other than capitalized interest.
<PAGE>
Exhibit 23
CONSENT OF INDEPENDENT ACCOUNTANTS
----------------------------------
We hereby consent to the incorporation by reference in the Registration
Statements on Form S-3 and Form S-8 (File Nos. 333-75217, 333-59601, 33-57658,
333-24705, and 33-49801 and 333-45051, 33-59545, and 33-56084, respectively) of
Constellation Energy Group, Inc. and Form S-3 (File No. 333-66015) of Baltimore
Gas and Electric Company of our report dated January 19, 2000 relating to the
financial statements which appear in this Form 8-K.
/s/ PricewaterhouseCoopers LLP
- ---------------------------------
PricewaterhouseCoopers LLP
Baltimore, Maryland
February 15, 2000
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM
CONSTELLATION ENERGY'S DECEMBER 31, 1999 CONSOLIDATED INCOME STATEMENT, BALANCE
SHEET AND STATEMENT OF CASH FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE
TO SUCH STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 5,523
<OTHER-PROPERTY-AND-INVEST> 1,981
<TOTAL-CURRENT-ASSETS> 1,491
<TOTAL-DEFERRED-CHARGES> 689
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 9,684
<COMMON> 1,494
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 1,499
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,993
0
190
<LONG-TERM-DEBT-NET> 2,575
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 372
<LONG-TERM-DEBT-CURRENT-PORT> 808
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,746
<TOT-CAPITALIZATION-AND-LIAB> 9,684
<GROSS-OPERATING-REVENUE> 3,786
<INCOME-TAX-EXPENSE> 186
<OTHER-OPERATING-EXPENSES> 3,026
<TOTAL-OPERATING-EXPENSES> 3,212
<OPERATING-INCOME-LOSS> 574
<OTHER-INCOME-NET> 7
<INCOME-BEFORE-INTEREST-EXPEN> 581
<TOTAL-INTEREST-EXPENSE> 255
<NET-INCOME> 260
0
<EARNINGS-AVAILABLE-FOR-COMM> 260
<COMMON-STOCK-DIVIDENDS> 251
<TOTAL-INTEREST-ON-BONDS> 230
<CASH-FLOW-OPERATIONS> 679
<EPS-BASIC> 1.74
<EPS-DILUTED> 1.74
</TABLE>
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM BALTIMORE
GAS AND ELECTRIC COMPANY'S DECEMBER 31, 1999 CONSOLIDATED INCOME STATEMENT,
BALANCE SHEET AND STATEMENT OF CASH FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 5,523
<OTHER-PROPERTY-AND-INVEST> 414
<TOTAL-CURRENT-ASSETS> 655
<TOTAL-DEFERRED-CHARGES> 681
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 7,273
<COMMON> 1,494
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 861
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,355
0
190
<LONG-TERM-DEBT-NET> 2,206
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 129
<LONG-TERM-DEBT-CURRENT-PORT> 524
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,869
<TOT-CAPITALIZATION-AND-LIAB> 7,273
<GROSS-OPERATING-REVENUE> 3,028
<INCOME-TAX-EXPENSE> 178
<OTHER-OPERATING-EXPENSES> 2,324
<TOTAL-OPERATING-EXPENSES> 2,502
<OPERATING-INCOME-LOSS> 526
<OTHER-INCOME-NET> 8
<INCOME-BEFORE-INTEREST-EXPEN> 534
<TOTAL-INTEREST-EXPENSE> 206
<NET-INCOME> 262
13
<EARNINGS-AVAILABLE-FOR-COMM> 249
<COMMON-STOCK-DIVIDENDS> 251
<TOTAL-INTEREST-ON-BONDS> 174
<CASH-FLOW-OPERATIONS> 783
<EPS-BASIC>
<EPS-DILUTED>
</TABLE>
