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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended DECEMBER 31, 2000
Commission Exact name of registrant as specified in its IRS Employer
file number charter Identification No.
1-12869 CONSTELLATION ENERGY GROUP, INC. 52-1964611
1-1910 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210
MARYLAND
(States of incorporation)
250 W. PRATT STREET BALTIMORE, MARYLAND 21201
(Address of principal executive offices) (Zip Code)
410-234-5000
(Registrants' telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
Name of Each Exchange
Title of each class on Which Registered
------------------- -----------------------------
New York Stock Exchange, Inc.
Constellation Energy Group, Inc. Common Chicago Stock Exchange, Inc.
Stock--Without Par Value } Pacific Stock Exchange, Inc.
7.16% Trust Originated Preferred Securities
($25 liquidation amount per preferred
security) issued by BGE Capital Trust I, } New York Stock Exchange, Inc.
fully and unconditionally guaranteed, based
on several obligations, by Baltimore Gas and
Electric Company
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
Not Applicable
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months, and (2) have been subject to such filing
requirements for the past 90 days. Yes X No .
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrants' knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
Aggregate market value of Constellation Energy Group, Inc. Common Stock,
without par value, held by non-affiliates as of February 28, 2001 was
approximately $6,438,511,488 based upon New York Stock Exchange composite
transaction closing price.
CONSTELLATION ENERGY GROUP, INC. COMMON STOCK, WITHOUT PAR VALUE 151,188,640
SHARES OUTSTANDING ON FEBRUARY 28, 2001.
DOCUMENTS INCORPORATED BY REFERENCE
Part of Form 10-K Document Incorporated by Reference
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III Certain sections of the Proxy Statement for Constellation
Energy Group, Inc. for the Annual Meeting of Shareholders to
be held on April 27, 2001.
Baltimore Gas and Electric Company meets the conditions set forth in General
Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this Form in
the reduced disclosure format.
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TABLE OF CONTENTS
Page
----
Forward Looking Statements................................. 1
PART I
Item 1 -- Business................................................... 1
Overview.................................................. 1
Domestic Merchant Energy Business ........................ 3
BGE....................................................... 9
Electric Business........................................ 10
Electric Operating Statistics............................ 12
Gas Business............................................. 12
Gas Operating Statistics................................. 14
Franchises............................................... 15
Other Nonregulated Businesses ............................ 15
Consolidated Capital Requirements......................... 16
Environmental Matters..................................... 16
Employees................................................. 19
Item 2 -- Properties................................................. 19
Item 3 -- Legal Proceedings.......................................... 19
Item 4 -- Submission of Matters to a Vote of Security Holders........ 20
Executive Officers of the Registrant (Instruction 3 to Item
401(b) of Regulation S-K)................................. 20
PART II
Item 5 -- Market for Registrant's Common Equity and Related
Shareholder Matters....................................... 21
Item 6 -- Selected Financial Data.................................... 22
Item 7 -- Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 24
Item 7A -- Quantitative and Qualitative Disclosures About Market
Risk..................................................... 43
Item 8 -- Financial Statements and Supplementary Data................ 44
Item 9 -- Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................. 83
PART III
Item 10 -- Directors and Executive Officers of the Registrant......... 83
Item 11 -- Executive Compensation..................................... 83
Item 12 -- Security Ownership of Certain Beneficial Owners and
Management................................................ 83
Item 13 -- Certain Relationships and Related Transactions............. 83
PART IV
Item 14 -- Exhibits, Financial Statement Schedules and Reports on Form
8-K....................................................... 84
Signatures............................................................. 88
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:
. satisfaction of all the conditions precedent to the closing on the
purchase of the Nine Mile Point nuclear power plants, including obtaining
all regulatory approvals,
. obtaining all regulatory approvals necessary to close on the investment by
an affiliate of the Goldman Sachs Group, Inc. in our domestic merchant
energy business and complete the separation of our domestic merchant
energy business from our remaining businesses,
. satisfaction of all conditions precedent to the transaction with Goldman
Sachs,
. general economic, business, and regulatory conditions,
. the pace and nature of deregulation nationwide (including the status of
the California markets),
. competition,
. energy supply and demand,
. 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,
including the outcome of the appeal,
. commodity price risk,
. operating our generation assets in a deregulated market without the
benefit of a fuel rate adjustment clause,
. loss of revenue due to customers choosing alternative suppliers,
. higher volatility of earnings and cash flows,
. increased financial requirements of our nonregulated subsidiaries,
. inability to recover all costs associated with providing electric retail
customers service during the electric rate freeze period,
. implications from the transfer of BGE's generation assets and related
liabilities to nonregulated subsidiaries of Constellation Energy,
including the outcome of the appeal of the Maryland PSC's Order regarding
the transfer of generation assets, and
. force majeure events (events beyond our control), such as: acts of nature,
changes of laws, labor strikes and work stoppages, especially as they
could impact plant construction or operation.
Given these uncertainties, you should not place undue reliance on these
forward looking statements. Please see the other sections of this report and
our other periodic reports filed with the Securities and Exchange Commission
(SEC) for more information on these factors. These forward looking statements
represent our estimates and assumptions only as of the date of this report.
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PART I
Item 1. Business
Overview
Constellation Energy(R) Group, Inc. (Constellation Energy) is a holding company
whose businesses consist primarily of a domestic merchant energy business
focused mostly on power marketing and merchant generation in North America, and
Baltimore Gas and Electric Company (BGE(R)), a regulated electric and gas
public utility distribution company. Constellation Energy was incorporated in
Maryland on September 25, 1997. On April 30, 1999, Constellation Energy became
the holding company for BGE and its subsidiaries through a share exchange.
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.
Effective July 1, 2000, electric generation was deregulated in Maryland. In
anticipation of deregulation, during the first quarter of 2000, we combined our
wholesale power marketing operation with our domestic plant development and
operation activities to form a domestic merchant energy business. Additionally,
on July 1, 2000, BGE transferred all of its generation assets and related
liabilities at book value to two new nonregulated subsidiaries of our domestic
merchant energy business--Calvert Cliffs Nuclear Power Plant,(TM) Inc. and
Constellation Power Source Generation,(TM) Inc. We discuss the deregulation of
electric generation in Item 7. Management's Discussion and Analysis--Current
Issues.
We also formed a nonregulated holding company, Constellation Power Source
Holdings,(TM) Inc. that oversees:
. the wholesale power marketing and risk management activities of
Constellation Power Source,(TM) Inc.,
. the domestic power projects of Constellation Investments,(TM) Inc. and
Constellation Power,(TM) Inc. and subsidiaries,
. the fossil and hydroelectric generating assets of Constellation Power
Source Generation.
1
As a result of these changes, our domestic merchant energy business includes
the operations of Constellation Power Source Holdings, the nuclear generating
assets of Calvert Cliffs Nuclear Power Plant, Inc., and the nuclear consulting
services of Constellation Nuclear,(TM) LLC.
BGE is a regulated electric and gas public utility distribution company with
a service territory that covers the City of Baltimore and all or part of ten
counties in Central Maryland. BGE was incorporated in Maryland in 1906. BGE's
electric service territory includes an area of approximately 2,300 square miles
with an estimated population of 2.7 million. BGE's gas service territory
includes an area of approximately 800 square miles with an estimated population
of 2.0 million. There are no municipal or cooperative wholesale customers
within BGE's service territory.
Our other nonregulated businesses include the:
. Latin American power projects of Constellation Power and subsidiaries,
. energy products and services of Constellation Energy Source,(TM) Inc.,
. home products, commercial building systems, and residential and small
commercial electric and gas retail marketing of BGE Home Products &
Services,(TM) Inc. and subsidiaries,
. a general partnership, in which BGE is a partner, of District Chilled
Water General Partnership (ComfortLink(R)) that provides cooling services
for commercial customers in Baltimore,
. financial investments of Constellation Investments, and
. real estate holdings and senior-living facilities of Constellation Real
Estate Group,(TM) Inc.
Strategy
Customer choice and regulatory change significantly impact our business. In
response to these, we regularly evaluate our strategies with two goals in mind:
to improve our competitive position, and to anticipate and adapt to regulatory
change. Prior to July 1, 2000, the majority of our earnings were from BGE.
Going forward, prior to separating into two companies, we expect to derive
almost two-thirds of our earnings from our domestic merchant energy business.
While BGE continues to be regulated and to deliver electricity and natural
gas through its core distribution business, our primary growth strategies
center on the nonregulated domestic merchant energy business with the objective
of providing new sources of earnings growth.
On October 23, 2000, we announced three initiatives to advance our growth
strategies. The first initiative is that we entered into an agreement (the
"Agreement") with an affiliate of The Goldman Sachs Group, Inc. ("Goldman
Sachs"). Under the terms of the Agreement, Goldman Sachs will acquire up to a
17.5% equity interest in our domestic merchant energy business, which will be
consolidated under a single holding company ("Holdco"). Goldman Sachs will also
acquire a ten-year warrant for up to 13% of Holdco's common stock (subject to
certain adjustments). The warrant is exercisable six months after Holdco's
common stock becomes publicly available. The amount of common stock which
Goldman Sachs may receive upon exercise will be equal to the excess of the
market price of Holdco's common stock at the time of exercise over the exercise
price of $60 per share for all the stock subject to the warrant, divided by the
market price. Holdco may at its option pay Goldman Sachs such excess in cash.
Goldman Sachs is acquiring its interest and the warrant in exchange for $250
million in cash (subject to adjustment in certain instances) and certain assets
related to our power marketing operation. At closing, Goldman Sachs' existing
services agreement with our power marketing operation will terminate.
The second initiative is a plan to separate our domestic merchant energy
business from our remaining businesses. The separation will create two stand-
alone, publicly traded energy companies. One will be a merchant energy business
engaged in wholesale power marketing and generation under the name
"Constellation Energy Group" after the separation. The other will be a regional
retail energy delivery and energy services company, BGE Corp., which will
include BGE, our other nonregulated businesses, and our investment in Orion
Power Holdings, Inc. ("Orion").
As a result of the separation, shareholders will continue to own all of
Constellation Energy's current businesses through their ownership of the stock
of the new Constellation Energy Group and of BGE Corp.
The third initiative is a change in our common stock dividend policy
effective April 2001. In a move closely aligned with our separation plan,
effective April 2001, our annual dividend is expected to be set at $.48 per
share. After the separation, BGE Corp. expects to pay initial annual dividends
of $.48 per share. Constellation Energy Group, as a growing merchant energy
company, initially expects to reinvest its earnings in order to fund its growth
plans and not to pay a dividend.
The closing of the transaction with Goldman Sachs and the separation are
subject to customary closing conditions and contingent upon obtaining
regulatory approvals and a Private Letter Ruling from the Internal Revenue
Service regarding certain tax matters. We expect to complete the transaction
and separation by mid to late 2001. At the date of this report, we received
approval from the Federal Energy Regulatory Commission (FERC).
We discuss these strategic initiatives further in our Report on Form 8-K and
exhibits filed with the SEC on October 23, 2000.
Currently, our domestic merchant energy business controls over 9,000
megawatts (MW) of generation. In December 2000, we announced that a subsidiary
of Constellation Nuclear will purchase 1,550 MW of the 1,757 MW total
generating capacity of the Nine Mile Point nuclear power plant located in
Scriba, New York. The total purchase price, including
2
fuel, is $815 million. We discuss the planned acquisition of the Nine Mile
Point power plant in more detail in Note 10 to Consolidated Financial
Statements.
We also are constructing generating facilities representing 1,100 MW of
natural gas-fired peaking capacity in the Mid-Atlantic and Mid-West regions
which are expected to be operational by the summer of 2001. An additional 6,700
MW of natural gas-fired peaking and combined cycle production facilities in
various regions of North America are scheduled for completion in 2002 and
beyond. By 2005, our domestic merchant energy business expects to control
approximately 30,000 MW through the construction or purchase of additional
nuclear and non-nuclear generation assets and through contractual arrangements.
We decided to exit the Latin American portion of our operation as a result
of our concentration on domestic merchant energy. Currently, we are actively
seeking a buyer for the Latin American portion of our business and are working
toward completing our exit strategy in 2001.
We also might consider one or more of the following strategies:
. the complete or partial separation of our transmission and distribution
functions,
. mergers or acquisitions of utility or non-utility businesses, and
. sale of generation assets or one or more businesses.
Operating Segments
The percentages of revenues, net income, and assets attributable to our
operating segments are shown in the tables below. We present information about
our operating segments, including certain nonrecurring items, in Note 2 to
Consolidated Financial Statements. Effective with the first quarter of 2000, we
revised our operating segments to reflect the realignments of our organization
as discussed in the Overview section. Effective July 1, 2000, the financial
results of the electric generation portion of our business are included in the
domestic merchant energy business segment. Prior to that date, the financial
results are included in the regulated electric segment.
Unaffiliated Revenues
-----------------------------------------
Domestic
Merchant Regulated Regulated Other
Energy Electric Gas Nonregulated
-------- --------- --------- ------------
2000 11% 55% 15% 19%
1999 6 60 12 22
1998 4 66 13 17
Net income(1)
-----------------------------------------
Domestic
Merchant Regulated Regulated Other
Energy Electric Gas Nonregulated
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2000 60% 29% 9% 2%
1999 16 81 10 (7)
1998 17 85 9 (11)
Total Assets
-----------------------------------------
Other
Domestic Nonregulated
Merchant Regulated Regulated & Corp.
Energy Electric Gas Items
-------- --------- --------- ------------
2000 55% 28% 8% 9%
1999 13 65 9 13
1998 9 67 10 14
(1) Excludes an extraordinary charge of $66.3 million recorded in 1999 related
to electric restructuring as discussed in Note 4 to Consolidated Financial
Statements.
Domestic Merchant Energy Business
Introduction
Our domestic merchant energy business engages primarily in generation and power
marketing in North America. We integrate our electric generation, risk
management, and marketing operations to meet our customers' energy needs in the
wholesale energy market.
Our goal is to become a leading merchant energy business in North America.
We plan to continue our growth through the acquisition, development, and
operation of power plants in our targeted markets. We also intend to capitalize
on our ability to integrate power plants with the marketing of energy products
and the management of market risk associated with these products. We plan to
implement our strategy through the development of new power plants, acquisition
of power assets competitively positioned in targeted markets, contractual
arrangements for the control of generation capacity, and expansion of our
marketing and risk management activities.
Currently, our domestic merchant energy business controls over 9,000 MW of
generation. By 2005, our domestic merchant energy business expects to control
approximately 30,000 MW through the construction or purchase of additional
nuclear and non-nuclear generation assets and through contractual arrangements.
Our domestic merchant energy business experiences substantial competition
from diversified energy companies, merchant generation companies, utilities,
independent power producers, and power marketers. Competition is based on the
price and availability of the commodities, services delivered, and the quality
and reliability of services provided.
Weather conditions in the different regions of North America influence the
financial results of our domestic merchant energy business. Typically, demand
for electricity and its price are higher in the summer and the winter, when
weather is more extreme. However, all regions of North America typically do not
experience extreme weather conditions at the same time. Since the majority of
our generating plants currently are located in the PJM (Pennsylvania-New
Jersey-Maryland) Interconnection, our financial results are affected, to a
greater extent, by weather conditions in this area. Current weather conditions
also can affect the forward market price of
3
energy commodity and derivative contracts used by our power marketing operation
that are accounted for on a mark-to-market basis. To the extent that our power
marketing operation purchases and sells such contracts, our financial results
could be influenced by the impact that weather conditions have on the market
price of such contracts.
Delays in, or the ultimate form of, deregulation of electric generation in
various states may affect our domestic merchant energy business strategy. Our
domestic merchant energy business has $297.9 million invested in power projects
that sell 142 MW of electricity in California under power purchase agreements
as discussed in Note 10 to Consolidated Financial Statements, under the heading
California Power Purchase Agreements. The counterparties to the agreements are
two California investor-owned utilities. Due to various factors, including
shortage of generation and the high cost of natural gas, these utilities'
financial condition was severely impacted because they were paying more for
power than they were allowed to recover from their customers under the
deregulation plan in California. As a result, these utilities have not been
able to maintain current payments for the power they purchased to meet their
customers' energy needs and the credit ratings of these utilities were
downgraded below investment grade. The governor and legislature of California
have undertaken emergency actions to stabilize the financial condition of the
two utilities by purchasing power on behalf of these utilities and pursuing
legislation that should permit the utilities to pay their power costs.
In the meantime, these utilities have not been paying our California
projects in full for power supplied to them from December 2000. As of the date
of this report, our portion of the amount due from these utilities is
approximately $42 million. While we expect to be paid for this power, we cannot
predict when payment will occur or if full payment will be received. We have
taken reserves in amounts we believe to be reasonable under the circumstances.
On March 27, 2001, the California Public Utilities Commission issued an order
for an immediate retail rate increase. Accordingly, we expect that this order
should enable these utilities to pay us for all future power supplied to these
utilities. However, if the ultimate resolution of the events in California
prevents the collection of unpaid balances under power purchase agreements by
some or all of our projects, it could have a material impact on our financial
results.
In light of California's shortage of generation, we recently signed an
agreement with the California Department of Water Resources for the sale of
electricity beginning April 2001 through June 2003. We also signed an agreement
with the California Department of Water Resources for the output of our High
Desert I plant beginning July 2003 through September 2011 on a unit contingent
basis (i.e., if the output is not available because the plant is not operating,
there is no requirement to provide output from other sources.) We discuss our
credit and other exposures related to the issues in California in Item 7.
Management's Discussion and Analysis-Current Issues section.
Domestic Generation
We have operated in the nonregulated power markets since 1985. At December 31,
2000, we owned about 6,550 MW of generation capacity, and have over 9,000 MW
under development, in construction, or pending acquisition. We cannot provide
assurance that these projects or pending acquisitions will be completed.
Effective July 1, 2000, BGE transferred, at book value, its nuclear
generating assets, its nuclear decommissioning trust fund, and related
liabilities to Calvert Cliffs Nuclear Power Plant, Inc. These two units are our
largest generating units, totaling 1,685 MW, and are located in PJM. In March
2000, Calvert Cliffs became the first nuclear power plant in the United States
to achieve license renewal. The Nuclear Regulatory Commission (NRC) approved a
twenty-year license renewal for both units of Calvert Cliffs, extending the
license for Unit 1 to 2034 and for Unit 2 to 2036.
In addition, BGE transferred, at book value, its fossil generating assets
and related liabilities and its partial ownership interest in two coal plants
and a hydroelectric plant located in Pennsylvania to Constellation Power Source
Generation. These plants provide electricity from a variety of fuels (coal,
oil, gas and water) that total 4,554 MW and are located in PJM.
In total, these generating assets represent about 6,240 MW of generation
capacity with a total net book value at June 30, 2000 of approximately $2.4
billion. The output of these plants is managed by our power marketing
operation. We discuss our power marketing operation in the Power Marketing
section.
Constellation Power, Inc. and subsidiaries holds up to a 50% ownership
interest in 28 operating domestic energy projects that consist of electric
generation, fuel processing, or fuel handling facilities and are either
qualifying facilities under the Public Utility Regulatory Policies Act of 1978
or otherwise exempt from, or not subject to, the Public Utility Holding Company
Act of 1935. Projects totaling approximately $51.8 million of assets are
located in the East and $419.8 million of assets are located in the West. Each
electric generating plant sells its output to a local utility under long-term
contracts.
4
The following table describes our generating and processing facilities.
Installed % Owned Primary
Plant Location Capacity (MW) Owned Capacity (MW) Fuel
-------------------- ------------------------------ ---------------------- ----- ---------------------- ------------
(at December 31, 2000) (at December 31, 2000)
Generating
Facilities
Nuclear
Calvert Cliffs Calvert Co., MD 1,685 100.0 1,685 (A) Nuclear
Fossil
Steam
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Brandon Shores Anne Arundel Co., MD 1,300 100.0 1,300 (A) Coal
Herbert A. Wagner Anne Arundel Co., MD 1,006 100.0 1,006 (A) Coal/Oil/Gas
Charles P. Crane Baltimore Co., MD 385 100.0 385 (A) Coal
Gould Street Baltimore City, MD 104 100.0 104 (A) Oil/Gas
Riverside Baltimore Co., MD 78 100.0 78 (A) Gas
Keystone Armstrong and Indiana Cos., PA 1,711 21.0 359 (A),(B) Coal
Conemaugh Indiana Co., PA 1,711 10.6 181 (A),(B) Coal
ACE Trona, CA 102 22.5 23 (C) Coal
Jasmin Kern Co., CA 33 50.0 17 (C) Coal
POSO Kern Co., CA 33 50.0 17 (C) Coal
----- -----
Total Steam 6,463 3,470
Combustion Turbine
------------------
Perryman Harford Co., MD 350 100.0 350 Oil/Gas
Notch Cliff Baltimore Co., MD 128 100.0 128 Gas
Westport Baltimore City, MD 121 100.0 121 Gas
Riverside Baltimore Co., MD 173 100.0 173 Oil/Gas
Philadelphia Road Baltimore City, MD 64 100.0 64 Oil
Charles P. Crane Baltimore Co., MD 14 100.0 14 Oil
Herbert A. Wagner Anne Arundel Co., MD 14 100.0 14 Oil
----- -----
Total Combustion
Turbine 864 864 (A)
Hydroelectric
Safe Harbor Safe Harbor, PA 416 66.7 277 (A) Hydro
Malacha Muck Valley, CA 32 50.0 16 (C) Hydro
----- -----
Total Hydroelectric 448 293
Alternative
Mammoth Lakes G-1 Mammoth Lakes, CA 8 50.0 4 Geothermal
Mammoth Lakes G-2 Mammoth Lakes, CA 12 50.0 6 Geothermal
Mammoth Lakes G-3 Mammoth Lakes, CA 12 50.0 6 Geothermal
Ormesa II Imperial Valley, CA 17 50.0 9 Geothermal
Puna I Hilo, HI 30 50.0 15 Geothermal
Soda Lake I Fallon, NV 3 50.0 2 Geothermal
Soda Lake II Fallon, NV 14 50.0 7 Geothermal
Stillwater Fallon, NV 11 50.0 6 Geothermal
SEGS IV Kramer Junction, CA 30 12.0 4 Solar
SEGS V Kramer Junction, CA 30 4.0 1 Solar
SEGS VI Kramer Junction, CA 30 9.0 3 Solar
Chinese Station Sonora, CA 22 50.0 11 Biomass
Fresno Fresno, CA 24 50.0 12 Biomass
Rocklin Placer Co., CA 24 50.0 12 Biomass
Central Wayne Dearborn, MI 22 50.0 11 Municipal
Solid Waste
Colver Colver Township, PA 110 50.0 55 Waste Coal
Panther Creek Nesquehoning, PA 83 50.0 42 Waste Coal
Sunnyside Sunnyside, UT 51 50.0 26 Waste Coal
----- -----
Total Alternative 533 232 (C)
----- -----
Total Generating
Facilities 9,993 6,544
===== =====
(A) Represent the generating assets that were transferred from BGE to
nonregulated subsidiaries of Constellation Energy on July 1, 2000.
(B) These totals reflect our proportionate interest and entitlement to capacity
from Keystone and Conemaugh, which include 2 megawatts of diesel capacity for
Keystone and 1 megawatt of diesel capacity for Conemaugh.
(C) These totals reflect our proportionate interest in the entities that own
these plants.
5
Installed % Owned Primary
Plant Location Capacity (MW) Owned Capacity (MW) Fuel
------------- -------------- ---------------------- ----- ---------------------- ------------------
(at December 31, 2000) (at December 31, 2000)
Processing Facilities
Gary PCI Gary, IN -- 12.5 -- Coal Processing
A/C Fuels Hazelton, PA -- 50.0 -- Coal Processing
PC Synfuel VA I Appalachia, VA -- 16.7 -- Synfuel Processing
PC Synfuel WV I Charleston, WV -- 16.7 -- Synfuel Processing
PC Synfuel WV II Nettie, WV -- 16.7 -- Synfuel Processing
PC Synfuel WV III Mayberry, WV -- 16.7 -- Synfuel Processing
Our domestic generation operation currently plans to construct generating
facilities representing about 7,800 MW of natural gas-fired peaking capacity
and combined cycle production facilities in various regions in North America in
2001 and beyond. The output of these plants will be used to meet the energy
requirements of customers in the wholesale energy market. The following table
describes the generating facilities that currently are under construction or
are scheduled to begin construction shortly:
Target In
Capacity Primary Percent Service
Plant Location (MW) Type Fuel Controlled Date
- ----------- ------------ -------- ------------ ------- ---------- ---------
University
Park Chicago, IL 300 Combustion Turbine Gas 100 Summer 2001
Wolf Hills Bristol, VA 250 Combustion Turbine Gas 100 Summer 2001
Handsome
Lake Rockland Twp, PA 250 Combustion Turbine Gas 100 Summer 2001
Big Sandy Neal, WV 300 Combustion Turbine Gas 100 Summer 2001
Rio
Nogales Seguin, TX 800 Combined Cycle Gas 100 Summer 2002
Holland
Energy Shelby Co., IL 665 Combined Cycle Gas 100 Summer 2002
Oleander Brevard Co., FL 680 Combustion Turbine Gas 100 Summer 2002
High
Desert I Victorville, CA 750 Combined Cycle Gas 100 Summer 2003
-----
Total 3,995
We also have projects that currently are under development in other
strategic areas that include Texas, Wisconsin, Massachusetts, Florida, and
California.
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Planned Acquisition
On December 12, 2000, we announced that a subsidiary of Constellation Nuclear
will purchase 1,550 MW of the 1,757 MW total generating capacity of the Nine
Mile Point nuclear power plant, located in Scriba, New York. The subsidiary of
Constellation Nuclear will buy 100 percent of Unit 1 and 82 percent of Unit 2
for $815 million, including $78 million for fuel. The sale is expected to close
in mid-2001 upon receipt of all necessary regulatory approvals. Key regulatory
approvals are required from the NRC, FERC, and the New York State Public
Service Commission.
The terms of the transaction include power purchase agreements, whereby we
have agreed to sell 90 percent of our share of the Nine Mile Point plant's
output back to the sellers for approximately 10 years at an average price of
nearly $35 per megawatt-hour (MWH) over the term of the power purchase
agreements on a unit contingent basis. We discuss this planned acquisition in
more detail in Note 10 to Consolidated Financial Statements.
Fuel Sources
Our power plants use diverse fuel sources. At December 31, 2000, our fuel mix
based on capacity owned was:
Fuel Percentage
- ---- ----------
Nuclear.............................................................. 26%
Coal................................................................. 42
Oil.................................................................. 13
Renewable and Alternative(1)......................................... 8
Dual(2).............................................................. 6
Natural Gas.......................................................... 5
(1) Includes solar, geothermal, hydro, biomass, and waste-to-energy.
(2) Switches between natural gas and oil.
6
Nuclear
The two units at Calvert Cliffs produce electricity at a relatively low cost.
As a result, the costs of replacement energy associated with outages at these
units can be significant. If an unplanned outage were to occur during the
summer or winter when demand was at a high level, the replacement power costs
could have a material adverse impact on our financial results. We will use
appropriate risk management techniques consistent with our business plan and
policies in an effort to address this issue. The output at Calvert Cliffs over
the past five years was as follows:
Generation Capacity
MWH Factor
---------- --------
2000........................................................ 13,826,046 93%
1999........................................................ 13,309,306 91
1998........................................................ 13,326,633 91
1997........................................................ 13,133,441 90
1996........................................................ 12,069,937 82
The supply of fuel for nuclear generating stations includes the:
. purchase of uranium concentrates,
. conversion to uranium hexafluoride,
. enrichment of uranium hexafluoride, and
. fabrication of nuclear fuel assemblies.
Uranium
Concentrates:
We have, either in inventory or under contract, sufficient
quantities of uranium to meet 100% of our requirements through 2002
and 25% through 2004.
Conversion:We have contractual commitments providing for the conversion of
uranium concentrates into uranium hexafluoride that will meet
approximately 75% of our requirements through 2004.
Enrichment:We have a contract with the U.S. Enrichment Corporation that
provides approximately 50% of our enrichment requirements to 2004.
Fuel
Assembly
Fabrication:
We have contracted for the fabrication of fuel assemblies for
reloads required through 2013.
The nuclear fuel market is competitive and we do not anticipate any problem
in meeting our requirements.
Storage of Spent Nuclear Fuel--Federal Facilities: Under the Nuclear Waste
Policy Act of 1982 (the 1982 Act), we contracted with the United States
Department of Energy (DOE) to place spent fuel discharged from Calvert Cliffs
into a federal repository. Such facilities do not currently exist, and,
consequently, must be developed and licensed. We cannot predict when such
facilities will be available. However, the 1982 Act required the DOE to accept
spent fuel starting in 1998. We cannot predict the ultimate cost of disposing
spent fuel. However, the 1982 Act assesses a 0.1 cent (one mill) per kilowatt-
hour fee on nuclear electricity generated and sold to help pay for spent fuel
disposal. We estimate this fee to be approximately $13 million for Calvert
Cliffs each year based on expected operating levels. Fees are deposited into
the Nuclear Waste Fund. These costs are paid by Calvert Cliffs Nuclear Power
Plant, Inc.
In December 1996, the DOE notified us and other nuclear utilities that it
would not be able to meet the 1998 deadline for accepting spent fuel. We
participated in litigation, along with 36 other utilities, against the DOE. The
litigation, titled Northern States Power, et al. v. DOE, was filed January 31,
1997 in the United States Court of Appeals for the D.C. Circuit. That court has
original jurisdiction under the 1982 Act. The utilities asked the court to
allow them to pay fees that formerly went directly to the DOE for deposit into
the Nuclear Waste Fund, into escrow instead. Among other remedies, the
utilities also asked the court to force the DOE to submit a program with
milestones illustrating how it would meet the deadline for accepting spent
nuclear fuel, and a monthly report to allow the utilities to monitor the DOE's
progress.
On November 14, 1997, the court ordered the DOE to comply with its
unconditional obligation under the 1982 Act to dispose of spent fuel. The court
did not grant the utilities the remedies sought, stating that adequate
contractual and statutory remedies already existed. The DOE and several
utilities filed separate motions for reconsideration with the court, which were
denied. The DOE's request for review to the U.S. Supreme Court was also denied.
We are currently evaluating our contractual options in light of the court's
decision. We cannot currently estimate the total costs we will incur as a
result of the DOE's failure to meet the 1998 deadline.
Storage of Spent Nuclear Fuel--On-Site Facility: We have a license from the NRC
to operate an on-site independent spent fuel storage facility. We have storage
capacity at Calvert Cliffs that will accommodate spent fuel from operations
through the year 2006. In addition, we can expand our temporary storage
capacity to meet future requirements until federal storage is available.
Cost for Decommissioning Uranium Enrichment Facilities: The Energy Policy Act
of 1992 (the 1992 Act) contains provisions requiring domestic nuclear utilities
to contribute to a fund for decommissioning and decontaminating the DOE's
uranium enrichment
7
facilities. These contributions are payable by BGE generally over a fifteen-
year period with escalation for inflation and are based upon the amount of
uranium enriched by the DOE for each utility through 1992. The 1992 Act
provides that these costs are recoverable through BGE's service rates.
Information about the cost of decommissioning is discussed in Note 1 to
Consolidated Financial Statements.
Cost for Decommissioning Calvert Cliffs: Calvert Cliffs Nuclear Power Plant,
Inc., is liable for the decommissioning costs of Calvert Cliffs and costs
associated with the on-site independent spent fuel storage facilities. On July
1, 2000, BGE transferred the trust fund established to decommission Calvert
Cliffs and the on-site spent fuel storage facility to Calvert Cliffs Nuclear
Power Plant, Inc. Under the Restructuring Order issued by the Maryland Public
Service Commission (Maryland PSC), BGE is authorized to collect from customers
$520 million in 1993 dollars, adjusted for inflation, for the decommissioning
of Calvert Cliffs. BGE is passing the amount collected from its customers to
Calvert Cliffs Nuclear Power Plant, Inc. We must refund any amounts collected
from BGE customers at the time of decommissioning that is in excess of the
amount authorized to be collected by the Restructuring Order. We discuss the
Restructuring Order in the Electric Regulatory Matters and Competition--
Restructuring Order section.
Coal
We get most of our coal under supply contracts with mining operators, and we
get the rest through spot purchases. We believe that we will be able to renew
supply contracts as they expire or enter into similar contracts with other coal
suppliers. Our primary coal-burning facilities have the following requirements:
Annual Coal
Requirement Special Coal
(tons) Restrictions
----------- ----------------------
Brandon Shores Sulfur content less
Units 1 and 2 (combined).................... 3,500,000 than 0.8%
Crane Low ash melting
Units 1 and 2 (combined).................... 800,000 temperature
Wagner Sulfur content no more
Units 2 and 3 (combined).................... 1,000,000 than 1%
Coal deliveries to these facilities are made by rail and barge. The coal we
use is produced mostly from mines located in central and northern Appalachia.
The majority of the annual coal requirements for the Keystone plant are
under contract from Rochester and Pittsburgh Coal Company. The remainder of the
Keystone plant and all of the Conemaugh plant annual coal requirements are
purchased from local suppliers on the open market. The sulfur restrictions on
coal are approximately 2.5% for the Keystone plant and approximately 3.5% for
the Conemaugh plant.
The annual coal requirements for the ACE, Jasmin, and POSO plants, which are
located in California, are supplied under contracts with mining operators. Each
plant is restricted to coal with sulfur content less than 4%.
Oil
Under normal burn practices, our requirements for residual fuel oil (No. 6)
amount to approximately 1,500,000 to 2,000,000 barrels of low-sulfur oil per
year. Deliveries of residual fuel oil are made directly into our barges from
the suppliers' Baltimore Harbor marine terminal for distribution to the various
generating plant locations. We also require approximately 5,000,000 to
6,000,000 gallons of distillates (No. 2 oil and kerosene) annually. Distillates
are purchased from the suppliers' Baltimore truck terminals for distribution to
the various generating plant locations. We have contracts with various
suppliers to purchase oil at spot prices to meet our requirements.
Gas
We purchase natural gas and transportation, as necessary, for electric
generation at certain plants and to provide ignition and banking at certain
plants. Some of our gas-fired units can use residual fuel oil or distillates
instead of gas. Gas is purchased under contracts with suppliers on the spot
market. We believe that we will be able to obtain adequate quantities of gas to
meet our requirements.
Power Marketing
Constellation Power Source, Inc. (CPS), formed in 1997, provides power
marketing and risk management services to wholesale customers in North America
through the purchase and sale of electric power, other energy commodities and
related derivative contracts. CPS was ranked by Power Markets Weekly as a top
ten power marketer in the United States based on MWH sold in 2000.
CPS purchases electric power by several methods, including:
. through bilateral agreements with third parties,
. from regional power pools, or
. from affiliates in the domestic merchant energy business.
CPS sells the electric power it purchases to customers such as utilities,
municipalities, cooperatives and other resellers, structuring the transactions
to meet each customer's diverse needs.
8
CPS supplies the standard offer electric supply service to BGE as discussed
in Item 7. Management's Discussion and Analysis--Current Issues and to several
distribution utilities in New England. CPS sold 162,349,997 MWH of electric
power in 2000, including sales to BGE, 69,787,986 MWH in 1999, and 27,608,080
MWH in 1998, its first full year of operation. Excluding BGE, no one customer
or small group of customers accounts for a material portion of CPS' electric
power purchases or sales.
CPS' goal is to be a premier provider of energy products and risk management
services to wholesale customers throughout North America. To accomplish this
goal, CPS focuses its activities on structuring transactions to meet customers'
specific energy needs and providing risk management services to wholesale
customers. This includes optimizing the value of generating assets owned by
affiliates. We believe that our energy marketing and risk management expertise
and strong risk controls are essential to maximize the value of our generating
assets in the highly competitive wholesale energy market. We expect CPS to
continue to establish itself as a leading national merchant energy company by
leveraging its marketing and risk management expertise to pursue opportunities
presented by the continuing deregulation of the North American energy markets.
CPS engages in trading activities in order to manage its portfolio of energy
purchases and sales to customers through structured transactions, and to take
advantage of arbitrage opportunities that exist across different markets. These
activities involve the use of a variety of instruments, including:
.forward contracts, which commit it to purchase or sell energy commodities
in the future,
.swap agreements, which require payments to or from counterparties based
upon the differential between two prices for a predetermined contractual
(notional) quantity,
.options contracts, which convey the right to buy or sell a commodity,
financial instrument or index at a predetermined price, and
.futures contracts, which are exchange traded standardized commitments to
purchase or sell a commodity or financial instrument, or make a cash
settlement, at a specified price and future date.
Active portfolio management allows CPS to manage and hedge its fixed price
purchase and sale commitments; provide fixed-price commitments to customers and
suppliers; reduce exposure to the volatility of market prices; and hedge fuel
requirements at power generation facilities.
CPS' trading activities expose it to market and credit risk. CPS monitors
and controls its risk exposure through separate but complementary financial,
operational, and credit reporting systems. Our Board of Directors establishes
parameters for the risks that CPS undertakes, which are monitored daily by
management. In addition, CPS maintains a segregation of duties, with credit
review and risk monitoring functions performed by groups that are independent
from revenue producing groups.
CPS is exposed to the risk that fluctuating market prices may adversely
affect its, or our, financial results. For additional information on market and
credit risk, see Item 7. Management's Discussion and Analysis--Market Risk.
Nuclear Consulting Services
Constellation Nuclear Services, Inc. (CNS) was formed in 1999 to provide
nuclear license renewal related services to the utility industry. In addition
to nuclear license renewal, CNS also provides plant aging mitigation services
including: spent fuel management, dry fuel storage, steam generation life
optimization, and project management and engineering.
BGE
BGE is a regulated electric and gas public utility distribution company with a
service territory that covers the City of Baltimore and all or part of ten
counties in Central Maryland. BGE's electric service territory includes an area
of approximately 2,300 square miles with an estimated population of 2.7
million. BGE's gas service territory includes an area of approximately 800
square miles with an estimated population of 2.0 million. Our electric and gas
revenues come from many customers--residential, commercial, and industrial. In
2000, our largest electric customer provided 2.4% of our total electric
revenues. In 2000, our largest gas customer provided 0.7% of our total gas
revenues. As discussed below, BGE's regulated electric business was
significantly impacted by the July 1, 2000 implementation of customer choice in
Maryland.
Weather affects the demand for electricity and gas for our regulated
businesses. Very hot summers and very cold winters increase demand. Mild
weather reduces demand. Residential sales for our regulated businesses are
impacted more by weather than commercial and industrial sales, which are mostly
affected by business needs for electricity and gas.
9
Electric Business
Electric Regulatory Matters and Competition
Restructuring Order
On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition
Act of 1999 (the "Act") and accompanying tax legislation that significantly
restructured Maryland's electric utility industry and modified the industry's
tax structure. In the Restructuring Order discussed below, the Maryland PSC
addressed the major provisions of the Act. The accompanying tax legislation is
discussed in detail in Note 4 to Consolidated Financial Statements.
On November 10, 1999, the Maryland PSC issued a Restructuring Order that
resolved the major issues surrounding electric restructuring, accelerated the
timetable for customer choice, and addressed the major provisions of the Act.
The Restructuring Order also resolved 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 to lower our electric base rates. The major provisions of the
Restructuring Order are discussed in Note 4 to Consolidated Financial
Statements.
As a result of the deregulation of electric generation, the following
occurred effective July 1, 2000:
.All customers, except a few commercial and industrial companies that have
signed contracts with BGE, can choose their electric energy supplier. 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 reduced residential base rates by approximately 6.5%, on average about
$54 million a year. These rates will not change before July 2006.
.BGE transferred, at book value, its nuclear generating assets, its nuclear
decommissioning trust fund, and related liabilities to Calvert Cliffs
Nuclear Power Plant, Inc. In addition, BGE transferred, at book value, its
fossil generating assets and related liabilities and its partial ownership
interest in two coal plants and a hydroelectric plant located in
Pennsylvania to Constellation Power Source Generation. In total, these
generating assets represent about 6,240 megawatts of generation capacity
with a total net book value at June 30, 2000 of approximately $2.4
billion.
.BGE assigned approximately $47 million to Calvert Cliffs Nuclear Power
Plant, Inc. and $231 million to Constellation Power Source Generation of
tax-exempt debt related to the transferred assets. Also, Constellation
Power Source Generation issued approximately $366 million in unsecured
promissory notes to BGE. Repayments of the notes by Constellation Power
Source Generation will be used exclusively to service the current
maturities of certain BGE long-term debt.
.BGE transferred equity associated with the generating assets to Calvert
Cliffs Nuclear Power Plant, Inc. and Constellation Power Source
Generation.
.The fossil fuel and nuclear fuel inventories, materials and supplies, and
certain purchased power contracts of BGE were also assumed by these
subsidiaries.
Standard Offer Service
Effective July 1, 2000, BGE provides standard offer service to customers at
fixed rates over various time periods during the transition period through June
30, 2006 for those customers that do not choose an alternate supplier. In
addition, the electric fuel rate was discontinued effective July 1, 2000. CPS
provides BGE with the energy and capacity required to meet its standard offer
service obligations for the first three years of the transition period.
Thereafter, BGE will competitively bid the energy and capacity for those
customers electing to receive energy from BGE. We are evaluating alternatives
to minimize the market risk after June 30, 2003. We discuss the market risk of
our regulated electric business in more detail in Item 7. Management's
Discussion and Analysis--Market Risk.
Prior to July 1, 2000, BGE deferred (included as an asset or liability on
the Consolidated Balance Sheets and excluded from the Consolidated Statements
of Income) the difference between its actual costs of fuel and energy and what
it collected from customers under the fuel rate in a given period. Effective
July 1, 2000, the fuel rate clause was discontinued under the terms of the
Restructuring Order. In September 2000, the Maryland PSC approved the
collection of the $54.6 million accumulated difference between BGE's actual
costs of fuel and energy and the amounts collected from customers that were
deferred under the electric fuel rate clause through June 30, 2000. BGE is
collecting this accumulated difference from customers over the twelve-month
period beginning October 2000.
10
BGE's electric transmission and distribution business continues to be
regulated by the Maryland PSC although electric delivery rates are fixed until
June 30, 2004 for industrial and commercial customers and until June 30, 2006
for residential customers. However, electric transmission and distribution
utilities are facing competition from alternative energy sources that include
on-site generation and cogeneration projects. In future years, electric
transmission and distribution utilities could face competition from emerging
technologies that include fuel cells and solar panels.
Electric Load Management
BGE implemented various programs for use when system-operating conditions or
market economics indicate that a reduction in load would be beneficial. We
refer to these programs as active load management programs. These programs
include:
.customer-owned generation and curtailable service for large commercial and
industrial customers,
.air conditioning control for residential and commercial customers, and
.residential water heater control.
BGE generally activates these programs on summer days when demand and/or
wholesale prices are relatively high. The reduction in the summer 2000 peak
load from active load management was approximately 425 MW. The potential
reduction in the summer 2001 peak load from active load management is expected
to be approximately425 MW.
Transmission Facilities
Our transmission facilities are connected to those of neighboring utility
systems as part of the PJM. Under the PJM agreement, we use the interconnected
facilities for substantial energy interchange and capacity transactions as well
as emergency assistance.
In December 1999, FERC issued Order 2000, amending its regulations under the
Federal Power Act to advance the formation of Regional Transmission
Organizations (RTOs). The regulations require that each public utility that
owns, operates, or controls facilities for the transmission of electric energy
in interstate commerce make certain filings with respect to forming and
participating in a RTO. FERC also identified the minimum characteristics and
functions that a transmission entity must satisfy in order to be considered a
RTO.
According to Order 2000, a public utility that is a member of an existing
transmission entity that has been approved by FERC as in conformance with the
Independent System Operator (ISO) principles set forth in the FERC Order No.
888, such as BGE through its membership in the PJM, was required to make a
filing no later than January 15, 2001. PJM and the joint transmission owners,
including BGE, made that filing on October 11, 2000. That filing explained the
extent to which PJM met the minimum characteristics and functions of a RTO, and
explained its plans with respect to conforming to these characteristics and
functions.
As a member of PJM, an existing ISO, BGE does not expect to be materially
impacted by Order 2000. However, we are appealing two requirements of Order
2000 whereby:
.we would have to go through PJM to make a filing with FERC to change our
transmission rates, and
.we would have to transfer operational control of our transmission
facilities to PJM.
The U.S. Supreme Court agreed to hear an appeal by others of FERC Order 888.
We cannot predict the outcome of this appeal or the impact on BGE at this time.
11
Electric Operating Statistics
Year Ended December 31,
--------------------------------------------
2000(A) 1999 1998 1997 1996
-------- -------- -------- -------- --------
Revenues (In Millions)
Residential...................... $ 922.6 $ 975.2 $ 948.6 $ 932.5 $ 958.7
Commercial....................... 926.2 939.3 912.9 892.6 861.3
Industrial....................... 203.6 204.3 211.5 211.9 207.6
-------- -------- -------- -------- --------
System Sales.................... $2,052.4 $2,118.8 $2,073.0 $2,037.0 $2,027.6
======== ======== ======== ======== ========
Sales (In Thousands)-- MWH:
Residential...................... 11,675 11,349 10,965 10,806 11,243
Commercial....................... 14,042 13,565 13,219 12,718 12,591
Industrial....................... 4,476 4,350 4,583 4,575 4,596
-------- -------- -------- -------- --------
System Sales.................... 30,193 29,264 28,767 28,099 28,430
======== ======== ======== ======== ========
Customers (In Thousands)
Residential...................... 1,033.4 1,021.4 1,009.1 1,001.0 995.2
Commercial....................... 108.9 107.7 106.5 105.9 104.5
Industrial....................... 5.0 4.7 4.6 4.5 4.3
-------- -------- -------- -------- --------
Total........................... 1,147.3 1,133.8 1,120.2 1,111.4 1,104.0
======== ======== ======== ======== ========
(A) Electric operating results reflect generation function as part of
regulated operations through June 30, 2000.
- --------------------------------------------------------------------------------
Gas Business
Gas Regulatory Matters and Competition
Currently, no regulation exists for the wholesale price of natural gas as a
commodity, and the regulation of interstate transmission at the federal level
has been reduced. All BGE gas customers have the option to purchase gas from
other suppliers. However, the delivery of gas continues to be regulated by the
Maryland PSC.
We buy all gas that we resell directly from various suppliers (rather than
pipeline companies) and arrange separately for transportation and storage.
Alternatively, we can transport gas for our customers. We also participate in
the interstate markets, by releasing pipeline capacity or bundling pipeline
capacity with gas for off-system sales.
We provide all of our customers with the option for delivery service across
our distribution system so that they may make direct purchase and
transportation arrangements with suppliers and pipelines. In addition to the
delivery service, we also provide these customers with meter readings, billing,
emergency response, regular maintenance, and balancing.
Approximately 57% of the gas on our distribution system is for customers
using delivery service. We charge all our delivery service customers fees to
recover the fixed costs for the transportation service we provide. These fees
are the same as the base rate charged for gas sales.
Delivery service customers may choose to purchase gas from several different
suppliers, including our subsidiary, BGE Home Products & Services, Inc. The
basis of competition for delivery service customers is primarily commodity
price.
As part of our response to the increase in competition in the natural gas
business, earnings from off-system gas sales and capacity release revenues are
shared between shareholders and customers. Off-system gas sales are low-margin
direct sales of gas to wholesale suppliers of natural gas outside our service
territory. We make these sales as part of a program to balance our supply of,
and cost of, natural gas. In addition, we have a market based rates incentive
mechanism for gas we sell on our system. Under market based rates, our actual
cost of gas is compared to a market index (a measure of the market price of gas
in a given period). The difference between our actual cost and the market index
is shared equally between shareholders and customers.
On November 17, 1999, BGE filed an application with the Maryland PSC to
increase its gas base rates. The Maryland PSC authorized a $6.4 million annual
increase in our gas base rates effective June 22, 2000.
12
Gas Operations
We distribute natural gas purchased directly from many producers and marketers.
We have transportation and storage agreements as shown below. These agreements
are on file with the FERC. The gas is transported to our city gates, under
various transportation agreements, by:
. Columbia Gas Transmission Corporation,
. Dominion Transmission Inc., and
. Transcontinental Gas Pipe Line Corporation.
To transport gas from the pipelines that supply gas to the pipelines that
are connected to our city gates as mentioned above, we also have transportation
capacity under contract with:
. Texas Gas,
. Columbia Gulf Transmission Company, and
. ANR Pipeline Company.
We have storage service agreements with:
. Columbia Gas Transmission Corporation,
. Dominion Transmission Inc., and
. ANR Pipeline Company.
Our current pipeline firm transportation entitlements to serve our firm
loads are 284,053 DTH per day during the winter period and 259,053 DTH per day
during the summer period. We use the firm transportation capacity to move gas
from the Gulf of Mexico, Louisiana, south central regions of Texas, and Canada
to our city gates. We can arrange short-term contracts or exchange agreements
with other gas companies in the event of short-term emergencies.
We have three market area storage contracts to manage weather sensitive gas
demand during the winter period. Our current maximum storage entitlements are
235,080 DTH per day. To supplement our gas supply at times of heavy winter
demands and to be available in temporary emergencies affecting gas supply, we
have:
. a liquefied natural gas facility for the liquefaction and storage of
natural gas with a total storage capacity of 1,000,000 DTH and a planned
daily capacity of 287,988 DTH, and
. a propane air facility with a mined cavern with a total storage capacity
equivalent to 500,000 DTH and a planned daily capacity of 85,000 DTH.
We have under contract sufficient volumes of propane for the operation of
the propane air facility and are capable of liquefying sufficient volumes of
natural gas during the summer months for operation of our liquefied natural gas
facility during winter emergencies.
13
Gas Operating Statistics
Year Ended December 31,
--------------------------------------------
2000 1999 1998 1997 1996
-------- -------- -------- -------- --------
Gas Output (In Thousands) -- DTH:
Purchased........................ 48,518 49,082 47,972 62,988 70,260
LNG Withdrawn from Storage....... 874 463 268 484 904
Produced......................... 261 486 46 541 784
-------- -------- -------- -------- --------
Total Output.................... 49,653 50,031 48,286 64,013 71,948
Delivery service gas (A)......... 67,658 59,494 55,608 52,629 45,964
Off-system sales (B)............. 22,456 15,543 16,724 14,759 9,968
-------- -------- -------- -------- --------
Total........................... 139,767 125,068 120,618 131,401 127,880
======== ======== ======== ======== ========
Peak Day Sendout (DTH)............ 795,700 727,800 658,359 765,011 708,966
======== ======== ======== ======== ========
Capability on Peak Day (DTH)...... 825,100 836,600 833,000 870,000 870,000
Revenues (In Millions)
Residential
Excluding Delivery Service...... $ 328.4 $ 298.1 $ 279.2 $ 321.7 $ 320.1
Delivery Service................ 23.5 11.5 4.9 0.5 --
Commercial
Excluding Delivery Service...... 97.9 79.3 75.6 113.5 125.1
Delivery Service................ 25.8 24.4 19.4 12.9 7.2
Industrial
Excluding Delivery Service...... 10.9 8.2 8.0 11.4 17.1
Delivery Service................ 16.3 16.1 16.0 17.2 14.6
-------- -------- -------- -------- --------
System sales..................... 502.8 437.6 403.1 477.2 484.1
Off-system sales................. 101.0 42.9 40.9 37.5 26.6
Other............................ 7.8 7.6 7.1 6.9 6.6
-------- -------- -------- -------- --------
Total........................... $ 611.6 $ 488.1 $ 451.1 $ 521.6 $ 517.3
======== ======== ======== ======== ========
Sales (In Thousands) -- DTH:
Residential
Excluding Delivery Service...... 34,561 34,272 33,595 39,958 43,784
Delivery Service................ 9,209 4,468 1,890 205 --
Commercial
Excluding Delivery Service...... 13,186 11,733 11,775 18,435 22,698
Delivery Service................ 22,921 20,288 16,633 12,964 8,755
Industrial
Excluding Delivery Service...... 1,386 1,367 1,412 2,016 2,887
Delivery Service................ 32,382 33,118 34,798 38,791 36,201
-------- -------- -------- -------- --------
System sales..................... 113,645 105,246 100,103 112,369 114,325
Off-system sales................. 22,456 15,543 16,724 14,759 9,968
-------- -------- -------- -------- --------
Total........................... 136,101 120,789 116,827 127,128 124,293
======== ======== ======== ======== ========
Customers (In Thousands)
Residential...................... 553.7 543.5 532.5 524.5 516.5
Commercial....................... 40.1 39.9 39.6 39.3 38.9
Industrial....................... 1.4 1.3 1.3 1.3 1.3
-------- -------- -------- -------- --------
Total........................... 595.2 584.7 573.4 565.1 556.7
======== ======== ======== ======== ========
For the periods presented, we achieved an all-time peak day sendout of
795,700 DTH on January 17, 2000.
(A) Delivery service gas is gas purchased by customers directly from
suppliers for which we receive a fee for transportation through our
system.
(B) Off-system sales are low-margin sales to wholesale suppliers of natural
gas outside our service territory (beginning first quarter 1996).
We discuss these programs further in the Gas Regulatory Matters and
Competition section.
14
Franchises
We have nonexclusive electric and gas franchises to use streets and other
highways that are adequate and sufficient to permit us to engage in our present
business. All such franchises, other than the gas franchises in Manchester,
Hampstead, Perryville, Sykesville, Havre de Grace, Mt. Airy, and Montgomery and
Frederick Counties, are unlimited
as to time. The gas franchises for these jurisdictions expire at various times
from 2015 to 2087, except for Havre de Grace which has the right, exercisable
at twenty-year intervals from 1907, to purchase all of our gas properties in
that municipality. Conditions of the franchises are satisfactory.
- --------------------------------------------------------------------------------
Other Nonregulated Businesses
International Projects
At December 31, 2000, Constellation Power, Inc. had invested about $255.9
million in 10 power projects in Latin America. These investments include:
. a 51% interest in a Panamanian electric distribution company by an
investment group in which subsidiaries of Constellation Power hold an 80%
interest,
. existing electric generation facilities in Guatemala and Bolivia, and
. an investment in an Energy Fund that has investments in Argentina, Brazil,
and Bolivia.
In December 1999, we decided to exit the Latin American portion of our
business as a result of our concentration on domestic merchant energy.
Currently, we are actively seeking a buyer for the Latin American portion of
our business and are working toward completing our exit strategy in 2001.
Energy Products and Services
Constellation Energy Source, Inc. offers energy products and services designed
primarily to provide solutions to the energy needs of commercial and industrial
customers. These energy products and services include:
. a full range of heating, ventilation, air conditioning, and energy
services,
. energy consulting and power-quality services,
. services to enhance the reliability of individual electric supply systems,
and
. customized financing alternatives.
Home Products, Commercial Building Systems, and Electric and Gas Retail
Marketing
BGE Home Products & Services, Inc. and subsidiaries offer services to
residential, commercial, and industrial customers. These services include:
. the sale and service of electric and gas appliances,
. home improvements,
. the sale and service of heating, air conditioning, plumbing, electrical,
and indoor air quality systems, and
. electric and natural gas retail marketing.
ComfortLink
ComfortLink provides cooling services using a central chilled water
distribution system to commercial customers in Baltimore.
Financial Investments
Constellation Investments, Inc. engages in financial investments, including:
. marketable securities, and
. financial limited partnerships.
Real Estate and Senior-Living Facilities
Constellation Real Estate Group, Inc. develops, owns, and manages real estate
and senior-living facilities, including:
. land under development in the Baltimore-Washington corridor,
. a mixed-use planned-unit development,
. senior-living facilities, and
. an equity interest in Corporate Office Properties Trust (COPT), a real
estate investment trust.
We describe the real estate business and the COPT transaction further in
Item 7. Management's Discussion and Analysis and Note 3 to Consolidated
Financial Statements.
We consider market demand, interest rates, the availability of financing,
and the strength of the economy in general when making decisions about our real
estate projects. If we were to decide to sell our real estate projects, we
could have write-downs. In addition, if we were to sell our real estate
projects in the current market, we would have losses, which could be material,
although the amount of the losses is hard to predict. Depending on market
conditions, we could also have material losses on any future sales.
15
Consolidated Capital Requirements
Our business requires a great deal of capital. Our total capital requirements
for 2000 were $1,877 million. Of this amount, $1,125 million was used in our
nonregulated businesses and $752 million was used in our utility operations. We
estimate our total capital requirements for the years 2001 through 2003 to be:
. $2,529 million in 2001,
. $1,863 million in 2002, and
. $2,626 million in 2003.
We continuously review and change our capital expenditure programs, so
actual expenditures may vary from the estimates for the years 2001 through
2003.
We discuss our capital requirements further in Item 7. Management's
Discussion and Analysis-- Capital Resources.
- --------------------------------------------------------------------------------
Environmental Matters
We are subject to regulation by various federal, state, and local authorities
with regard to:
. air quality,
. water quality,
. chemical and waste management and disposal, and
. other environmental matters.
Some of the regulations require substantial expenditures for additions to
some of our older generating plants and the use of more low-sulfur fuels. We
cannot precisely estimate the total effect on our facilities and operations of
current and future environmental regulations and standards. However, our
capital expenditures (excluding allowance for funds used during construction)
were approximately $126 million during the five-year period 1996-2000 to comply
with existing environmental standards and regulations, and we estimate that the
future incremental capital expenditures (excluding allowance for funds used
during construction) necessary to comply with existing environmental standards
and regulations will be approximately:
. $88 million in 2001,
. $40 million in 2002, and
. $7 million in 2003.
Clean Air
The Federal Clean Air Act regulates health and welfare standards for
concentrations of air pollutants. Under this Act, each state must set limits on
all major sources of these pollutants in its state so that the standards are
not exceeded. We have certain emission or operational limits which include
limits on sulfur content in fuel, releases of nitrogen oxides (NOx) emissions,
release of particulate matter, facility design, or operational parameters
imposed by either a federal or state agency on our generating units for the
purpose of air quality control and compliance with existing air quality
regulations.
The Clean Air Act of 1990 contains two titles designed to reduce emissions
of sulfur dioxides and NOx from certain electric generating stations--Title IV
and Title I.
Title IV addresses emissions of sulfur dioxides. For our older plants, we
meet the requirements of Title IV through a combination of switching fuels and
allowance trading. For newer plants, we meet the requirements of Title IV
primarily through facility design, and operational and pollution controls.
Title I addresses emissions of NOx. The Maryland Department of the
Environment (MDE) has issued regulations, effective October 18, 1999, which
required up to 65% NOx emissions reductions by May 1, 2000. We entered into a
settlement agreement with the MDE since we could not meet this deadline. Under
the terms of the settlement agreement, we 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 reductions by 22 states (including
Maryland and Pennsylvania). Maryland and Pennsylvania expect to meet the
requirements of the rule by 2003. The emissions reduction equipment
installations discussed above will allow us to meet these requirements in
Maryland. The generating plants in Pennsylvania also will install emissions
reduction equipment by 2003 to meet the 85% reduction requirements.
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 $150 million. Through December 31, 2000, we have spent
approximately $115 million to meet the 65% reduction requirements. We estimate
the additional cost for the EPA's 85% reduction requirements to be
approximately $90 million by 2003. These amounts will be paid by our domestic
merchant energy business.
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 appealed
16
the 1999 court rulings to the Supreme Court. In February 2001, the Supreme
Court upheld EPA's authority to issue the standards. However, the Supreme Court
sent the case back to the lower court and EPA for further proceedings on
implementation issues related to the revised ozone standard. The lower court
will also address remaining challenges to the fine particulate standard. While
these standards may require increased controls at the fossil generating plants
in the future, implementation, if required, would be delayed for several years.
We cannot estimate the cost of these increased controls at this time because
the states, including Maryland, Pennsylvania, and California still need to
determine what reductions in pollutants will be necessary to meet the EPA
standards.
In December 2000, the EPA issued a determination that coal-fired power plant
mercury emissions will be controlled. Final regulations are expected to be
issued in 2004 with controls required by 2007. The costs of these controls
cannot be estimated at this time since the level of control or systems to
implement them have not yet been established.
We received letters from the EPA requesting us to provide certain
information under Section 114 of the federal Clean Air Act regarding some of
our electric generating plants. This information is to determine compliance
with the Clean Air Act and state implementation plan requirements, including
potential application of federal New Source Performance Standards. In general,
such standards can require the installation of additional air pollution control
equipment upon the major modification of an existing plant. We have provided
the EPA the requested information. We believe our generating plants have been
operated in accordance with the Clean Air Act and the rules implementing the
Clean Air Act. However, we cannot estimate the impact of this inquiry on our
generating plants, and our financial results, at this time.
Water
Each state regulates the discharge of process wastewater and certain stormwater
discharges into its waters under the National Pollutant Discharge Elimination
System permit program. This program was established as part of the Federal
Clean Water Act. At the present time, we have the required permits under the
program for all of our electric generating plants.
The water quality regulations require us to, among other things, define
procedures to determine compliance with each state's water quality standards.
These procedures require extensive studies involving sampling and monitoring of
the waters around affected generating plants. Each state may require changes in
plant operations. We continually perform studies to determine whether any
changes will be necessary to comply with these regulations.
Waste Disposal
The EPA has regulations for implementing the portions of the Resource
Conservation and Recovery Act that deal with the management of hazardous
wastes. These regulations, and the Hazardous and Solid Waste Amendments of
1984, identify certain spent materials as hazardous wastes and establish
standards and requirements for those who generate, transport, store, or dispose
of such wastes. States have adopted regulations governing the management of
hazardous wastes that are similar to the EPA regulations and in some cases more
stringent. We have procedures in place to comply with all applicable EPA and
state regulations governing the management of hazardous wastes. Some high
volume utility wastes, such as coal fly ash and bottom ash, are exempt from
these regulations. We currently use all of our coal fly ash and bottom ash in a
manner consistent with federal, state, and local laws and regulations. These
include the use of ash as structural fill material, and recycled material that
can be sold to the construction industry for a number of other approved uses.
We also deposit ash in landfills. We continue to evaluate various recycling
opportunities for our coal fly ash and bottom ash.
The Federal Comprehensive Environmental Response, Compensation and Liability
Act (Superfund statute) establishes liability for the cleanup of hazardous
wastes that contaminate the soil, water, or air. Those who generated,
transported, or deposited the waste at the contaminated site are each jointly
and severally liable for the cost of the cleanup, as are the current property
owner and the owner when the contamination occurred. Many states have
implemented laws similar to the Superfund statute.
The EPA and several state agencies have notified us that we are considered a
potentially responsible party with respect to the cleanup of certain
environmentally contaminated sites owned and operated by others. We cannot
estimate the cleanup costs for all of these sites.
In the early 1970s, we shipped an unknown number of scrapped transformers to
Metal Bank of America, a metal reclaimer in Philadelphia. Metal Bank's scrap
and storage yard has been found to be contaminated with oil containing high
levels of PCBs (hazardous chemicals frequently used as a fire-resistant coolant
in electrical equipment). On December 7, 1987, the EPA notified us and nine
other utilities that we are considered potentially responsible parties (PRPs)
with respect to the cleanup of the site. We, along with the other PRPs,
17
submitted a remedial investigation and feasibility study (RI/FS) to the EPA on
October 14, 1994, and the EPA issued its Record of Decision (ROD) on December
31, 1997. On June 26, 1998, the EPA ordered us, the other utility PRPs, and the
owner/operator to implement the requirements of the ROD. The utility PRPs are
currently conducting the remedial design. Based on the ROD, our share of the
reasonably possible cleanup costs, estimated to be approximately 15.47%, could
be as much as $2.3 million higher than amounts we have recorded as a liability
on our Consolidated Balance Sheets.
On October 16, 1989, the EPA filed a complaint in the U.S. District Court
for the District of Maryland under the Superfund statute against us and seven
other defendants to recover past and future expenditures associated with the
cleanup of a site located at Kane and Lombard Streets in Baltimore. The State
of Maryland filed a similar complaint in the same case and court on February
12, 1990. The complaints alleged that we arranged for our coal fly ash to be
deposited on the site. The Court dismissed these complaints in November 1995.
The MDE began additional investigation on the remainder of the site for the
EPA, but never completed the investigation. We, along with three other
defendants, agreed to complete the RI/FS of groundwater contamination around
the site in a July 1993 consent order. The remedial action, if any, for the
remainder of the site will not be selected until these investigations are
concluded. Therefore, we cannot estimate the total amount, or our share, of the
site cleanup costs.
From 1985 until 1989, we shipped waste oil and other materials to the
Industrial Solvents and Chemical Company in York County, Pennsylvania for
disposal. The Pennsylvania Department of Environmental Protection (PADEP)
subsequently investigated this site and found it to be heavily contaminated by
hazardous wastes. The PADEP notified us on August 15, 1990, that approximately
1,000 other entities and we are PRPs with respect to the cost of all remedial
activities to be conducted at the site. The PRPs have performed waste
characterization, removed and disposed of all tanks and drums of waste,
completed a RI/FS at the site, and installed public water lines. In 1998, PADEP
notified BGE and other PRPs of the final remedy and requested the installation
of additional public water lines. In 1999, the PRPs installed the water lines
and PADEP approved the final report in March 2000. We have no further
obligations under the consent orders at the site.
In December 1995, the EPA notified us that we are one of approximately 650
parties that may have incurred liability under the Superfund statute for
shipments of hazardous wastes to a site in Denver, Colorado known as the RAMP
Industries site. We, through our disposal vendor, shipped a small amount of low
level radioactive waste to the site between 1989 and 1992. The site, which was
found to have been operated improperly, was closed in 1994. That same year, the
EPA began cleaning up the site by removing drums of radioactive and hazardous
mixed wastes. BGE accepted a settlement offer from EPA in August 1999, whereby
BGE will pay an immaterial amount to resolve its liability at this site. The
consent order will be finalized in 2001.
In September 1996, we received an information request from the EPA about the
Drumco Drum Dump Site, located in the Curtis Bay area of Maryland. This site
was the subject of an emergency drum removal action in 1991, due to a concern
about hazardous substances leaking from drums and posing a threat to human
health and the environment. According to EPA documents, approximately $2
million was spent on the drum removal action. To our knowledge, no long-term
remediation is planned for this site. In addition, we understand that the EPA
has sent information requests to approximately 17 other parties. Our records
indicate that we sold empty drums to Drumco, Inc. from approximately 1983-1990.
Although our potential liability cannot be estimated, we do not expect such
liability to be material based on our records showing that we sold only empty
storage drums to Drumco, Inc.
On July 12, 1999, the EPA notified us, along with 19 other entities, that we
may be a potentially responsible party at the 68th Street Dump/Industrial
Enterprises Site, also known as the Robb Tyler Dump, located in Baltimore,
Maryland. The EPA indicated that it is proceeding with plans to conduct a
remedial investigation and feasibility study. This site was proposed for
listing as a federal Superfund site in January 1999, but the listing has not
been finalized. Although our potential liability cannot be estimated, we do not
expect such liability to be material based on our records showing that we did
not send waste to the site.
In the early part of the century, predecessor gas companies (which were
later merged into BGE) manufactured coal gas for residential and industrial
use. The residue from this manufacturing process was coal tar, previously
thought to be harmless but now found to contain a number of chemicals
designated by the EPA as hazardous substances. We are coordinating an
investigation of some of these former manufacturing sites, and determining
what, if any, remedial action may be required by MDE.
In late December 1996, we signed a consent order with the MDE that requires
us to implement remedial action plans for contamination at and around the
Spring Gardens site, located in Baltimore,
18
Maryland. We submitted the required remedial action plans and they have been
approved by the MDE. Based on the remedial action plans, the costs we consider
to be probable to remedy the contamination are estimated to total $47 million
in nominal dollars (including inflation). We have recorded these costs as a
liability on our Consolidated Balance Sheets and have deferred these costs, net
of accumulated amortization and amounts we recovered from insurance companies,
as a regulatory asset. We discuss this further in Note 5 to Consolidated
Financial Statements. Through December 31, 2000, we have spent approximately
$35 million for remediation at this site.
We are also required by accounting rules to disclose additional costs we
consider to be less likely than probable, but still "reasonably possible" of
being incurred at these sites. Because of the results of studies at these
sites, it is reasonably possible that these additional costs could exceed the
amount we recognized by approximately $14 million in nominal dollars ($7
million in current dollars, plus the impact of inflation at 3.1% over a period
of up to 36 years).
Employees
As of December 31, 2000, we employed about 7,800 people.
- --------------------------------------------------------------------------------
Item 2. Properties
We lease several properties that are used for Constellation Energy's
headquarters, various offices, and services. We own BGE's principal
headquarters building in downtown Baltimore.
We describe our electric generation properties in the Domestic Merchant
Energy Business section.
We own the following propane air and liquefied natural gas facilities:
. a liquefied natural gas facility for the liquefaction and storage of
natural gas with a total storage capacity of 1,000,000 DTH and a planned
daily capacity of 287,988 DTH, and
. a propane air facility with a mined cavern with a total storage capacity
of 500,000 DTH and a planned daily capacity of 85,000 DTH.
We also have rights-of-way to maintain 26-inch natural gas mains across
certain Baltimore City owned property (principally parks) which expire in 2004.
These rights-of-way can be renewed during their last year for an additional
period of 25 years based on a fair revaluation. Conditions of the grants are
satisfactory.
property.
All of BGE's property and the electric generation assets that were
transferred by BGE to our domestic merchant energy business as part of
deregulation, are subject to the lien of BGE's mortgage securing its mortgage
bonds.
- --------------------------------------------------------------------------------
Item 3. Legal Proceedings
In the normal course of business, we are involved in various legal proceedings.
We discuss our legal proceedings in Note 10 to Consolidated Financial
Statements.
19
Item 4. Submission of Matters to Vote of Security Holders
Not applicable.
Executive Officers of the Registrant
BGE meets the conditions set forth in General Instruction I(1)(a) and (b) of
Form 10-K for a reduced disclosure format. Accordingly, the executive officers
of BGE are not presented below.
Executive Officers of Constellation Energy Group at the date of this report
are:
Other Offices or Positions
Name Age Present Office Held During Past Five Years
---- --- -------------- ---------------------------
Christian H. Poindexter 62 Chairman of the Board and Chief Chairman of the Board,
Executive Officer (A) (Since President, and Chief
formation of Constellation Executive Officer--
Energy Group as the holding Constellation Energy and
company on April 30, 1999; since BGE
March 1, 1998 for BGE)
Edward A. Crooke 62 Vice Chairman (B) (Since October Vice Chairman--Constellation
20, 2000) Energy, Chairman of the
Board, President and Chief
Executive Officer--
Constellation Enterprises,
Inc., Chairman of the
Board--Constellation
Holdings, Inc., and
President and Chief
Operating Officer--BGE
Eric P. Grubman 43 Co-President (Since October 20, Partner and Managing
2000) Director, Co-Head of Energy
& Power--Goldman Sachs &
Co.
Charles W. Shivery 55 Co-President (Since October 20, Chairman of the Board and
2000) Chief Executive Officer--
President and Chief Executive Constellation Energy
Officer, Constellation Power Source, Inc., Vice
Source Holdings, Inc. (since President, Chief Financial
July 1, 2000), Officer & Secretary--BGE
CEO and President, Constellation
Enterprises, Inc. (since 1998),
Chairman of the Board,
President, and Chief Executive
Officer, Constellation Power
Source, Inc. (since 1997)
Robert E. Denton 58 President and Chief Executive Executive Vice President,
Officer of Constellation Generation--BGE, Senior
Nuclear, LLC (since July 1, 2000) Vice President,
Generation--BGE
Frank O. Heintz 57 President and Chief Executive Executive Vice President,
Officer of Baltimore Gas and Utility Operations--BGE,
Electric Company (since July 1, Vice President, Gas--BGE.
2000)
Thomas F. Brady 51 Vice President Corporate Strategy Vice President, Retail
and Development (Since formation Services--BGE, Vice
of Constellation Energy Group as President, Customer Service
the holding company on April 30, and Distribution--BGE
1999; since January 1, 1999 for
BGE)
David A. Brune 60 Vice President Finance and General Counsel--BGE
Accounting, Chief Financial
Officer and Secretary (Since
formation of Constellation
Energy Group as the holding
company on April 30, 1999; since
February 25, 1997 for BGE)
20
Other Offices or Positions
Name Age Present Office Held During Past Five Years
---- --- -------------- ---------------------------
Robert S. Fleishman 47 Vice President Corporate Affairs General Counsel--BGE,
and General Counsel (Since Associate General Counsel--
formation of Constellation Regulatory at BGE
Energy Group as the holding
company on April 30, 1999; since
May 1, 1998 for BGE)
Janet E. McHugh 43 Vice President Human Resources Deputy General Counsel and
(Since June 1, 2000) Manager, Legal Department--
Constellation Energy,
Associate General Counsel--
Commercial Unit--BGE
(A) Chief Executive Officer, Director, and member of the Executive
Committee.
(B) Director and member of the Executive Committee, Long-Range Strategy
Committee, and Risk Management Committee.
Officers of Constellation Energy Group are elected by, and hold office at
the will of, the Board of Directors and do not serve a "term of office" as
such. There is no arrangement or understanding between any director or officer
and any other person pursuant to which the director or officer was selected.
- --------------------------------------------------------------------------------
PART II
Item 5. Market for Registrant's Common Equity and Related Shareholder Matters
Stock Trading
Constellation Energy's common stock is traded under the ticker symbol CEG. It
is listed on the New York, Chicago, and Pacific stock exchanges. It has
unlisted trading privileges on the Boston, Cincinnati, and Philadelphia
exchanges.
As of February 28, 2001, there were 58,650 common shareholders of record.
Dividend Policy
Constellation Energy pays dividends on its common stock after its Board of
Directors declares them. There is no limitation on Constellation Energy paying
common stock dividends.
BGE pays dividends on its common stock after its Board of Directors declares
them. There is no limitation on BGE paying common stock dividends unless:
. BGE elects to defer interest payments on the 7.16% Deferrable Interest
Subordinated Debentures due June 30, 2038, and any deferred interest
remains unpaid; or
. all dividends (and any redemption payments) due on BGE's preference stock
have not been paid.
Dividends have been paid on the common stock continuously since 1910. Future
dividends depend upon future earnings, our financial condition, and other
factors. Effective April 2001, our annual dividend is expected to be set at
$.48 per share ($.12 quarterly). Upon separation, BGE Corp. expects to pay
initial annual dividends of $.48 per share, and Constellation Energy Group, as
a growing merchant energy company, initially expects to reinvest its earnings
in order to fund its growth plans and not to pay a dividend.
Quarterly dividends were declared on the common stock during 2000 and 1999
in the amounts set forth below. Dividends paid prior to April 30, 1999 were on
BGE common stock. As a result of the share exchange, Constellation Energy is
the successor of BGE.
- --------------------------------------------------------------------------------
Common Stock Dividends and Price Ranges
2000 1999
---------------------- ----------------------
Price* Price*
Dividend ------------- Dividend -------------
Declared High Low Declared High Low
-------- ------ ------ -------- ------ ------
First Quarter..................... $ .42 $33.81 $27.06 $ .42 $31.13 $24.69
Second Quarter.................... .42 35.69 31.25 .42 31.38 25.13
Third Quarter..................... .42 52.06 32.06 .42 30.88 27.19
Fourth Quarter.................... .42 50.50 37.88 .42 31.50 27.50
----- -----
Total............................. $1.68 $1.68
===== =====
* Based on New York Stock Exchange Composite Transactions as reported in THE
WALL STREET JOURNAL.
21
Item 6. SELECTED FINANCIAL DATA
Constellation Energy Group Inc., and Subsidiaries
2000 1999 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------------------------
(Dollar amounts in millions, except per share amounts)
Summary of Operations
Total Revenues $ 3,878.5 $3,786.2 $3,386.4 $3,307.6 $3,153.2
Total Expenses 3,038.3 3,026.3 2,647.9 2,584.0 2,483.7
- ----------------------------------------------------------------------------------------------------------------------------
Income From Operations 840.2 759.9 738.5 723.6 669.5
Other Income (Expense) 6.6 7.9 5.7 (52.8) 6.1
- ----------------------------------------------------------------------------------------------------------------------------
Income Before Fixed Charges and Income Taxes 846.8 767.8 744.2 670.8 675.6
Fixed Charges 271.4 255.0 260.6 258.7 237.0
- ----------------------------------------------------------------------------------------------------------------------------
Income Before Income Taxes 575.4 512.8 483.6 412.1 438.6
Income Taxes 230.1 186.4 177.7 158.0 166.3
- ----------------------------------------------------------------------------------------------------------------------------
Income Before Extraordinary Item 345.3 326.4 305.9 254.1 272.3
Extraordinary Loss, Net of Income Taxes -- (66.3) -- -- --
- ----------------------------------------------------------------------------------------------------------------------------
Net Income $ 345.3 $ 260.1 $ 305.9 $ 254.1 $ 272.3
============================================================================================================================
Earnings Per Share of Common Stock and
Earnings Per Share of Common Stock--
Assuming Dilution Before Extraordinary Item $ 2.30 $ 2.18 $ 2.06 $ 1.72 $ 1.85
Extraordinary Loss, Net of Income Taxes -- (.44) -- -- --
- ----------------------------------------------------------------------------------------------------------------------------
Earnings Per Share of Common Stock and
Earnings Per Share of Common Stock--
Assuming Dilution $ 2.30 $ 1.74 $ 2.06 $ 1.72 $ 1.85
============================================================================================================================
Dividends Declared Per Share of Common Stock $ 1.68 $ 1.68 $ 1.67 $ 1.63 $ 1.59
============================================================================================================================
Summary of Financial Condition
Total Assets $12,384.6 $9,683.8 $9,434.1 $8,900.0 $8,678.2
============================================================================================================================
Capitalization
Long-term debt $ 3,159.3 $2,575.4 $3,128.1 $2,988.9 $2,758.8
Redeemable preference stock -- -- -- 90.0 134.5
Preference stock not subject to mandatory
redemption 190.0 190.0 190.0 210.0 210.0
Common shareholders' equity 3,153.0 2,993.0 2,981.5 2,870.4 2,854.7
- ----------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 6,502.3 $5,758.4 $6,299.6 $6,159.3 $5,958.0
============================================================================================================================
Financial Statistics at Year End
Ratio of Earnings to Fixed Charges 2.78 2.87 2.60 2.35 2.44
Book Value Per Share of Common Stock $ 20.95 $ 20.01 $ 19.98 $ 19.44 $ 19.33
Number of Common Shareholders (In Thousands) 60.1 66.1 69.9 73.7 77.6
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
22
Baltimore Gas and Electric Company and Subsidiaries
2000 1999 1998 1997 1996
- ----------------------------------------------------------------------------------------------------------------------------
(Dollar amounts in millions, except per share amounts)
Summary of Operations
Total Revenues $ 2,746.8 $3,092.2 $3,386.4 $3,307.6 $3,153.2
Total Expenses 2,336.7 2,387.9 2,647.9 2,584.0 2,483.7
- ----------------------------------------------------------------------------------------------------------------------------
Income From Operations 410.1 704.3 738.5 723.6 669.5
Other Income (Expense) 9.8 8.4 5.7 (52.8) 6.1
- ----------------------------------------------------------------------------------------------------------------------------
Income Before Fixed Charges and Income Taxes 419.9 712.7 744.2 670.8 675.6
Fixed Charges 184.0 205.9 238.8 230.0 198.5
- ----------------------------------------------------------------------------------------------------------------------------
Income Before Income Taxes 235.9 506.8 505.4 440.8 477.1
Income Taxes 92.4 178.4 177.7 158.0 166.3
- ----------------------------------------------------------------------------------------------------------------------------
Income Before Extraordinary Item 143.5 328.4 327.7 282.8 310.8
Extraordinary Loss, Net of Income Taxes -- (66.3) -- -- --
- ----------------------------------------------------------------------------------------------------------------------------
Net Income 143.5 262.1 327.7 282.8 310.8
Preference Stock Dividends 13.2 13.5 21.8 28.7 38.5
- ----------------------------------------------------------------------------------------------------------------------------
Earnings Applicable to Common Stock $ 130.3 $ 248.6 $ 305.9 $ 254.1 $ 272.3
============================================================================================================================
Summary of Financial Condition
Total Assets $ 4,654.2 $7,272.6 $9,434.1 $8,900.0 $8,678.2
============================================================================================================================
Capitalization
Long-term debt $ 1,864.4 $2,206.0 $3,128.1 $2,988.9 $2,758.8
Redeemable preference stock -- -- -- 90.0 134.5
Preference stock not subject to mandatory
redemption 190.0 190.0 190.0 210.0 210.0
Common shareholders' equity 802.3 2,355.4 2,981.5 2,870.4 2,854.7
- ----------------------------------------------------------------------------------------------------------------------------
Total Capitalization $ 2,856.7 $4,751.4 $6,299.6 $6,159.3 $5,958.0
============================================================================================================================
Financial Statistics at Year End
Ratio of Earnings to Fixed Charges 2.27 3.45 2.94 2.78 3.10
Ratio of Earnings to Combined Fixed Charges and
Preferred and Preference Stock Dividends 2.03 3.14 2.60 2.35 2.44
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
23
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
INTRODUCTION
On April 30, 1999, Constellation Energy(R) Group, Inc. (Constellation Energy)
became the holding company for Baltimore Gas and Electric Company (BGE(R)) and
Constellation(R) Enterprises, Inc. Constellation Enterprises was previously
owned by BGE.
This report is a combined report of Constellation Energy and BGE. 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.
Constellation Energy's subsidiaries primarily include a domesti