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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 1-1910
DECEMBER 31, 1998 Commission file number
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BALTIMORE GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
MARYLAND 52-0280210
(State of incorporation) (I.R.S. Employer Identification No.)
39 W. LEXINGTON STREET, 21201
BALTIMORE, MARYLAND (Zip Code)
(Address of principal
executive offices)
410-783-5920
(Registrant's 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
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New York Stock Exchange, Inc.
Common Stock -- Without Par Value Chicago Stock Exchange, Inc.
} Pacific Stock Exchange, Inc.
7.16% Trust Originated Preferred Securities
($25 liquidation amount per preferred security)
issued by BGE Capital Trust I, fully and } New York Stock Exchange, Inc.
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 registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months, and (2) has 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 registrant's 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. [ ]
Aggregate market value of Common Stock, without par value, held by
non-affiliates as of February 26, 1999 was approximately $3,823,612,000 based
upon New York Stock Exchange composite transaction closing price.
COMMON STOCK, WITHOUT PAR VALUE -- 149,556,416 SHARES OUTSTANDING ON FEBRUARY
26, 1999.
DOCUMENTS INCORPORATED BY REFERENCE
PART OF FORM 10-K DOCUMENT INCORPORATED BY REFERENCE
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III Certain sections of the Proxy Statement/Prospectus on Form
S-4 for a share exchange between Constellation Energy Group,
Inc. and the common shareholders of Baltimore Gas and
Electric Company and the Annual Meeting of Shareholders of
Baltimore Gas and Electric Company to be held on April 16,
1999 (Proxy Statement).
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TABLE OF CONTENTS
PAGE
--------
FORWARD LOOKING STATEMENTS ................................ 1
PART I
Item 1 -- Business
Overview of Consolidated Business .......... 1
Electric Business
Electric Regulatory Matters and
Competition ................................ 3
Electric Rate Matters ...................... 4
Nuclear Operations ......................... 5
Electric Load Management, Energy,
and Capacity Purchases ..................... 5
Fuel for Electric Generation ............... 6
Electric Operating Statistics .............. 8
Gas Business
Gas Regulatory Matters and
Competition ................................ 9
Gas Operations ............................. 9
Gas Rate Matters ........................... 10
Gas Operating Statistics ................... 11
Franchises ................................. 12
Diversified Businesses ..................... 12
Consolidated Capital Requirements .......... 14
Environmental Matters ...................... 14
Employees .................................. 17
Item 2 -- Properties ................................. 17
Item 3 -- Legal Proceedings .......................... 18
Item 4 -- Submission of Matters to a Vote of
Security Holders ........................... 19
Executive Officers of the Registrant
(Instruction 3 to Item 401(b) of
Regulation S-K) ............................ 20
PAGE
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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 ................................. 23
Item 7A -- Quantitative and Qualitative
Disclosures About Market Risk .............. 39
Item 8 -- Financial Statements and
Supplementary Data ......................... 39
Item 9 -- Changes in and Disagreements with
Accountants on Accounting and
Financial Disclosure ....................... 69
PART III
Item 10 -- Directors and Executive Officers of the
Registrant ................................. 69
Item 11 -- Executive Compensation ..................... 69
Item 12 -- Security Ownership of Certain
Beneficial Owners and Management ........... 69
Item 13 -- Certain Relationships and Related
Transactions ............................... 69
PART IV
Item 14 -- Exhibits, Financial Statement Schedules
and Reports on Form 8-K .................... 70
Signatures .............................................. 74
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:
o general economic, business, and regulatory conditions,
o energy supply and demand,
o competition,
o federal and state regulations,
o availability, terms, and use of capital,
o nuclear and environmental issues,
o weather,
o industry restructuring and cost recovery (including the potential effect
of stranded investments),
o commodity price risk, and
o year 2000 readiness.
Given these uncertainties, you should not place undue reliance on these
forward looking statements. Please see the other sections of this report and
our other periodic reports filed with the Securities and Exchange Commission
for more information on these factors. These forward looking statements
represent our estimates and assumptions only as of the date of this report.
PART I
ITEM 1. BUSINESS
OVERVIEW OF CONSOLIDATED BUSINESS
Baltimore Gas and Electric Company (BGE(R)) is the parent company and
conducts our primary business -- the electric and gas utility business. We also
conduct diversified businesses in subsidiary companies.
BGE was incorporated under the laws of the State of Maryland on June 20,
1906.
BGE also owns two-thirds of the outstanding capital stock, including
one-half of the voting stock, of Safe Harbor Water Power Corporation (Safe
Harbor). Safe Harbor is a producer of hydroelectric power on the Susquehanna
River at Safe Harbor, Pennsylvania. We discuss this further in ITEM 2.
PROPERTIES -- ELECTRIC.
OVERVIEW OF UTILITY BUSINESS
Our utility business includes our electric and gas businesses. Our
electric business generates, purchases, and sells electricity. Our gas business
purchases, transports, and sells natural gas. The focus of these activities is
serving residential, commercial, and industrial customers in our service
territory.
We furnish electric and gas retail services in the City of Baltimore and
in all or part of ten counties in Central Maryland. Our electric service
territory includes an area of approximately 2,300 square miles with an
estimated population of 2.7 million. Our gas service territory includes an area
of more than 600 square miles with an estimated population of 2.0 million.
There are no municipal or cooperative wholesale customers within our service
territory.
As discussed throughout this report, the two units at our Calvert Cliffs
Nuclear Power Plant (Calvert Cliffs) are our principal generating facilities
and have the lowest fuel cost in our system. An extended outage of either of
these units could have a substantial adverse effect on our business and
financial condition. We describe prior outages at our nuclear plant in the
NUCLEAR OPERATIONS section and in NOTE 10 TO CONSOLIDATED FINANCIAL STATEMENTS.
We describe our utility business further in five other sections of this
report -- ELECTRIC BUSINESS, ELECTRIC OPERATING STATISTICS, GAS BUSINESS, GAS
OPERATING STATISTICS, and FRANCHISES.
COMPETITION AND RESPONSE TO REGULATORY CHANGE
The electric utility industry is undergoing rapid and substantial
change. Competition in the generation part of our business is increasing. In
the natural gas industry, competition and regulatory changes are well under
way. The regulatory environment (federal and state) for both electric and
natural gas is shifting toward customer choice. In response to this change, we
regularly reevaluate our strategies with two goals in mind: to improve our
competitive position, and to anticipate and adapt to regulatory changes. These
strategies might include one or more of the following:
o the complete or partial separation of our generation, transmission, and
distribution functions,
o purchase or sale of generation assets,
o mergers or acquisitions of utility or non-utility businesses,
o spin-off or sale of one or more businesses, and
o growth of earnings from nonregulated businesses.
We cannot predict whether any of the strategies described above may
actually occur, or what their effect on our financial condition or competitive
position might be. Please refer to the FORWARD LOOKING STATEMENTS section.
1
We expect to form a holding company, Constellation Energy Group, Inc.,
on or about April 30, 1999 and it will be exempt from registration under the
Public Utility Holding Company Act of 1935. Maryland law was recently amended
to allow public utility companies incorporated in Maryland to form holding
companies. We have applied for and received approvals to form our holding
company with the Federal Energy Regulatory Commission (FERC), the Nuclear
Regulatory Commission (NRC), and the Pennsylvania Public Utility Commission. In
addition, we must receive shareholder approval at our annual meeting scheduled
for April 16, 1999.
In addition, our Board of Directors has a Long-Range Strategy Committee to
oversee the development of our long-range strategic goals, and to consider
strategic initiatives presented by management. We also recently formed a
Corporate Strategy and Development Group, led by a Vice President, that is
responsible for evaluating strategic objectives and developing strategy
implementation.
We discuss competition in our electric and gas businesses in more detail
in the ELECTRIC REGULATORY MATTERS AND COMPETITION and GAS REGULATORY MATTERS
AND COMPETITION sections.
OVERVIEW OF DIVERSIFIED BUSINESSES
In the 1980s, we began to diversify our business in response to limited
growth in gas and electric sales. Today, we continue to diversify our business
in response to regulatory changes in the utility industry. Our diversified
businesses engage primarily in energy services. Our energy services businesses
include certain subsidiaries of Constellation(R) Enterprises, Inc. and the
District Chilled Water General Partnership (ComfortLink(R)), a general
partnership in which BGE is a partner. They are:
o Constellation Power Source(TM), Inc. -- our wholesale power marketing and
trading business,
o Constellation Power(TM), Inc. and Subsidiaries -- our power projects
business,
o Constellation Energy Source(TM), Inc. -- our energy products and services
business,
o BGE Home Products & Services(TM), Inc. and Subsidiaries -- our home
products, commercial building systems, and residential and small
commercial gas retail marketing business, and
o ComfortLink -- our cooling services business for commercial customers in
Baltimore.
Constellation Enterprises, Inc. also has two other subsidiaries:
o Constellation Investments(TM), Inc. -- our financial investments business,
and
o Constellation Real Estate Group(TM), Inc. -- our real estate and
senior-living facilities business.
We describe our diversified businesses in more detail in the DIVERSIFIED
BUSINESSES section.
REVENUES AND NET INCOME BY OPERATING SEGMENT
The percentages of revenues and net income attributable to our electric,
gas, and diversified businesses are shown in the tables below. We present
information about our operating segments, including certain non-recurring
items, in NOTE 2 TO CONSOLIDATED FINANCIAL STATEMENTS.
REVENUES*
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ELECTRIC GAS DIVERSIFIED
---------- ----- --------------------------
ENERGY SERVICES OTHER
----------------- ------
1998 ......... 66% 13% 16% 5%
1997 ......... 66 16 12 6
1996 ......... 70 16 10 4
1995 ......... 76 14 6 4
1994 ......... 76 15 5 4
NET INCOME*
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ELECTRIC GAS DIVERSIFIED
---------- ------- --------------------------------
ENERGY SERVICES OTHER
----------------- ------------
1998 ......... 85% 9% 13% (7)%
1997 ......... 88 10 10 (8)
1996 ......... 74 11 10 5
1995 ......... 85 7 6 2
1994 ......... 88 6 6 --
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* Reflects the elimination of intercompany transactions.
The differences in percentages of revenues and net income for our
electric and gas businesses are due to two factors:
o our level of investment in each business, and
o our fuel costs in each business.
Our electric and gas revenues reflect amounts collected for fuel and
other operating expenses plus a return on our investment. Our investment for
ratemaking purposes in the electric business is $4.7 billion and our investment
for ratemaking purposes in the gas business is approximately $707 million. As a
result, our electric revenues include a much higher return component than our
gas revenues.
Also, as shown in our Consolidated Statements of Income in ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, our electric fuel costs ("Electric
fuel and purchased energy") were 23% of electric revenues in 1998, and our
purchased gas costs ("Gas purchased for resale") were 46% of gas revenues in
1998. This means our cost of fuel in relation to our revenues is lower in the
electric business than in the gas business.
2
We charge the actual cost of the fuel we use to generate electricity and
the net cost of purchases and sales of electricity to customers with no profit
to us. The price we charge for natural gas is based on a market based rates
incentive mechanism approved by the Maryland PSC . The difference between our
actual cost and the price we charge under market based rates does not
significantly impact earnings. We discuss market based rates further in the GAS
REGULATORY MATTERS AND COMPETITION section.
Our electric and gas revenues come from many customers -- residential,
commercial, and industrial. Our largest electric customer provides 2.3% of our
total electric revenues. Our largest gas customer provides 1.5% of our total
gas revenues.
As shown in the tables on page 2, the percentages for revenues and net
income have historically been about the same for our diversified businesses.
However, in 1998 and 1997, the percentages differ for our other diversified
businesses because our real estate and senior-living facilities business wrote
down its investments in certain real estate projects. These write-downs reduced
net income by about $15.4 million in 1998 and $46.0 million in 1997. We discuss
these write-downs further in NOTE 3 TO CONSOLIDATED FINANCIAL STATEMENTS.
ELECTRIC BUSINESS
We get most of our revenues and net income from our electric utility
business. We describe this business in several sections below.
ELECTRIC REGULATORY MATTERS
AND COMPETITION
Electric utilities are facing competition on various fronts, including:
o the construction of generating units to meet increased demand for
electricity,
o the sale of electricity in bulk power markets,
o competing with alternative energy suppliers, and
o electric sales to retail customers.
In recent years, federal and state initiatives have promoted the
development of competition in the sale of electricity. In general, these
initiatives have sought to unbundle the integrated services that electric
utilities have traditionally provided and to enable customers to purchase
electricity directly from suppliers other than their local utilities.
FEDERAL INITIATIVES
With the passage of the Energy Policy Act of 1992, there has been a
significant increase in the level of competition for the generation and sale of
electricity to wholesale customers. The Energy Policy Act reduces barriers to
market entry for companies that wish to build, own, and operate electric
generating facilities. It also promotes competition by authorizing the FERC to
require electric utilities to provide transmission service to other companies
for wholesale power transactions. In 1996, the FERC issued an order requiring
electric utilities to make the utility transmission systems available to
wholesale sellers and buyers of electric energy on a non-discriminatory basis.
This means that other companies may use our transmission system to transport
electricity to their customers.
Also, we are a member of the PJM (Pennsylvania-New Jersey-Maryland)
Interconnection, which is an independent system operator that controls and
operates electric transmission facilities in our region as an integrated system
on a non-discriminatory basis. The PJM provides open access to the transmission
facilities of all of its members based on tariffs filed with the FERC.
STATE INITIATIVES
At the retail level, many states are implementing "customer choice"
programs giving electric retail customers the option to choose among energy
suppliers. Maryland is considering offering a customer choice program beginning
in July 2000. Presently, the single electric utility company that holds the
franchise for the area of Maryland where a retail customer lives serves that
customer. Under customer choice, we would continue to transmit and deliver
electricity; however, the customer could contract to buy the electricity from
any willing supplier. From our perspective, this means that transmission and
distribution of electricity will remain regulated services and the generation
of electricity will become a competitive service.
There are many issues associated with moving from a regulated generation
market to a competitive generation market. These issues include, among others:
o the recovery of stranded investments1 by electric utilities,
o adjusting the tax burden so as not to penalize electric utilities'
current generating assets in a competitive market,
o how to address the needs of low income customers, and
o the need to maintain reliable electric service.
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1 Stranded investments are costs a utility would recover under a regulated
pricing system, but not a competitive one. Traditionally, utilities have been
required to serve all customers in their franchised area while regulators have
set the rates customers pay for that service. To meet customers' demand for
electricity, utilities have had to build facilities, including generating
plants, and enter into contracts to buy power, among other things, all with the
approval of the Maryland PSC.
Under customer choice, however, the market will set the price for electricity,
not regulators. That means if the market price drops below the current
regulated price, the utility may not be able to fully recover its investments
in facilities or costs under contracts to buy power and, therefore, a portion
of these costs would be "stranded."
3
MARYLAND PSC
The Maryland PSC also has addressed customer choice, recognizing,
however, that legislation is needed to resolve several issues. In a December
1997 order, the Maryland PSC specified the phase-in of customer choice in three
increments, with one-third of customers being offered choice in each increment.
The three increments are phased-in over two years from July 1, 2000 to July 1,
2002. Also pursuant to the order, in 1998 we participated in a series of
hearings and meetings with others to address the issues of customer choice
outlined on page 3.
On July 1, 1998, we filed our proposal for transition from a regulated
electric supply system to one where generation is priced based on a competitive
retail electric market. We discuss our proposal in detail in ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS -- COMPETITION AND RESPONSE TO REGULATORY
CHANGE.
On December 22, 1998, other parties filed their positions in response to
our proposal. The Maryland PSC will hold hearings to examine our proposal and
the counter-proposals of other parties. In the meantime, settlement
negotiations are ongoing. Absent settlement, the Maryland PSC is scheduled to
issue an order by October 1, 1999.
On September 3, 1998, the Office of People's Counsel (OPC) filed a
petition requesting the Maryland PSC to lower our electric base rates. At our
request, the Maryland PSC agreed to consolidate any such review of our electric
base rates with its review of our electric restructuring transition proposal
mentioned above. We filed testimony and exhibits with the Maryland PSC
supporting our position that our current electric base rates are justified. On
February 5, 1999, other parties, including the OPC, filed testimonies to lower
our base rates by as much as $131 million. As a condition of the Maryland PSC's
consolidation of these matters, we agreed to make our rates subject to refund
effective July 1, 1999 should the Maryland PSC issue a rate reduction order
after that date.
MARYLAND LEGISLATION
Several bills have been introduced in the 1999 Maryland legislative
session that would address the customer choice issues discussed under the
heading STATE INITIATIVES, in addition to other related issues. These bills
resulted from, in part, the Maryland PSC required hearings and meetings held
during 1998. The Maryland legislative session runs until mid-April 1999. We
cannot predict whether customer choice legislation will be enacted this session
or whether or not the Maryland PSC timetable for implementation of customer
choice will change.
We also cannot predict the ultimate effect competition or regulatory
change will have on our earnings.
ELECTRIC RATE MATTERS
CONSERVATION SURCHARGE
The Maryland PSC allows us to include in base rates a component to
recover money we have spent on conservation programs. This component is called
a "conservation surcharge" and was approved by the Maryland PSC effective July
1, 1992. Under this surcharge, the Maryland PSC limits what our electric
business profit can be. If, at the end of the year, we have exceeded our
allowed profit, we defer (include as a liability in our Consolidated Balance
Sheets and exclude from our Consolidated Statements of Income) the excess in
that year and we lower the amount of future surcharges to our customers to
correct the amount of overage, plus interest. The surcharge is reset on July 1
of each year. We also discuss the surcharge in ITEM 7. MANAGEMENT'S DISCUSSION
AND ANALYSIS -- REGULATION BY THE MARYLAND PUBLIC SERVICE COMMISSION
POSTRETIREMENT AND POSTEMPLOYMENT BENEFIT COSTS
Beginning in 1998, the Maryland PSC authorized us to make some changes
in the way we account for postretirement and other postemployment benefit
costs. The Maryland PSC authorized us to:
o expense all of the increase in annual postretirement benefit costs
related to our electric business, and
o amortize the regulatory asset for postretirement and other postemployment
benefit costs related to our electric business over 15 years.
The Maryland PSC authorized us to reflect these benefit cost changes in
our current electric base rates starting in 1998. We also discuss this in NOTE
5 TO CONSOLIDATED FINANCIAL STATEMENTS.
ELECTRIC FUEL RATE PROCEEDINGS
By law, we are allowed to recover our cost of electric fuel as long as
the Maryland PSC finds that, among other things, we have kept the productive
capacity of our generating plants at a reasonable level. To do this, the
Maryland PSC may perform an evaluation of each outage (other than regular
maintenance outages) at our generating plants. The evaluation will determine if
we used all reasonable and cost-effective maintenance and operating control
procedures to try to prevent the outage.
The Maryland PSC, under the Generating Unit Performance Program,
measures annually whether we have maintained the productive capacity of our
generating plants at reasonable levels. To do this, the program uses a
system-wide generating performance target and
4
an individual performance target for each base load generating unit. In fuel
rate hearings, actual generating performance adjusted for planned outages will
be compared first to the system-wide target. If that target is met, it should
mean that the requirements of Maryland law have been met. If the system-wide
target is not met, each unit's adjusted actual generating performance will be
compared to its individual performance target to determine if the requirements
of Maryland law have been met and, if not, to determine the basis for possibly
imposing a penalty on BGE. Even if we meet these targets, other parties to fuel
rate hearings may still question whether we used all reasonable and
cost-effective procedures to try to prevent an outage. If the Maryland PSC
decides we were deficient in some way, the Maryland PSC may not allow us to
recover the cost of replacement energy.
We are required to submit to the Maryland PSC the actual generating
performance data for each calendar year 45 days after year-end. The Maryland
PSC reviews the performance for each calendar year in the first fuel rate
proceeding that is initiated after the data is submitted. We must initiate fuel
rate proceedings in any month following a month during which the calculated
fuel rate decreased by more than 5% and may initiate fuel rate proceedings in
any month following a month during which the calculated fuel rate increased by
more than 5%.
NUCLEAR OPERATIONS
The two units at Calvert Cliffs use the cheapest fuel. As a result, the
costs of replacement energy associated with outages at these units can be
significant.
During 1989 through 1991 we had extended outages at Calvert Cliffs.
These outages drove up fuel costs, and resulted in fuel rate proceedings for
several years before the Maryland PSC under the Generating Unit Performance
Program, as discussed in ELECTRIC RATE MATTERS -- ELECTRIC FUEL RATE
PROCEEDINGS. In these proceedings, the Maryland PSC considered whether any
portion of the extra fuel costs should be charged to BGE instead of passed on
to customers.
In December 1996, we settled the proceedings by agreeing not to bill our
customers for $118 million of electric replacement energy costs associated with
these outages. In 1990, we wrote off $35 million of these costs. In 1996, we
wrote off the remaining $83 million plus $5.6 million of related financing
charges.
We have been able to recover all replacement energy costs for the
outages at Calvert Cliffs in 1992, 1993, and 1994.
Our performance in 1995 and 1996 is currently being reviewed in a fuel
rate proceeding. We established that we exceeded the system-wide target for
those years as well as the performance target for both units at Calvert Cliffs
for 1995 and for unit 2 in 1996. Under a settlement agreement in the
proceeding, we will recover our replacement energy costs for the 1995 and 1996
outages.
Performance for 1997 and 1998 will be reviewed when we submit our next
fuel rate application. We cannot estimate the amount of replacement energy
costs that could be challenged or disallowed in future fuel rate proceedings,
but such amounts could be material.
The following is a summary of Calvert Cliffs' performance over the last
5 years:
GENERATION CAPACITY FACTOR
--------------------- ----------------
MEGAWATT-HOURS (MWH)
1998 ......... 13,326,633 91%
1997 ......... 13,133,441 90%
1996 ......... 12,069,937 82%
1995 ......... 12,940,496 88%
1994 ......... 11,225,977 77%
In 1998, we filed an application with the NRC for 20-year license
renewals for both units at Calvert Cliffs. The current operating licenses
expire in 2014 for Unit 1 and in 2016 for Unit 2. This is discussed further in
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS -- OTHER MATTERS.
ELECTRIC LOAD MANAGEMENT, ENERGY, AND CAPACITY PURCHASES
We have implemented various programs for use when system operating
conditions require a reduction in load. We refer to these programs as active
load management programs. These programs include:
o customer-owned generation and curtailable service for large commercial
and industrial customers,
o air conditioning control which is available to residential and commercial
customers, and
o residential water heater control.
We have generally activated these programs on peak summer days. The
potential reduction in the summer 1999 peak load from active load management is
approximately 480 megawatts (MW). We recover the costs of these load management
programs from our customers.
Our generation and transmission facilities are connected to those of
neighboring utility systems to form the PJM. Under the PJM agreement, we use
the interconnected facilities for substantial energy interchange and capacity
transactions as well as emergency assistance. In addition, sometimes we enter
into short-term capacity transactions to meet PJM obligations.
5
We have an agreement with Pennsylvania Power & Light Company (PP&L) to
purchase electricity and capacity (availability to supply electricity) from
June 1, 1990 through May 31, 2001. This agreement, which has been accepted by
the FERC, is designed to help maintain adequate reserve margins through this
decade and provide flexibility in meeting capacity obligations. The PP&L
agreement:
o entitles us to 5.94% of the electricity output, and net capacity
(currently 130 MW), of PP&L's nuclear Susquehanna Steam Electric
Station from October 1, 1991 to May 31, 2001, and
o enables us to treat a portion of PP&L's capacity as our capacity for
purposes of satisfying our installed capacity requirements as a
member of the PJM.
We are not acquiring an ownership interest in any of PP&L's generating
units. PP&L will continue to control, manage, operate, and maintain that
station and all other PP&L-owned generating facilities.
Our firm capacity purchases at December 31, 1998 represented:
o 150 MW of rated capacity of Bethlehem Steel Corporation's Sparrows Point
complex,
o 57 MW of rated capacity of the Baltimore Refuse Energy Systems Company,
and
o 130 MW of Susquehanna capacity from PP&L.
FUEL FOR ELECTRIC GENERATION
Our electric generation by type of fuel and the cost of each fuel in the
five-year period 1994-1998 is shown below:
GENERATION BY FUEL TYPE
------------------------------------------------------
1998 1997 1996 1995 1994
---------- ---------- ---------- ---------- ----------
Nuclear (a) ................... 44% 44% 40% 43% 39%
Coal .......................... 58 59 58 57 56
Oil ........................... 3 1 1 1 3
Hydro & Gas ................... 4 3 4 3 3
-- -- -- -- --
109 107 103 104 101
Net Interchange Sales ......... (9) (7) (3) (4) (1)
------ ------ ------ ------ ------
100% 100% 100% 100% 100%
===== ===== ===== ===== =====
AVERAGE COST OF FUEL CONSUMED
((cent) PER MILLION BTU)
------------------------------------------------------
1998 1997 1996 1995 1994
---------- ---------- ---------- ---------- ----------
Nuclear (a) ................... 45.45 46.51 47.29 47.22 52.06
Coal .......................... 137.17 140.52 143.80 148.64 148.64
Oil ........................... 243.18 283.61 313.33 267.59 245.28
Hydro & Gas ................... -- -- -- -- --
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(a) Nuclear fuel costs include disposal costs associated with long-term
off-site spent fuel storage and shipping, which is currently set by law at
one mill per kilowatt-hour of nuclear generation (approximately 10 cents
per million Btu), and contributions to a fund for decommissioning and
decontaminating the Department of Energy's uranium enrichment facilities.
We discuss this further below.
NUCLEAR
The supply of fuel for nuclear generating stations includes the:
o purchase of uranium concentrates,
o conversion to uranium hexafluoride,
o enrichment of uranium hexafluoride, and
o fabrication of nuclear fuel assemblies.
Information is shown below about fuel requirements for Calvert Cliffs
Units 1 and 2:
Uranium We have, either in inventory or
Concentrates: under contract, sufficient quantities
of uranium to meet 70% to 80% of
our requirements through 2004.
Conversion: We have contractual commitments
providing for the conversion of
uranium concentrates into uranium
hexafluoride which will meet
approximately 75% of our
requirements through 2004.
Enrichment: We have a contract with the U.S.
Enrichment Corporation that
provided for 100% of our
enrichment requirements through
1998, and will provide for
approximately 75% of our
enrichment requirements in 1999,
declining to approximately 50% by
2004.
Fuel We have contracted for the
Assembly fabrication of fuel assemblies for
Fabrication: reloads required through 2013.
The nuclear fuel market is very competitive and we do not anticipate any
problem in meeting our requirements beyond these periods. We discuss our
expenditures for nuclear fuel in ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS -- CAPITAL RESOURCES.
STORAGE OF SPENT NUCLEAR FUEL -- FEDERAL FACILITIES: Under the Nuclear
Waste Policy Act of 1982 (the 1982 Act), we contracted with the United States
Department
6
of Energy (DOE) to place spent fuel discharged from Calvert Cliffs into a
federal repository. Such facilities do not currently exist, and, consequently,
must be developed and licensed. We cannot predict when such facilities will be
available. However, the 1982 Act required the DOE to accept spent fuel starting
in 1998. We cannot predict what the ultimate cost to dispose of the spent fuel
will be. However, the 1982 Act assesses a one mill per kilowatt-hour fee on
nuclear electricity generated and sold. We estimate this fee to be
approximately $13 million for Calvert Cliffs each year based on expected
operating levels. Fees are deposited into the Nuclear Waste Fund.
In December 1996, the DOE notified us and other nuclear utilities that
it would not be able to meet the 1998 deadline for accepting spent fuel. We
participated in litigation, along with 36 other utilities, against the DOE. The
litigation, titled NORTHERN STATES POWER, ET AL. V. DOE, was filed January 31,
1997 in the United States Court of Appeals for the D.C. Circuit. That court has
original jurisdiction under the 1982 Act. The utilities asked the court to
allow them to pay fees, that formerly went directly to the DOE for deposit into
the Nuclear Waste Fund, into escrow instead. Among other remedies, the
utilities also asked the court to force the DOE to submit a program with
milestones illustrating how it would meet the deadline for accepting spent
nuclear fuel, and a monthly report to allow the utilities to monitor the DOE's
progress.
On November 14, 1997, the court ordered the DOE to comply with its
unconditional obligation under the 1982 Act to dispose of spent fuel. The court
did not grant the utilities the remedies sought, stating that adequate
contractual and statutory remedies already existed. The DOE and several
utilities filed separate motions for reconsideration with the court which were
denied. The DOE's request for review to the U.S. Supreme Court was also denied.
We are currently evaluating our contractual options in light of the
court's decision. We cannot currently estimate the total amount of the costs we
will incur as a result of the DOE's failure to meet the 1998 deadline.
STORAGE OF SPENT NUCLEAR FUEL -- BGE FACILITY: We have a license from
the NRC to operate an on-site independent spent fuel storage facility. We have
storage capacity at Calvert Cliffs that will accommodate spent fuel from
operations through the year 2006. In addition, we can expand our temporary
storage capacity to meet future requirements until federal storage is
available.
COSTS FOR DECOMMISSIONING URANIUM ENRICHMENT FACILITIES: The Energy
Policy Act of 1992 (the 1992 Act) contains provisions requiring domestic
nuclear utilities to contribute to a fund for decommissioning and
decontaminating the DOE's uranium enrichment facilities. These contributions
are generally payable over a fifteen-year period with escalation for inflation
and are based upon the amount of uranium enriched by the DOE for each utility
through 1992. The 1992 Act provides that these costs are recoverable through
utility service rates as a cost of fuel. Information about the cost of
decommissioning is discussed in NOTE 1 TO CONSOLIDATED FINANCIAL STATEMENTS
under the heading "FUEL AND PURCHASED ENERGY COSTS."
COAL
We get most of our coal under supply contracts with mining operators,
and we get the rest through spot purchases. We believe that we will be able to
renew supply contracts as they expire or enter into similar contracts with
other coal suppliers. Our coal-burning facilities have the following
requirements:
ANNUAL COAL
REQUIREMENT
(TONS)
------------
Brandon Shores (a)
Units 1 and 2 (combined) ......... 3,500,000
Crane (b)
Units 1 and 2 (combined) ......... 700,000
Wagner (c)
Units 2 and 3 (combined) ......... 1,000,000
- ----------------------
Special Coal Restrictions:
(a) Sulfur content less than 0.8%
(b) Low ash melting temperature
(c) Sulfur content no more than 1%
Coal deliveries to our coal burning facilities are made by rail and
barge. The coal we use is produced from mines located in central and northern
Appalachia.
We have a 20.99% undivided interest in the Keystone coal-fired
generating plant and a 10.56% undivided interest in the Conemaugh coal-fired
generating plant. Both of these plants are located in Pennsylvania. The bulk of
the annual coal requirements for the Keystone plant is under contract from
Rochester and Pittsburgh Coal Company. The Conemaugh plant purchases coal from
local suppliers on the open market.
OIL
Under normal burn practices, our requirements for residual fuel oil
amount to approximately 1,000,000 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.
GAS
We have a firm natural gas transportation entitlement of 3,500
dekatherms (DTH) a day to provide ignition and banking at certain power plants.
We purchase gas for electric generation as needed using interruptible
transportation arrangements. Some of our gas fired units can use residual fuel
oil instead of gas.
7
ELECTRIC OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------
1998 1997 1996 1995 1994
------------ ------------ ------------ ------------ -----------
Electric Output (In Thousands) -- MWH:
Generated ..................................................... 32,372 31,289 30,107 30,548 28,413
Purchased (A) ................................................. 3,496 4,737 7,560 7,403 6,270
------ ------ ------ ------ ------
Subtotal ................................................... 35,868 36,026 37,667 37,951 34,683
Less Interchange and Other Sales .............................. 5,454 6,224 7,580 8,149 5,684
------ ------ ------ ------ ------
Total Output ............................................... 30,414 29,802 30,087 29,802 28,999
====== ====== ====== ====== ======
Power Generated and Purchased at Times of Peak Load
(MW) (one hour):
Generated by Company .......................................... 5,565 5,472 4,789 5,162 3,384
Net Purchased (A) ............................................. 480 508 1,166 785 2,654
------ ------ ------ ------ ------
Peak Load (B) .................................................. 6,045 5,980 5,955 5,947 6,038
====== ====== ====== ====== ======
Annual System Load Factor (%) .................................. 57.4 56.9 57.5 57.2 54.7
Revenues (In Millions)
Residential ................................................... $ 948.6 $ 932.5 $ 958.7 $ 955.2 $ 931.7
Commercial .................................................... 912.9 892.6 861.3 879.4 853.0
Industrial .................................................... 211.5 211.9 207.6 208.5 205.6
--------- --------- --------- --------- ---------
System Sales .................................................. 2,073.0 2,037.0 2,027.6 2,043.1 1,990.3
Interchange and Other Sales ................................... 120.8 132.7 155.9 167.0 118.0
Other ......................................................... 27.0 22.3 25.5 21.0 19.1
--------- --------- --------- --------- ---------
Total ...................................................... $ 2,220.8 $ 2,192.0 $ 2,209.0 $ 2,231.1 $ 2,127.4
========= ========= ========= ========= =========
Sales (In Thousands) -- MWH:
Residential ................................................... 10,965 10,806 11,243 10,966 10,670
Commercial .................................................... 13,219 12,718 12,591 12,635 12,351
Industrial .................................................... 4,583 4,575 4,596 4,591 4,433
--------- --------- --------- --------- ---------
System Sales .................................................. 28,767 28,099 28,430 28,192 27,454
Interchange and Other Sales ................................... 5,454 6,224 7,580 8,149 5,684
--------- --------- --------- --------- ---------
Total ...................................................... 34,221 34,323 36,010 36,341 33,138
========= ========= ========= ========= =========
Customers (In Thousands)
Residential ................................................... 1,009.1 1,001.0 995.2 988.2 978.6
Commercial .................................................... 106.5 105.9 104.5 103.4 101.9
Industrial .................................................... 4.6 4.5 4.3 4.1 4.0
--------- --------- --------- --------- ---------
Total ...................................................... 1,120.2 1,111.4 1,104.0 1,095.7 1,084.5
========= ========= ========= ========= =========
Average Cost of Fuel Consumed ((cent) per million BTU) ......... 104.05 105.76 108.05 104.78 112.44
========== ========== ========== ========== ==========
We achieved an all-time peak load of 6,045 megawatts on August 25, 1998.
- ----------
(A) Includes purchases from Safe Harbor Water Power Corporation, a
hydroelectric company, of which we own two-thirds of the capital stock.
(B) We discuss active load management programs that may be activated at times
of peak load in ELECTRIC LOAD MANAGEMENT, ENERGY, AND CAPACITY PURCHASES.
8
GAS BUSINESS
We describe our gas utility business in the sections below.
GAS REGULATORY MATTERS AND COMPETITION
In recent years, federal and state initiatives have promoted the
development of competition in the sale of gas. In general, these initiatives
have sought to unbundle the integrated services that gas utilities have
traditionally provided and to enable customers to purchase gas directly from
suppliers other than their local utilities.
Two decades ago, the price of gas was regulated from the original
producer and supplier through the sale to the ultimate end-user. Currently,
there is no regulation over the wholesale price of natural gas as a commodity,
and the federal regulation of interstate transmission has been reduced.
We buy all gas that we resell directly from various suppliers (rather
than pipeline companies) and arrange separately for transportation and storage.
We offer gas for sale to our residential customers on a firm basis, and to our
commercial and industrial customers on a firm and interruptible basis.
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 commercial and industrial 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. We also provide delivery service under a pilot program allowing up
to 50,000 residential customers to purchase gas from other suppliers.
Currently, approximately 50,000 customers participate in the program but all
residential customers will be eligible to receive delivery service beginning on
November 1, 1999. In addition to the delivery service, we also provide these
customers with meter readings, billing, emergency response, regular
maintenance, and balancing.
Approximately 53% 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 essentially the same as the base rate charged for gas sales.
Delivery service customers may choose to purchase gas from several
different suppliers, including two of our diversified businesses. The basis of
competition for delivery service customers is primarily commodity price.
As part of our response to the increase in competition in the natural
gas business, earnings from off-system gas sales and capacity release revenues
are shared between shareholders and customers. Off-system gas sales are
low-margin direct sales of gas to wholesale suppliers of natural gas outside
our service territory. We make these sales as part of a program to balance our
supply of, and cost of, natural gas. In addition, we have a market based rates
incentive mechanism for gas we sell on our system. Under market based rates,
our actual cost of gas is compared to a market index (a measure of the market
price of gas in a given period). The difference between our actual cost and the
market index is shared equally between shareholders and customers.
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:
o Columbia Gas Transmission Corporation,
o CNG Transmission Corporation, and
o 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:
o Texas Eastern Transmission Corporation,
o Columbia Gulf Transmission Company, and
o ANR Pipeline Company.
We have storage service agreements with:
o Columbia Gas Transmission Corporation,
o CNG Transmission Corporation, and
o ANR Pipeline Company.
Our current pipeline firm transportation entitlements to serve our firm
loads are 280,553 DTH per day during the winter period and 255,533 DTH per day
during the summer period. We use the firm transportation capacity to move gas
from the Gulf of Mexico, Louisiana, south central regions of Texas, and Canada
to our city gates. The gas is subject to a mix of long- and short-term
contracts that are managed to provide economic, reliable, and flexible service.
We can arrange additional 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
9
at times of heavy winter demands and to be available in temporary emergencies
affecting gas supply, we have:
o a liquified 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
o a propane air facility with a mined cavern and refrigerated storage
facilities with a total storage capacity equivalent to 1,000,000 DTH
and a planned daily capacity of 85,000 DTH.
We expect to close our refrigerated storage facilities with
approximately 500,000 DTH of storage capacity during the summer of 1999. We
believe our remaining storage facilities are sufficient to supplement our gas
supply during heavy winter demands and temporary emergencies.
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.
GAS RATE MATTERS
POSTRETIREMENT AND POSTEMPLOYMENT BENEFIT COSTS
Beginning in 1998, the Maryland PSC authorized us to make a change in
the way we account for postretirement and other postemployment benefit costs.
The Maryland PSC authorized us to amortize the regulatory asset for
postretirement and other postemployment benefit costs related to our gas
business over 15 years. The Maryland PSC adjusted our gas base rates to recover
the higher costs starting in 1998. We discuss this also in NOTE 5 TO
CONSOLIDATED FINANCIAL STATEMENTS.
WEATHER NORMALIZATION
Effective March 1, 1998, the Maryland PSC allowed us to implement a
monthly adjustment to our gas base rate revenues to eliminate the effect of
abnormal weather patterns on our gas system sales volumes. This means our
monthly gas base rate revenues will be based on weather that is considered
"normal" for the month and, therefore, will not be affected by actual weather
conditions.
DELIVERY SERVICE REALIGNMENT CHARGE
Effective November 1, 1998, the Maryland PSC allowed us to begin
collecting a Delivery Service Realignment Charge in order to recover certain
costs associated with the introduction of competition in our gas business.
Costs eligible for recovery include:
o amounts under pre-existing interstate pipeline capacity contracts, and
o approved administrative and system costs to prepare for competition,
including customer education and development costs and changes in
computer systems.
1997 RATE CASE
In February 1998, we reached a settlement with the Maryland PSC for a
$16 million increase in our gas base rates related to the application that we
filed in 1997. The increase became effective March 1, 1998.
10
GAS OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------
1998 1997 1996 1995 1994
------------ ------------ ------------ ------------ ------------
Gas Output (In Thousands) -- DTH:
Purchased ............................ 47,972 62,988 70,260 70,391 68,541
LNG Withdrawn from Storage ........... 268 484 904 815 698
Produced ............................. 46 541 784 528 828
------ ------ ------ ------ ------
Total Output ...................... 48,286 64,013 71,948 71,734 70,067
Delivery service gas (A) ............. 55,608 52,629 45,964 43,854 41,897
Off-system sales (B) ................. 16,724 14,759 9,968 -- --
------ ------ ------ ------ ------
Total ............................. 120,618 131,401 127,880 115,588 111,964
======= ======= ======= ======= =======
Peak Day Sendout (DTH) ................ 658,359 765,011 708,966 706,287 761,900
======= ======= ======= ======= =======
Capability on Peak Day (DTH) .......... 833,000 870,000 870,000 847,000 847,000
Revenues (In Millions)
Residential
Excluding Delivery Service ......... $ 279.2 $ 321.7 $ 320.1 $ 248.3 $ 262.7
Delivery Service (C) ............... 4.9 0.5 -- -- --
Commercial
Excluding Delivery Service ......... 75.6 113.5 125.1 109.9 121.0
Delivery Service ................... 19.4 12.9 7.2 3.7 2.3
Industrial
Excluding Delivery Service ......... 8.0 11.4 17.1 16.7 20.2
Delivery Service ................... 16.0 17.2 14.6 16.3 9.6
--------- --------- --------- --------- ---------
System sales ......................... 403.1 477.2 484.1 394.9 415.8
Off-system sales ..................... 40.9 37.5 26.6 -- --
Other ................................ 7.2 6.9 6.6 5.6 5.4
--------- --------- --------- --------- ---------
Total ............................. $ 451.2 $ 521.6 $ 517.3 $ 400.5 $ 421.2
========= ========= ========= ========= =========
Sales (In Thousands) -- DTH:
Residential
Excluding Delivery Service ......... 33,595 39,958 43,784 40,211 40,279
Delivery Service ................... 1,890 205 -- -- --
Commercial
Excluding Delivery Service ......... 11,775 18,435 22,698 23,612 23,712
Delivery Service ................... 16,633 12,964 8,755 6,982 6,490
Industrial
Excluding Delivery Service ......... 1,412 2,016 2,887 4,102 4,410
Delivery Service ................... 34,798 38,791 36,201 35,925 33,837
--------- --------- --------- --------- ---------
System sales ......................... 100,103 112,369 114,325 110,832 108,728
Off-system sales ..................... 16,724 14,759 9,968 -- --
--------- --------- --------- --------- ---------
Total ............................. 116,827 127,128 124,293 110,832 108,728
========= ========= ========= ========= =========
Customers (In Thousands)
Residential .......................... 532.5 524.5 516.5 506.8 498.2
Commercial ........................... 39.6 39.3 38.9 38.4 37.9
Industrial ........................... 1.3 1.3 1.3 1.3 1.3
--------- --------- --------- --------- ---------
Total ............................. 573.4 565.1 556.7 546.5 537.4
========= ========= ========= ========= =========
We achieved an all-time peak day sendout of 765,011 DTH on January 18,
1997.
- ----------
(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).
(C) Residential delivery service represents sales of gas through our Gas
Options pilot program that we began in late 1997.
We discuss these programs further in the GAS REGULATORY MATTERS AND
COMPETITION section.
11
FRANCHISES
We have nonexclusive electric and gas franchises to use streets and
other highways which 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.
The Public Service Commission Law of Maryland has superseded franchise
provisions relating to rates.
DIVERSIFIED BUSINESSES
Our diversified businesses engage primarily in energy services. We also
have other diversified businesses that engage in financial investments and
develop, own, and manage real estate and senior-living facilities. Our
diversified businesses are presented below.
ENERGY SERVICES
Our Energy Services businesses experience substantial competition from
utility companies or their subsidiaries and from other companies. Competition
is based on the price of the commodities, services delivered, and the quality
and reliability of services provided.
POWER MARKETING AND TRADING
We formed CONSTELLATION POWER SOURCE, INC. in February 1997 to enter the
power marketing and trading business. This business provides power marketing
and risk management services to wholesale customers in North America by
purchasing and selling electricity, other energy commodities, and related
derivative contracts.
In March 1998, Constellation Power Source and Goldman, Sachs Capital
Partners II L.P., an affiliate of Goldman, Sachs & Co., formed Orion Power
Holdings, Inc. (Orion) to acquire electric generating plants in the United
States and Canada. Constellation Power Source owns a minority interest in
Orion, and has committed to contribute up to $175 million in equity to fund its
investment in Orion. Orion has entered into strategic relationships with
Constellation Power Source and Constellation Operating Services, Inc., a
subsidiary of Constellation Power, Inc. Constellation Power Source has the
exclusive right to provide power marketing and risk management services to
Orion. Constellation Operating Services has the exclusive right to provide
operating and maintenance services to Orion's plants.
POWER PROJECTS
CONSTELLATION POWER, INC. AND SUBSIDIARIES primarily develop, own, and
operate domestic and international power projects and manage power projects
owned by Constellation Investments, Inc.
DOMESTIC PROJECTS
Our power projects business holds up to a 50% ownership interest in 28
energy projects in operation or under construction that account for $466.0
million of assets. All of these projects are either qualifying facilities under
the Public Utility Regulatory Policies Act of 1978 or otherwise exempt from the
Public Utility Holding Company Act of 1935. Projects totaling approximately
$39.8 million of assets are located in the East and $426.2 million of assets
are located in the West.
Our power projects business also invests in international power
projects. These are discussed later in this section.
California Power Purchase Agreements
Our Domestic-West power projects include $310.6 million invested in 15
projects that sell electricity in California under power purchase agreements
called "Interim Standard Offer No. 4" agreements.
Under these agreements, the electricity rates change from fixed rates to
variable rates beginning in 1996 and continuing through 2000. The projects that
already have had rate changes have lower revenues under variable rates than
they did under fixed rates. When the remaining projects transition to variable
rates, we expect their revenues also to be lower than they are under fixed
rates. We discuss these projects further in NOTE 10 TO CONSOLIDATED FINANCIAL
STATEMENTS.
Our power projects business is pursuing alternatives for some of these
power generation projects including:
o repowering the projects to reduce operating costs,
o changing fuels to reduce operating costs,
o renegotiating the power purchase agreements to improve the terms,
o restructuring financing to improve existing terms, and
o selling its ownership interests in the projects.
INTERNATIONAL PROJECTS
Constellation Power's business in Latin America:
o develops, acquires, owns, and operates power generation projects, and
o acquires and owns distribution systems.
12
At December 31, 1998, Constellation Power had invested about $183.4
million in 15 power projects in Latin America. These investments include:
o the purchase of a 51% interest in a Panamanian electric distribution
company for approximately $90 million in 1998 by an investment group
in which subsidiaries of Constellation Power hold an 80% interest,
and
o approximately $98 million for the purchase of existing electric
generation facilities and the construction of an electric generation
facility in Guatemala.
In the future, Constellation Power expects to expand its power projects
business further in both domestic and international projects.
ENERGY PRODUCTS AND SERVICES
CONSTELLATION ENERGY SOURCE, INC. offers energy products and services
designed primarily to provide solutions to the energy needs of mid-sized
commercial and industrial customers. These energy products and services
include:
o wholesale and retail natural gas marketing services,
o a full range of heating, ventilation, air conditioning, and energy
services,
o energy consulting and power-quality services,
o services to enhance the reliability of individual electric supply
systems,
o customized financing alternatives, and
o retail electricity as available.
HOME PRODUCTS, COMMERCIAL BUILDING SYSTEMS, AND GAS RETAIL MARKETING
BGE HOME PRODUCTS & SERVICES, INC. AND SUBSIDIARIES offer services to
residential and small commercial customers. These services include:
o the sale and service of electric and gas appliances,
o home improvements,
o the sale and service of heating, air conditioning, plumbing, electrical,
and indoor air quality systems, and
o natural gas retail marketing beginning in November 1998.
COMFORTLINK
COMFORTLINK provides cooling services to commercial customers in
Baltimore.
OTHER DIVERSIFIED BUSINESSES
FINANCIAL INVESTMENTS
CONSTELLATION INVESTMENTS, INC. engages in financial investments,
including:
o marketable securities,
o financial limited partnerships, and
o financial guaranty insurance companies.
REAL ESTATE AND SENIOR-LIVING FACILITIES
CONSTELLATION REAL ESTATE GROUP, INC. develops, owns, and manages real
estate and senior-living facilities, including:
o land under development in the Baltimore-Washington corridor,
o an entertainment, dining, and retail complex in Orlando, Florida,
o a mixed-use planned-unit development, and
o beginning in 1998, a 41.9% 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
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.
13
CONSOLIDATED CAPITAL REQUIREMENTS
Our business requires a great deal of capital. Our total capital
requirements for 1998 were $1,184 million. Of this amount, $627 million was
used in our utility operations and $557 million was used in our diversified
businesses. We estimate that our total capital requirements for the years 1999
through 2001 to be:
o $1,410 million in 1999,
o $1,428 million in 2000, and
o $1,502 million in 2001.
We continuously review and change our capital expenditure programs, so
actual expenditures may vary from the estimates for the years 1999 through
2001.
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:
o air quality,
o water quality,
o waste disposal, and
o other environmental matters.
Some of the regulations require substantial expenditures for additions
to our utility plant and the use of more expensive low-sulfur fuels. We cannot
precisely estimate the total effect on our facilities and operations of current
and future environmental regulations and standards. However, we increased
capital expenditures (excluding allowance for funds used during construction)
by approximately $91 million during the five-year period 1994-1998 to comply
with existing environmental standards and regulations, and we estimate that the
future capital expenditures (excluding allowance for funds used during
construction) necessary to comply with environmental standards and regulations
will be approximately:
o $33 million in 1999,
o $30 million in 2000, and
o $35 million in 2001.
CLEAN AIR
The Federal Clean Air Act (the Act) regulates health and welfare
standards for concentrations of air pollutants. Under the Act, the State of
Maryland must set limits on all major sources of these pollutants in the State
so that the standards are not exceeded. We have certain limits on our
generating units that put us in compliance with existing air quality
regulations, as follows:
o All of our generating units, except Crane Units 1 and 2, are limited to
burning fuel (coal or oil) with a sulfur content of 1% or below.
o The Crane Units 1 and 2 are limited to 3.5 pounds per million Btu for
sulfur dioxides, which is equivalent to a coal sulfur content of
approximately 2.4%.
o All units are limited to releasing particulate matter at or below 0.02
grains per standard cubic foot of exhaust gas for oil fired units
and 0.03 grains per standard cubic foot for coal-fired units.
o Brandon Shores, a newer plant, is subject to more stringent standards for
sulfur dioxides (1.2 pounds per million Btu), and nitrogen oxides
(0.7 pounds per million Btu).
The Clean Air Act of 1990 contains two titles designed to reduce
emissions of sulfur dioxides and nitrogen oxides (NOx) from electric generating
stations -- Title IV and Title I.
Title IV addresses emissions of sulfur dioxides. Compliance is required
in two separate phases:
o Phase I became effective January 1, 1995. We met the requirements of this
phase by installing flue gas desulfurization systems, switching
fuels, and retiring some units.
o Phase II must be implemented by January 1, 2000. We expect to meet the
compliance requirements through some combination of switching fuels
and allowance trading.
Title I addresses emissions of NOx. The Maryland Department of the
Environment (MDE) issued NOx regulations effective June 1, 1998. The MDE
regulations require major NOx sources to reduce NOx emissions up to 65% by May
1999. While we are already taking steps to control NOx emissions at our
generating plants, we communicated to MDE that we could not install the
required technology at our Brandon Shores plant in time to meet the MDE's May
1999 deadline. On June 19, 1998, we filed a lawsuit against MDE in Baltimore
challenging these regulations. On February 9, 1999, the court ordered MDE to
reissue the regulations with a new compliance date, indicating it was
impossible for utilities to meet the May 1999 deadline. We do not anticipate
that MDE will appeal the court's decision.
The Environmental Protection Agency (EPA) issued a final rule in
September 1998 that requires the reduction of NOx emissions up to 85% by 22
states (including Maryland and Pennsylvania). The 22 states
14
must submit plans to the EPA by September 1999 showing how they will meet its
new requirements.
Based on the MDE and EPA regulations, we currently estimate that the
additional controls needed at our generating plants to meet the 65% NOx
emission reduction requirements will cost approximately $126 million. Through
December 31, 1998, we have spent approximately $21.5 million to meet the 65%
reduction requirements. We cannot estimate the cost for the 85% reduction
requirements at this time; however, these costs could be material.
In July 1997, the EPA published National Ambient Air Quality Standards
for very fine particulates and revised standards for ozone attainment. These
standards may require increased controls at our fossil generating plants in the
future. We cannot estimate the cost of these increased controls at this time
because the states, including Maryland, still need to determine what
reductions, if any, in pollutants will be necessary to meet the federal
standards.
WATER
The MDE regulates the discharge of waste materials into the waters of
the State of Maryland under the National Pollutant Discharge Elimination System
permit program. This program was established as part of the Federal Clean Water
Act. At the present time, we have the required permits under the program for
all of our steam electric generating plants.
The MDE water quality regulations require us to, among other things,
define procedures to determine compliance with State water quality standards.
These procedures require extensive studies involving sampling and monitoring of
the waters around affected generating plants. The State of Maryland may require
changes in plant operations. We continually perform studies to determine
whether any changes will be necessary to comply with these regulations.
WASTE DISPOSAL
The EPA has regulations for implementing the portions of the Resource
Conservation and Recovery Act that deal with the management of hazardous
wastes. These regulations, and the Hazardous and Solid Waste Amendments of
1984, identify certain spent materials as hazardous wastes and establish
standards and permit requirements for those who generate, transport, store, or
dispose of such wastes. The State of Maryland has adopted regulations governing
the management of hazardous wastes that are similar to the EPA regulations. We
have procedures in place to comply with all applicable EPA and State of
Maryland regulations governing the management of hazardous wastes. Some high
volume utility wastes, such as coal fly ash and bottom ash, are exempt from
these regulations. We currently use almost all of our coal fly ash and bottom
ash as structural fill material in a manner approved by the State of Maryland.
Beginning in 1999, we will provide some of our coal fly ash to a processing
facility that is designed to recycle it into a new material that can be sold to
the construction industry. We sell the remainder of the coal ash to the
construction industry for a number of other approved uses.
The Federal Comprehensive Environmental Response, Compensation and
Liability Act (Superfund statute) establishes liability for the cleanup of
hazardous wastes that contaminate the soil, water, or air. Those who generated,
transported, or deposited the waste at the contaminated site are each jointly
and severally liable for the cost of the cleanup, as are the current property
owner and the owner when the contamination occurred. Many states have
implemented laws similar to the Superfund statute.
In the early 1970s, we shipped an unknown number of scrapped transformers
to Metal Bank of America, a metal reclaimer in Philadelphia. Metal Bank's scrap
and storage yard has been found to be contaminated with oil containing high
levels of PCBs (hazardous chemicals frequently used as a fire-resistant coolant
in electrical equipment). On December 7, 1987, the EPA notified us and nine
other utilities that we are considered potentially responsible parties (PRPs)
with respect to the cleanup of the site. We, along with the other PRPs,
submitted a remedial investigation and feasibility study (RI/FS) to the EPA on
October 14, 1994, and the EPA issued its Record of Decision (ROD) on December
31, 1997. On June 26, 1998, the EPA ordered us, the other utility PRPs, and the
owner/ operator to implement the requirements of the ROD. The utility PRPs are
currently conducting the remedial design. Based on the ROD, our share of the
reasonably possible cleanup costs, estimated to be approximately 15.42%, could
be as much as $4.9 million higher than amounts we have recorded as a liability
on our Consolidated Balance Sheets.
On October 16, 1989, the EPA filed a complaint in the U.S. District
Court for the District of Maryland under the Superfund statute against us and
seven other defendants to recover past and future expenditures associated with
the cleanup of a site located at Kane and Lombard Streets in Baltimore. The
State of Maryland filed a similar complaint in the same case and court on
February 12, 1990. The complaints alleged that we arranged for our coal fly ash
to be deposited on the site. The Court dismissed these complaints in November
1995. The MDE began additional investigation on the remainder of the site for
the EPA, but never completed the investigation. We, along with three other
defendants, agreed to complete the RI/FS of groundwater contamination around
the site in a July 1993 consent
15
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
selected the final remedy and determined that we have met all the requirements
of the consent orders. After we install additional public water lines, we will
have no further obligations under the consent orders at the site.
On August 30, 1994, we were named as a defendant in UNITED STATES V.
KEYSTONE SANITATION COMPANY, ET AL. The litigation was instituted by the EPA
and involved contamination of the Keystone Sanitation Company landfill
Superfund site located in Adams County, Pennsylvania. In 1997, BGE and other
defendants entered into a settlement with the EPA for an immaterial amount that
was submitted to the court for its approval in 1998.
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. Currently, the EPA is investigating potential soil and
groundwater contamination. Although our potential liability cannot be
estimated, we do not expect such liability to be material based on the limited
amount of waste we shipped to the site.
In September 1996, we received an information request from the EPA about
the Drumco Drum Dump Site, located in the Curtis Bay area of Maryland. This
site was the subject of an emergency drum removal action in 1991, due to a
concern about hazardous substances leaking from drums and posing a threat to
human health and the environment. According to EPA documents, approximately $2
million dollars were spent on the drum removal action. To our knowledge, no
long-term remediation is planned for this site. In addition, we understand that
the EPA has sent information requests to approximately 17 other parties. Our
records indicate that we sold empty drums to Drumco, Inc. from approximately
1983-1990. Although our potential liability cannot be estimated, we do not
expect such liability to be material based on our records showing that we sold
only empty storage drums to Drumco, Inc.
In April 1997 and September 1998, we received information requests from
the EPA concerning the 68th Street Dump Site, also known as the Robb Tyler
Dump, located in Baltimore, Maryland. This site is not currently listed as a
federal Superfund site. However, in January 1999, the EPA proposed that this
site be listed as a federal Superfund site. We understand that the EPA has sent
information requests to over 70 other parties. Our response to the EPA is that
our records do not show that we sent waste to the site. This response is based
on reviewing all relevant documents and interviewing employees involved in
waste disposal for the Company from 1950 to 1975, which is the period covered
by the EPA's inquiry. 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 these former manufacturing sites, which includes reviewing
possible actions to remove coal tar.
In late December 1996, we signed a consent order with the MDE that
requires us to implement remedial action plans for contamination at and around
the Spring Gardens site, located in Baltimore, Maryland. We submitted the
required remedial action plans and they have been approved by the MDE. Based on
the remedial action plans, the costs we consider to be probable to remedy the
contamination are estimated to total $47 million in nominal dollars (including
inflation). We have recorded these costs as a liability on our Consolidated
Balance Sheets and have deferred these costs, net of accumulated amortization
and amounts we recovered from insurance companies, as a regulatory asset. We
discuss this further in NOTE 4 TO CONSOLIDATED FINANCIAL STATEMENTS. Through
December 31, 1998, we have spent approximately $32 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
16
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, 1998, we employed about 9,400 people.
ITEM 2. PROPERTIES
We describe our electric and gas business properties separately below.
None of the properties used in connection with the operation of our diversified
businesses are considered material to BGE.
ELECTRIC
Our principal electric generating plants are shown below:
GENERATION (MWH)
INSTALLED PRIMARY ----------------------------
PLANT LOCATION CAPACITY (MW) FUEL 1998 1997
- ----------------------- ------------------------- ----------------------- -------------- ------------ -------------
(AT DECEMBER 31, 1998)
Steam
Calvert Cliffs Calvert County, MD 1,675 Nuclear 13,326,633 13,133,441
Brandon Shores Anne Arundel County, MD 1,296 Coal 8,259,725 8,483,339
Herbert A. Wagner Anne Arundel County, MD 1,006 Coal/Oil/Gas 4,108,074 3,399,601
Charles P. Crane Baltimore County, MD 385 Coal 1,995,318 1,942,621
Gould Street Baltimore City, MD 104 Oil 137,560 89,115
Riverside Baltimore County, MD 78 Oil/Gas 46,322 14,480
Jointly Owned -- Steam
Keystone Armstrong and Indiana
Counties, P.A. 359(A) Coal 2,800,921 2,788,081
Conemaugh Indiana County, PA 181(A) Coal 1,387,837 1,294,234
Combustion Turbine
Perryman Harford County, MD 350 Oil/Gas 234,990 106,748
Notch Cliff Baltimore County, MD 128 Gas 29,644 14,024
Westport Baltimore City, MD 121 Gas 20,814 10,236
Riverside Baltimore County, MD 173 Oil/Gas 11,989 8,197
Philadelphia Road Baltimore City, MD 64 Oil 8,021 3,391
Charles P. Crane Baltimore County, MD 14 Oil 2,247 960
Herbert A. Wagner Anne Arundel County, MD 14 Oil 1,665 754
----- ---------- ----------
Totals 5,948 32,371,760 31,289,222
===== ========== ==========
- ----------------------
(A) These totals reflect BGE's proportionate interest and entitlement to
capacity from Keystone and Conemaugh, which are 2 megawatts of diesel
capacity for Keystone and 1 megawatt of diesel capacity for Conemaugh.
We also own two-thirds of the outstanding capital stock of Safe Harbor
Water Power Corporation, and are currently entitled to 277 megawatts of the
rated capacity of the Safe Harbor Hydroelectric Project. Safe Harbor is
operated under a Federal Energy Regulatory Commission license which expires in
2030.
17
GAS
We own the following propane air and liquefied natural gas facilities:
o a liquefied natural gas facility for the liquefication and storage of
natural gas with a total storage capacity of 1,000,000 DTH and a
planned daily capacity of 287,988 DTH, and
o a propane air facility with a mined cavern and refrigerated storage
facilities with a total storage capacity of 1,000,000 DTH and a
planned daily capacity of 85,000 DTH.
We expect to close our refrigerated storage facilities with
approximately 500,000 DTH of storage capacity during the summer of 1999. We
believe our remaining storage facilities are sufficient to supplement our gas
supply during heavy winter demands and temporary emergencies.
GENERAL INFORMATION
We own our principal plants and other important units that are located
in Maryland including our principal headquarters building in downtown
Baltimore. We also lease several properties in our service area which are used
for various offices and services. We have electric transmission and electric
and gas distribution lines located:
o in public streets and highways pursuant to franchises, and
o on permanent rights-of-way secured for the most part by grants from
owners of the property and for a relatively small part by
condemnation.
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.
We share the ownership of the properties for the Keystone and Conemaugh
plants in Pennsylvania. There are minor liens and easements on the Keystone and
Conemaugh properties, but these encumbrances do not materially interfere with
our use of the properties.
All of our property referred to above is subject to the lien of our
mortgage securing our mortgage bonds.
We believe that our operating properties are adequately maintained and
are in good operating condition.
ITEM 3. LEGAL PROCEEDINGS
ASBESTOS
Since 1993, we have been involved in several actions concerning
asbestos. The actions are based upon the theory of "premises liability,"
alleging that we knew of and exposed individuals to an asbestos hazard. The
actions relate to two types of claims.
The first type is direct claims by individuals exposed to asbestos. We
described these claims in a Report on Form 8-K filed August 20, 1993. We are
involved in these claims with approximately 70 other defendants. Approximately
520 individuals that were never employees of BGE each claim $6 million in
damages ($2 million compensatory and $4 million punitive). These claims were
filed in the Circuit Court for Baltimore City, Maryland in the summer of 1993.
We do not know the specific facts necessary to estimate our potential liability
for these claims. The specific facts we do not know include:
o the identity of our facilities at which the plaintiffs allegedly worked
as contractors,
o the names of the plaintiff's employers, and
o the date on which the exposure allegedly occurred.
To date, seven of these cases were settled before trial for amounts that
were immaterial. One trial is currently scheduled for August 1999.
The second type is claims by one manufacturer -- Pittsburgh Corning
Corp. -- against us and approximately eight others, as third-party defendants.
These claims relate to approximately 1,500 individual plaintiffs and were filed
in the Circuit Court for Baltimore City, Maryland in the fall of 1993. We do
not know the specific facts necessary to estimate our potential liability for
these claims. The specific facts we do not know include:
o the identity of our facilities containing asbestos manufactured by the
manufacturer,
o the relationship (if any) of each of the individual plaintiffs to us,
o the settlement amounts for any individual plaintiffs who are shown to
have had a relationship to us, and
o the dates on which/places at which the exposure allegedly occurred.
Until the relevant facts for both types of claims are determined, we are
unable to estimate what our liability, if any, might be. Although insurance and
hold harmless agreements from contractors who employed the plaintiffs may cover
a portion of any awards in the actions, our potential liability could be
material.
18
NOX EMISSIONS LITIGATION
On June 19, 1998, we filed a lawsuit against the MDE in Baltimore City
Circuit Court challenging regulations that require major NOx sources to reduce
emissions up to 65% by May 1999. While we were already taking steps to control
NOx emissions at out generating plants, we communicated to MDE that we could
not install the required technology at our Brandon Shores plant in time to meet
the 1999 deadline. On February 9, 1999, the court ordered MDE to reissue the
regulations with a new compliance date, indicating it was impossible for
utilities to meet the May 1999 deadline. We do not anticipate that MDE will
appeal the court's decision.
See ITEM 1. BUSINESS -- ELECTRIC RATE MATTERS, NUCLEAR OPERATIONS, FUEL
FOR ELECTRIC GENERATION, GAS RATE MATTERS, ENVIRONMENTAL MATTERS, and NOTE 10
TO CONSOLIDATED FINANCIAL STATEMENTS for other information about our legal or
regulatory proceedings.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
19
EXECUTIVE OFFICERS OF THE REGISTRANT
Executive Officers of BGE at the date of this report are:
OTHER OFFICES OR POSITIONS
NAME AGE PRESENT OFFICE HELD DURING PAST FIVE YEARS
- ------------------------- ----- ------------------------------------- -------------------------------------------
Christian H. Poindexter 60 Chairman of the Board, President Chairman of the Board and Chief
and Chief Executive Officer (A) Executive Officer
(Since March 1, 1998) Vice Chairman
Edward A. Crooke 60 Vice Chairman of the President and Chief Operating Officer,
Board -- BGE; Chairman of the BGE
Board, President and Chief President, Chief Operating Officer, and
Executive Officer -- Chairman of the Board, Subsidiaries
Constellation Enterprises, Inc. (B) President and Chief Operating Officer,
(Since March 1, 1998) Utility Operations
Charles W. Shivery 53 Chairman, President and President, Constellation Energy Solutions,
Chief Executive Officer Inc.
Constellation Power Source, Inc. Vice President
(Since February 25, 1997) Finance and Accounting,
Chief Financial Officer and
Secretary
Vice President and Treasurer,
Corporate Finance Group
Robert E. Denton 56 Executive Vice President Senior Vice President, Generation
Generation Vice President, Nuclear Energy
(Since March 1, 1998)
Frank O. Heintz 55 Executive Vice President Vice President, Gas
Utility Operations
(Since March 1, 1998)
Thomas F. Brady 49 Vice President Vice President, Retail Services
Corporate Strategy and Vice President, Customer Service and
Development Distribution
(Since January 1, 1999) Vice President, Customer Service and
Accounting
David A. Brune 58 Vice President General Counsel
Finance and Accounting,
Chief Financial Officer
and Secretary
(Since February 25, 1997)
Robert S. Fleishman 45 Vice President General Counsel
Corporate Affairs and Associate General
General Counsel Counsel -- Regulatory
(Since May 1, 1998)
Gregory C. Martin 50 Vice President Manager, Customer Service
General Services Manager, Customer Accounts
(Since November 1, 1997)
and Chief Information Officer
(Since August 11, 1998)
Linda D. Miller 48 Vice President Vice President,
Human Resources Management Services
(Since May 1, 1998) Manager, Employee Services
- ----------
(A) Chief Executive Officer, Director, and member of the Executive Committee.
(B) Director and member of the Executive Committee.
Officers of BGE 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.
20
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS
STOCK TRADING
Our common stock is traded under the ticker symbol BGE. 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 26, 1999, there were 69,305 common shareholders of record.
DIVIDEND POLICY
We pay dividends on our common stock after our Board of Directors
declares them. There is no limitation on our paying common stock dividends
unless:
o we elect to defer interest payments on the 7.16% Deferrable Interest
Subordinated Debentures due June 30, 2038, and any deferred interest
remains unpaid; or
o all dividends (and any redemption payments) due on our preference
stock have not been paid.
Dividends have been paid on the common stock continuously since 1910.
Future dividends depend upon future earnings, our financial condition, and
other factors. Quarterly dividends were declared on the common stock during
1998 and 1997 in the amounts set forth below.
COMMON STOCK DIVIDENDS AND PRICE RANGES
1998 1997
------------------------------------- -------------------------------------
PRICE* PRICE*
------------------------ ------------------------
DIVIDEND DIVIDEND
DECLARED HIGH LOW DECLARED HIGH LOW
---------- ----------- ---------- ---------- ---------- -----------
First Quarter .......... $ .41 $ 34 1/8 $ 29 3/4 $ .40 $ 28 $ 26 1/4
Second Quarter ......... .42 32 15/16 29 1/4 .41 27 24 3/4
Third Quarter .......... .42 33 5/8 29 5/16 .41 28 1/16 26
Fourth Quarter ......... .42 35 1/4 30 1/8 .41 34 5/16 25 13/16
------ ------
Total ................. $ 1.67 $ 1.63
====== ======
- ----------
* Based on New York Stock Exchange Composite Transactions as reported in THE
WALL STREET JOURNAL.
21
Item 6. Selected Financial Data
Compound
1998 1997 1996 1995 1994 Growth
- ------------------------------------------------------------------------------------------------------------------------------------
(DOLLAR AMOUNTS IN MILLIONS, EXCEPT PER SHARE AMOUNTS) 5-Year 10-Year
Summary of Operations
Total Revenues $ 3,358.1 $ 3,307.6 $ 3,153.2 $ 2,934.8 $ 2,783.0 4.14% 5.37%
Expenses Other Than Interest and Income Taxes 2,617.0 2,584.0 2,483.7 2,239.1 2,147.7 4.25 5.81
- ---------------------------------------------------------------------------------------------------------------
Income From Operations 741.1 723.6 669.5 695.7 635.3 3.75 3.98
Other Income (Expense) 5.7 (52.8) 6.1 8.8 32.3 (22.43) (11.20)
- ---------------------------------------------------------------------------------------------------------------
Income Before Interest and Income Taxes 746.8 670.8 675.6 704.5 667.6 3.24 3.68
Net Interest Expense 240.9 230.0 198.5 197.0 190.1 4.99 6.87
- ---------------------------------------------------------------------------------------------------------------
Income Before Income Taxes 505.9 440.8 477.1 507.5 477.5 2.47 2.47
Income Taxes 178.2 158.0 166.3 169.5 153.9 5.23 6.71
- ---------------------------------------------------------------------------------------------------------------
Net Income 327.7 282.8 310.8 338.0 323.6 1.13 0.77
Preferred and Preference Stock Dividends 21.8 28.7 38.5 40.6 39.9 (12.21) (2.95)
- ---------------------------------------------------------------------------------------------------------------
Earnings Applicable to Common Stock $ 305.9 $ 254.1 $ 272.3 $ 297.4 $ 283.7 2.68 1.11
===============================================================================================================
Earnings Per Share of Common Stock and
Earnings Per Share of Common Stock--
Assuming Dilution $ 2.06 $ 1.72 $ 1.85 $ 2.02 $ 1.93 2.17 (1.14)
Dividends Declared Per Share of
Common Stock $ 1.67 $ 1.63 $ 1.59 $ 1.55 $ 1.51 2.58 2.38
Summary of Financial Condition
Total Assets $ 9,195.0 $ 8,900.0 $ 8,678.2 $ 8,419.1 $ 8,145.3 2.86 6.02
===============================================================================================================
Capitalization
Long-term debt $ 3,128.1 $ 2,988.9 $ 2,758.8 $ 2,598.2 $ 2,584.9 2.07 5.87
Preferred stock -- -- -- 59.2 59.2 -- --
Redeemable preference stock -- 90.0 134.5 242.0 279.5 -- --
Preference stock not subject to mandatory
redemption 190.0 210.0 210.0 210.0 150.0 4.84 6.63
Common shareholders' equity 2,981.5 2,870.4 2,854.7 2,811.2 2,719.0 2.61 4.69
- ---------------------------------------------------------------------------------------------------------------
Total Capitalization $ 6,299.6 $ 6,159.3 $ 5,958.0 $ 5,920.6 $ 5,792.6 1.00 4.51
===============================================================================================================
Financial Statistics at Year End
Ratio of Earnings to Fixed Charges 2.94 2.78 3.10 3.21 3.14
Ratio of Earnings to Combined Fixed Charges
and Preferred and Preference Stock Dividends 2.60 2.35 2.44 2.52 2.47
Book Value Per Share of Common Stock $ 19.98 $ 19.44 $ 19.33 $ 19.06 $ 18.43
Number of Common Shareholders (IN THOUSANDS) 69.9 73.7 77.6 79.8 81.5
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH THE CURRENT
YEAR'S PRESENTATION.
22
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Introduction
In Management's Discussion and Analysis, we explain the general financial
condition and the results of operations for BGE(R) and its diversified business
subsidiaries including:
o what factors affect our businesses,
o what our earnings and costs were in 1998 and 1997,
o why earnings and costs changed from the year before,
o where our earnings came from,
o how all of this affects our overall financial condition,
o what our expenditures for capital projects were in 1996 through 1998, and
what we expect them to be in 1999 through 2001, and
o where we will get cash for future capital expenditures.
As you read Management's Discussion and Analysis, it may be helpful to refer to
our Consolidated Statements of Income which present the results of our
operations for 1998, 1997, and 1996. In Management's Discussion and Analysis, we
analyze and explain the annual changes in the specific line items in the
Consolidated Statements of Income.
The electric utility industry is undergoing rapid and substantial change.
Competition in the generation part of our business is increasing. The regulatory
environment (federal and state) is shifting toward customer choice. These
matters are discussed briefly in the "Competition and Response to Regulatory
Change" section and in Item 1. Business--Electric Regulatory Matters and
Competition.
In response to this change, we regularly reevaluate our strategies with two
goals in mind: to improve our competitive position, and to anticipate and adapt
to regulatory change. These strategies might include one or more of the
following:
o the complete or partial separation of our generation, transmission, and
distribution functions,
o purchase or sale of generation assets,
o mergers or acquisitions of utility or non-utility businesses,
o spin-off or sale of one or more businesses, and
o growth of earnings from nonregulated businesses.
We cannot predict whether any of the strategies described above may actually
occur, or what their effect on our financial condition or competitive position
might be. Please refer to the "Forward Looking Statements" section.
Results of Operations
In this section, we discuss our earnings and the factors affecting them. We
begin with a general overview, then separately discuss earnings for the utility
business and for diversified businesses.
OVERVIEW
Total Earnings per Share
of Common Stock
1998 1997 1996
- --------------------------------------------------------------------------------
Utility business $ 1.93 $ 1.94 $ 1.96
Diversified businesses (subsidiaries) .27 .34 .31
- --------------------------------------------------------------------------------
Total earnings per share from
operations 2.20 2.28 2.27
Write-off of merger costs (see Note 2) -- (.25) --
Write-downs of real estate
investments (see Note 3) (.10) (.31) --
Disallowed replacement
energy costs (see Note 10) -- -- (.42)
Write-off of energy services investment
(see Note 2) (.04) -- --
- --------------------------------------------------------------------------------
Total earnings per share $ 2.06 $ 1.72 $ 1.85
================================================================================
1998
Our 1998 total earnings increased $51.8 million, or $.34 per share, compared to
1997. Our total earnings increased mostly because 1997 results reflect our
write-off of merger costs, and our real estate and senior-living facilities
business' write-down of its investments in two real estate projects, as
discussed in the 1997 section below. Our 1998 earnings would have been higher
except:
o our real estate and senior-living facilities business wrote down its
investment in a real estate project, and
o we wrote off an energy services investment.
In 1998, utility earnings from operations were about the same compared to 1997.
We discuss our utility earnings in more detail in the "Utility Business"
section.
In 1998, diversified business earnings from operations decreased compared to
1997 mostly because of lower earnings from our real estate and senior-living
facilities and financial investments
23
businesses. However, we had higher earnings from our power projects and power
marketing and trading businesses. We discuss our diversified business earnings
in more detail in the "Diversified Businesses" section.
We discuss the real estate write-down in the "Other Diversified Businesses"
section and the write-off of the energy services investment in the "Other Energy
Services" section.
1997
Our 1997 total earnings decreased $18.2 million, or $.13 per share, compared to
1996. Our total earnings decreased because: