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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:
o we wrote off costs associated with the terminated merger with Potomac
Electric Power Company, and
o our real estate and senior-living facilities business wrote down its
investments in two real estate projects.
We discuss the write-off of merger costs in the "Write-Off of Merger Costs"
section, and the real estate write-downs in the "Other Diversified Businesses"
section.
In 1997, utility earnings from operations decreased compared to 1996 mostly
because we sold less electricity and gas due to milder weather.
In 1997, diversified business earnings from operations increased compared to
1996 mostly because of higher earnings from our power projects and financial
investments businesses.
Utility Business
Before we go into the details of our electric and gas operations, we believe it
is important to discuss factors that have a strong influence on our utility
business performance: regulation, the weather, other factors including the
condition of the economy in our service territory, and competition.
Regulation by the Maryland Public Service Commission (Maryland PSC)
The Maryland PSC determines the rates we can charge our customers. Our rates
consist of a "base rate" and a "fuel rate." The base rate is the rate the
Maryland PSC allows us to charge our customers for the cost of providing them
service, plus a profit. We have both an electric base rate and a gas base rate.
Higher electric base rates apply during the summer when the demand for
electricity is the highest. Gas base rates are not affected by seasonal changes.
The Maryland PSC allows us to include in base rates a component to recover money
spent on conservation programs. This component is called a "conservation
surcharge." However, under this surcharge the Maryland PSC limits what our
profit can be. If, at the end of the year, we have exceeded our allowed profit,
we defer the excess in that year and we lower the amount of future surcharges to
our customers to correct the amount of overage, plus interest.
In addition, we charge our electric customers separately for the fuel we use to
generate electricity (nuclear fuel, coal, gas, or oil) and for the net cost of
purchases and sales of electricity (primarily with other utilities). We charge
the actual cost of these items to the customer with no profit to us. If these
fuel costs go up, the Maryland PSC permits us to increase the fuel rate. If
these costs go down, our customers benefit from a reduction in the fuel rate.
The fuel rate is impacted most by the amount of electricity generated at our
Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) because the cost of nuclear
fuel is cheaper than coal, gas, or oil.
We discuss this in more detail in the "Electric Fuel Rate Clause" section and in
Note 1 of the Notes to Consolidated Financial Statements.
Changes in the fuel rate normally do not affect earnings. However, if the
Maryland PSC disallows recovery of any part of the fuel costs, our earnings are
reduced. In 1996, the Maryland PSC disallowed certain fuel costs as discussed in
the "Disallowed Replacement Energy Costs" section and in Note 10.
We also charge our gas customers separately for the natural gas they purchase
from us. The price we charge for the natural gas is based on a market based
rates incentive mechanism approved by the Maryland PSC. We discuss market based
rates in more detail in the "Gas Cost Adjustments" section and in Note 1.
From time to time, when necessary to cover increased costs, we ask the Maryland
PSC for base rate increases. The Maryland PSC holds hearings to determine
whether to grant us all or a portion of the amount requested. The Maryland PSC
historically has allowed us to increase base rates to recover increased utility
plant asset costs, plus a profit, beginning at the time of replacement.
Generally, rate increases improve our utility earnings because they allow us to
collect more revenue. However, rate increases are normally granted based on
historical data, and those increases may not always keep pace with increasing
costs.
Other parties may petition the Maryland PSC to lower our base rates. We discuss
this in more detail in the "Competition and Response to Regulatory Change"
section.
Weather
Weather affects the demand for electricity and gas. Very hot summers and very
cold winters increase demand. Mild weather reduces demand. Weather impacts
residential sales more than commercial and industrial sales, which are mostly
affected by business needs for electricity and gas.
We measure the weather's effect using "degree days." A degree day is the
difference between the average daily actual temperature and a baseline
temperature of 65 degrees. Cooling degree days result when the average daily
actual temperature exceeds the 65 degree baseline. Heating degree days result
when the average daily actual temperature is less than the baseline.
24
During the cooling season, hotter weather is measured by more cooling degree
days and results in greater demand for electricity to operate cooling systems.
During the heating season, colder weather is measured by more heating degree
days and results in greater demand for electricity and gas to operate heating
systems.
Effective March 1, 1998, the Maryland PSC allowed us to implement a monthly
adjustment to our gas business revenues to eliminate the effect of abnormal
weather patterns. We discuss this further in the "Weather Normalization"
section.
We show the number of cooling and heating degree days in 1998 and 1997, the
percentage changes in the number of degree days from the prior year, and the
number of degree days in a "normal" year as represented by the 30-year average
in the following table.
30-year
1998 1997 average
- ---------------------------------------------------------------
Cooling degree days 915 746 836
Percentage change
from prior year 22.7% (5.1)%
Heating degree days 4,119 4,822 4,783
Percentage change
from prior year (14.6)% (6.2)%
Other Factors
Other factors, aside from weather, impact the demand for electricity and gas.
These factors include the "number of customers" and "usage per customer" during
a given period. We use these terms later in our discussions of electric and gas
operations. In those sections, we discuss how these and other factors affected
electric and gas sales during 1998 and 1997.
The number of customers in a given period is affected by new home and apartment
construction and by the number of businesses in our service territory.
Usage per customer refers to all other items impacting customer sales which
cannot be measured separately. These factors include the strength of the economy
in our service territory. When the economy is healthy and expanding, customers
tend to consume more electricity and gas. Conversely, during an economic
downtrend, our customers tend to consume less electricity and gas.
Competition and Response to Regulatory Change
Our electric and gas businesses are also affected by competition and regulatory
changes. We discuss these items for both of our regulated businesses below.
Electric Business
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.
On July 1, 1998, BGE and all other Maryland investor-owned electric utilities
filed with the Maryland PSC their individual proposals for the transition from a
regulated electric supply system to one where generation is priced based on a
competitive retail electric market. In our plan, we proposed that:
o all customers would be able to choose other suppliers or our service,
o we would guarantee our service at rates frozen until July 2002. Prices would
then be adjusted for inflation until the transition is complete, but not
beyond 2008,
o customers who choose an alternate supplier would receive a shopping credit.
This credit would reduce their BGE bill by the market value of capacity,
energy, and other services that we no longer provide those customers,
o we would attempt to reduce potentially stranded investments by lowering
operating costs and applying all earnings in excess of our authorized rate
of return to accelerate the recovery of generation assets. This would lower
the generation asset book values toward their competitive market values
thereby reducing any potentially stranded investment,
o market value of generation assets would be determined by annual independent
appraisals beginning in 2002 and continuing through the transition period,
o when the difference between the book value and market value of generation
assets is within 10%, the transition period would end and a non-bypassable
surcharge would be applied to customers' bills to recover the remaining
stranded investments over a two- to three-year period, and
o net regulatory assets and nuclear decommissioning costs would continue to be
collected from customers through the regulated transmission and distribution
business.
On December 22, 1998, other parties filed their positions in response to our
proposal. The counter-proposals contain provisions which, if adopted by the
Maryland PSC, could negatively impact our electric business. The Maryland PSC
will hold hearings to examine our electric restructuring transition 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
discussed 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.
25
We cannot predict the ultimate effect competition or regulatory change will have
on our earnings.
We discuss competition in our electric business in Item 1. Business--Electric
Regulatory Matters and Competition.
Gas Business
Regulatory change in the natural gas industry is well under way. We discuss
competition in our gas business in Item 1. Business--Gas Regulatory Matters and
Competition.
Effective November 1, 1998, the Maryland PSC allowed us to begin collecting a
Delivery Service Realignment Charge to recover certain costs associated with the
introduction of competition in our gas business. This is not expected to
significantly impact our earnings.
UTILITY
Business Earnings per Share
of Common Stock
1998 1997 1996
- --------------------------------------------------------------------------------
Electric business $ 1.75 $ 1.77 $ 1.75
Gas business .18 .17 .21
- --------------------------------------------------------------------------------
Total utility earnings per share
from operations 1.93 1.94 1.96
Write-off of merger costs (see Note 2) -- (.25) --
Disallowed replacement
energy costs (see Note 10) -- -- (.42)
- --------------------------------------------------------------------------------
Total utility earnings per share $ 1.93 $ 1.69 $ 1.54
================================================================================
Utility Business Earnings per Share of Common Stock
Our 1998 total utility earnings increased $36.1 million, or $.24 per share, from
1997. Our 1997 total utility earnings increased $24.0 million, or $.15 per
share, from 1996. We discuss the factors affecting utility earnings below.
Electric Operations
Electric Revenues
The changes in electric revenues in 1998 and 1997 compared to the respective
prior year were caused by:
1998 1997
- ------------------------------------------------------------
(In millions)
Electric system sales volumes $50.8 $(15.5)
Base rates (6.6) 29.2
Fuel rates (8.1) (4.3)
- ------------------------------------------------------------
Total change in electric revenues
from electric system sales 36.1 9.4
Interchange and other sales (13.2) (23.2)
Other 4.6 (3.2)
- ------------------------------------------------------------
Total change in electric revenues $27.5 $(17.0)
==========================================================
Electric System Sales Volumes
"Electric system sales volumes" are sales to customers in our service territory
at rates set by the Maryland PSC. These sales do not include interchange sales
and other sales.
The percentage changes in our electric system sales volumes, by type of
customer, in 1998 and 1997 compared to the respective prior year were:
1998 1997
- --------------------------------------------
Residential 1.5% (3.9)%
Commercial 3.9 1.0
Industrial 0.2 (0.4)
In 1998, we sold more electricity to residential customers mostly because:
o the number of customers increased,
o we had hotter summer weather, and
o usage per customer increased.
We would have sold even more electricity to residential customers except we had
milder winter weather in 1998. We sold more electricity to commercial customers
mostly because usage per customer increased. We sold about the same amount of
electricity to industrial customers as we did in 1997.
In 1997, we sold less electricity to residential customers mostly for two
reasons: lower usage per customer and milder weather. We sold more electricity
to commercial customers mostly because usage per customer increased. We would
have sold even more electricity to commercial customers except for milder
weather during the year. We sold about the same amount of electricity to
industrial customers as we did in 1996.
Base Rates
In 1998, base rate revenues decreased compared to 1997. Although we sold more
electricity in 1998, our base rate revenues decreased because of lower
conservation surcharge revenues.
In 1997, base rate revenues increased compared to 1996 because of higher
conservation surcharge revenues. During 1996, we exceeded our profit limit under
the conservation surcharge. As a result, we excluded $28.5 million of our 1996
surcharge billings from revenue. To correct the overage, we lowered the
surcharge on our customers' bills over a twelve- month period beginning July
1997 through June 1998.
26
Fuel Rates
In 1998, fuel rate revenues decreased compared to 1997. Although we sold more
electricity, the fuel rate was lower mostly because we were able to use a
less-costly mix of generating plants and electricity purchases.
In 1997, fuel rate revenues decreased compared to 1996 mostly because we sold
less electricity.
Interchange and Other Sales
"Interchange and other sales" are sales in the PJM (Pennsylvania-New
Jersey-Maryland) Interconnection energy market and to others. The PJM is a
regional power pool with members that include many wholesale market
participants, as well as BGE and seven other utility companies. We sell energy
to PJM members and to others after we have satisfied the demand for electricity
in our own system.
In 1998 and 1997, interchange and other sales revenues decreased compared to the
respective prior year mostly because of lower sales volumes.
Electric Fuel and Purchased Energy Expenses
1998 1997 1996
- -----------------------------------------------------------------
(In millions)
Actual costs $514.7 $504.5 $539.2
Net recovery (deferral)
of costs under electric fuel
rate clause (see Note 1) (9.0) 15.2 8.2
Disallowed replacement energy
costs (including carrying
charges) (see Note 10) -- -- 95.4
- -----------------------------------------------------------------
Total electric fuel and
purchased energy expenses $505.7 $519.7 $642.8
- -----------------------------------------------------------------
Actual Costs
In 1998, our actual costs of fuel to generate electricity (nuclear fuel, coal,
gas, or oil) and electricity we bought from others increased compared to 1997
mostly because we settled a capacity contract with PECO Energy Company.
In 1997, our actual costs decreased compared to 1996 mostly for two reasons: we
bought less electricity from others as a result of being able to meet demand
using the electricity we generated, and we were able to use a less-costly mix of
generating plants mostly because we generated more electricity at Calvert
Cliffs.
Electric Fuel Rate Clause
Under the electric fuel rate clause, we defer (include as an asset or liability
in our Consolidated Balance Sheets and exclude from our Consolidated Statements
of Income) the difference between our actual costs of fuel and energy and what
we collect from customers under the fuel rate in a given period. We either bill
or refund our customers that difference in the future. We discuss the
calculation of the fuel rate in Note 1.
In 1998, our actual costs of fuel and energy were higher than the fuel rate
revenues we collected from our customers.
In 1997, our actual costs of fuel and energy were lower than the fuel rate
revenues we collected from our customers.
Disallowed Replacement Energy Costs
In December 1996, we settled fuel rate proceedings about extended outages that
occurred at Calvert Cliffs from 1989 through 1991. We agreed not to bill our
customers for $118 million of electric replacement energy costs associated with
the outages. We wrote off a portion of the costs in 1990 and wrote off the
remainder in 1996. We discuss this further in Note 10.
Gas Operations
Gas Revenues
The changes in gas revenues in 1998 and 1997 compared to the respective prior
year were caused by:
1998 1997
- -----------------------------------------------
(In millions)
Gas system sales volumes $(10.8) $(7.3)
Base rates 14.2 0.6
Weather normalization 10.1 --
Gas cost adjustments (87.6) (0.2)
- -----------------------------------------------
Total change in gas revenues
from gas system sales (74.1) (6.9)
Off-system sales 1.8 10.9
Other 0.1 0.3
- -----------------------------------------------
Total change in gas revenues $(72.2) $ 4.3
===============================================
Gas System Sales Volumes
The percentage changes in our gas system sales volumes,
by type of customer, in 1998 and 1997 compared to the respective prior year
were:
1998 1997
- -----------------------------------------------
Residential (11.6)% (8.3)%
Commercial (9.5) (0.2)
Industrial (11.3) 4.4
27
In 1998, we sold less gas to residential and commercial customers mostly for two
reasons: milder weather and lower usage per customer. We would have sold even
less gas to residential and commercial customers except the number of customers
increased. We sold less gas to industrial customers mostly because usage by
Bethlehem Steel (our largest customer) and other industrial customers decreased.
In 1997, we sold less gas to residential customers mostly for two reasons: lower
usage per customer and milder weather. We sold about the same amount of gas to
commercial customers as we did in 1996. We sold more gas to industrial customers
mostly for two reasons: milder weather caused fewer service interruptions and
Bethlehem Steel used more gas. Sometimes we need to interrupt service during
periods with the highest demand. Some industrial customers pay reduced rates in
exchange for our right to interrupt their service during these periods. We would
have sold even more gas to industrial customers except gas usage by industrial
customers other than Bethlehem Steel decreased.
Base Rates
In 1998, base rate revenues increased compared to 1997. Although we sold less
gas during 1998, our base rate revenues increased mostly because the Maryland
PSC authorized an increase in our base rates effective March 1, 1998. The change
in rates will increase our base rate revenues over the twelve-month period from
March 1998 through February 1999 by approximately $16 million.
In 1997, base rate revenues increased compared to 1996. Although we sold less
gas in 1997, our base rate revenues increased because of higher conservation
surcharge revenues during the last six months of the year.
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.
Gas Cost Adjustments
We charge our gas customers for the natural gas they purchase from us using gas
cost adjustment clauses set by the Maryland PSC. These clauses operate similar
to the electric fuel rate clause described in the "Electric Fuel Rate Clause"
section.
However, effective October 1996, the Maryland PSC approved a modification of
these gas clauses to provide a market based rates incentive mechanism. Under
market based rates, our actual cost of gas is compared to a market index (a
measure of the market price of gas in a given period). The difference between
our actual cost and the market index is shared equally between shareholders and
customers, and does not significantly impact earnings. We also discuss this in
Note 1.
Delivery service customers, including Bethlehem Steel, are not subject to the
gas cost adjustment clauses because we are not selling gas to them. We charge
these customers fees to recover the fixed costs for the transportation service
we provide. These fees are essentially the same as the base rate charged for gas
sales and are included in gas system sales volumes.
In 1998 and 1997, gas cost adjustment revenues decreased compared to the
respective prior year mostly because we sold less gas.
Off-System Sales
Off-system gas sales are low-margin direct sales of gas to wholesale suppliers
of natural gas outside our service territory. Off-system gas sales, which occur
after we have satisfied our customers' demand, are not subject to gas cost
adjustments. The Maryland PSC approved an arrangement for part of the margin
from off-system sales to benefit customers (through reduced costs) and the
remainder to be retained by BGE (which benefits shareholders). Changes in
off-system sales do not significantly impact earnings.
In 1998, off-system gas sales revenues increased compared to 1997 mostly because
we sold more gas off-system.
In 1997, off-system gas sales revenues increased compared to 1996 mostly because
we first began off-system sales of gas in February 1996.
Gas Purchased for Resale Expenses
1998 1997 1996
- -------------------------------------------------------------------
(In millions)
Actual costs $212.2 $291.6 $295.4
Net recovery (deferral) of
costs under gas adjustment
clauses (see Note 1) (3.6) 0.5 (11.0)
- -------------------------------------------------------------------
Total gas purchased for
resale expenses $208.6 $292.1 $284.4
===================================================================
Actual Costs
Actual costs include the cost of gas purchased for resale to our customers and
for off-system sales. Actual costs do not include the cost of gas purchased by
delivery service customers.
In 1998 and 1997, actual gas costs decreased compared to the respective prior
year mostly because we sold less gas.
28
Gas Adjustment Clauses
We charge customers for the cost of gas sold through gas adjustment clauses
(determined by the Maryland PSC), as discussed under "Gas Cost Adjustments"
earlier in this section.
In 1998, actual gas costs were higher than the revenues we collected from our
customers.
In 1997, actual gas costs were lower than the revenues we collected from our
customers.
Other Operating Expenses
Operations and Maintenance Expenses
In 1998, operations and maintenance expenses increased $34.8 million compared to
1997 mostly because of:
o higher nuclear costs,
o higher employee benefit costs, and
o a $6.0 million write-off of contributions to a third party for a low-level
radiation waste facility that was never completed.
In 1997, operations and maintenance expenses were slightly lower than they were
in 1996.
Depreciation and Amortization Expenses
We describe depreciation and amortization expenses in Note 1.
In 1998, depreciation and amortization expenses increased $34.2 million compared
to 1997 mostly because:
o in October, 1998, the Maryland PSC authorized us to implement new electric
depreciation rates retroactive to January 1, 1998, which increased
depreciation expense by approximately $13.9 million,
o we had more utility plant in service (as our level of plant in service
changes, the amount of our depreciation and amortization expense changes),
and
o we reduced the amortization period for certain computer software beginning
in the first quarter of 1998 from five years to three years.
In 1997, depreciation and amortization expenses increased $12.7 million compared
to 1996 mostly because we had more plant in service.
Other Income and Expenses
Write-Off of Merger Costs
In September 1995, we signed an agreement with Potomac Electric Power Company to
merge together into a new company, Constellation Energy (R) Corporation, after
all necessary regulatory approvals were received. In December 1997, both
companies mutually terminated the merger agreement. Accordingly, in 1997, we
wrote off $57.9 million of costs related to the merger. This write-off reduced
after-tax earnings by $37.5 million, or $.25 per share.
Interest Charges
Interest charges represent the interest on our outstanding debt.
In 1998, interest charges increased $6.7 million compared to 1997 mostly because
we had more debt outstanding. Interest charges would have been higher except
interest rates were lower than they were in 1997.
In 1997, interest charges increased $23.6 million compared to 1996 mostly for
two reasons: we had more debt outstanding and interest rates were higher.
Income Taxes
In 1998, income taxes increased $20.2 million compared to 1997 because we had
higher taxable income from both our utility operations and our diversified
businesses.
In 1997, income taxes decreased $8.3 million compared to 1996 because we had
lower taxable income from both our utility operations and our diversified
businesses.
Diversified Businesses
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 Item 1. Business--
Diversified Businesses.
29
DIVERSIFIED
Business Earnings per Share
of Common Stock
1998 1997 1996
- ------------------------------------------------------------------------
Energy services
Power marketing and trading $.05 $.00 $--
Power projects .30 .25 .18
Other (.01) (.05) .02
- ------------------------------------------------------------------------
Total energy services earnings
per share from operations .34 .20 .20
Other diversified businesses
earnings per share from operations (.07) .14 .11
- ------------------------------------------------------------------------
Total diversified business earnings
per share from operations .27 .34 .31
Write-downs of real estate investments
(see Note 3) (.10) (.31) --
Write-off of energy services investment (.04) -- --
- ------------------------------------------------------------------------
Total earnings per share $ .13 $ .03 $ .31
========================================================================
Diversified Business Earnings per Share of Common Stock
Our 1998 diversified business earnings increased $15.7 million, or $.10 per
share, compared to 1997. Our 1997 diversified business earnings decreased $42.2
million, or $.28 per share, compared to 1996.
We discuss factors affecting the earnings of our diversified businesses below.
Energy Services
Power Marketing and Trading
In 1998, earnings from our power marketing and trading business increased
compared to 1997 mostly because of increased trading activities in 1998 which
was Constellation Power Source's first full year of operations.
Constellation Power Source uses the mark-to-market method of accounting for its
trading activities. We discuss the mark-to-market method of accounting and
Constellation Power Source's trading activities in Note 1.
As a result of the nature of its trading activities, Constellation Power
Source's revenue and earnings will fluctuate. We cannot predict these
fluctuations, but the effect on our revenues and earnings could be material. The
primary factors that cause these fluctuations are:
o the number and size of new transactions,
o the magnitude and volatility of changes in commodity prices and interest
rates, and
o the number and size of open commodity and derivative positions Constellation
Power Source holds or sells.
Constellation Power Source's management uses its best estimates to determine the
fair value of commodity and derivative positions it holds and sells. These
estimates consider various factors including closing exchange and
over-the-counter price quotations, time value, volatility factors, and credit
exposure. However, it is possible that future market prices could vary from
those used in recording assets and liabilities from trading activities, and such
variations could be material. In 1998, assets and liabilities from energy
trading activities increased because of greater trading activity compared to
1997.
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 has a commitment to fund its investment in Orion as
discussed further in Note 10.
Power Projects
In 1998, earnings from our power projects business increased compared to 1997
mostly because Constellation Power recorded a $10.4 million after-tax gain for
its share of earnings in a partnership. The partnership recognized a gain on the
sale of its ownership interest in a power sales contract.
In 1997, earnings increased compared to 1996 mostly because of improved
performance of various energy projects. Also, 1996 earnings included $14.6
million (after-tax) for Constellation Power's percentage share of earnings in a
partnership. The partnership recognized a gain on the sale of a power purchase
agreement. These increases were offset by $16.2 million of after-tax write-offs
of investments in certain power projects.
We describe our earnings in the partnerships and the write-offs further in Note
3.
California Power Purchase Agreements
Constellation Power and subsidiaries and Constellation Investments have $310.6
million invested in 15 projects that sell electricity in California under power
purchase agreements called "Interim Standard Offer No. 4" agreements. In 1998,
earnings from these projects were $41.3 million, or $.28 per share.
Under these agreements, the electricity rates change from fixed rates to
variable rates beginning in 1996 and continuing through 2000. The projects which
already have had rate changes have lower revenues under variable rates than they
did under fixed rates. When the remaining projects transition to variable rates,
we expect their revenues also to be lower than they are under fixed rates.
30
Our power projects business is pursuing alternatives for some of these 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.
The California projects that make the highest revenues will transition in 1999
and 2000. The projects which transition in 1999 contributed $10.7 million, or
$.07 per share to 1998 earnings, while those changing over in 2000 contributed
$24.0 million, or $.16 per share to 1998 earnings. We expect earnings to
ultimately decrease by similar amounts beginning in 1999 as these projects
transition.
We describe these projects in more detail in Note 10.
International Projects
At December 31, 1998, Constellation Power had invested about $183.4 million in
15 power projects in Latin America compared to $23.5 million invested in Latin
America in 1997. 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.
Other Energy Services
In 1998, earnings from our remaining energy services businesses increased
compared to 1997 due to improved results from our energy products and services
business. Earnings would have been higher except we recorded a $5.5 million
after-tax, or $.04 per share, write-off of our investment in, and certain of our
product inventory from, an automated electric distribution equipment company. We
recorded this write-off because of that company's inability to raise capital and
sell its products.
In 1997, earnings from our remaining energy services businesses decreased
compared to 1996 mostly because of lower earnings from our energy products and
services business.
Other Diversified Businesses
In 1998, earnings from our other diversified businesses decreased compared to
1997 mostly for two reasons: lower earnings from our real estate and
senior-living facilities and financial investments businesses. Earnings from our
real estate and senior-living facilities business decreased compared to 1997
mostly due to:
o a $15.4 million after-tax write-down of its investment in Church Street
Station--an entertainment, dining, and retail complex in Orlando, Florida,
o lower earnings from various real estate and senior-living facilities
projects, and
o a $4 million after-tax gain on the sale of two senior- living facilities
projects reflected in 1997 results.
In addition, in 1998, our real estate and senior-living facilities business
exchanged certain assets and liabilities in return for a 41.9% equity interest
in Corporate Office Properties Trust (COPT), a real estate investment trust.
Earnings from our financial investments business decreased compared to 1997
mostly because of:
o better market performance for our investments in 1997, and
o a $6 million after-tax gain on the sale of stock held by a financial limited
partnership reflected in 1997 results.
In 1997, earnings from our other diversified businesses increased compared to
1996 mostly because of increased earnings in our financial investments business
from better earnings in trading securities and increased gains from marketable
securities. Earnings would have been higher except we had a decrease in earnings
from our real estate and senior-living facilities business mostly due to:
o a $14.1 million after-tax write-down of the investment in Church Street
Station, and
o a $31.9 million after-tax write-down of the investment in Piney Orchard--a
mixed-use, planned-unit development.
We discuss our real estate projects, the write-downs of our real estate
projects, the COPT transaction, and our financial investments further in Note 3.
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.
Management's current real estate strategy is to hold each real estate project
until we can realize a reasonable value for it except for Church Street Station
which we intend to sell. Management evaluates strategies for all its businesses,
including real estate, on an ongoing basis. We anticipate that competing demands
for our financial resources and changes in the utility industry will cause us to
evaluate thoroughly all diversified business strategies on a regular basis so we
use capital and other resources in a manner that is most beneficial.
31
Financial Condition
Cash Flows
1998 1997 1996
- -----------------------------------------------------------
(In millions)
Cash provided by (used in):
Operating Activities $820.8 $726.0 $701.9
Investing Activities (625.0) (520.8) (567.0)
Financing Activities (184.7) (109.3) (91.6)
In 1998 and 1997, cash provided by operations increased compared to the
respective prior year mostly because of changes in working capital requirements.
In 1998, net cash used in investing activities increased compared to 1997 mostly
because of the additional investment in international power projects. Cash used
in investing would have been higher except for a $33.8 million decrease in
utility construction expenditures.
In 1997, net cash used in investing activities decreased mostly because of the
$79.5 million cash inflow from the sale of real estate properties and the
increase in loans collected from real estate projects compared to 1996. Cash
used in investing activities would have been lower except for a $12.7 million
increase in utility construction expenditures, and $46.5 million increase for
our investments in power projects and financial limited partnerships.
Total utility construction expenditures, including the allowance for funds used
during construction, were $339.4 million in 1998 as compared to $373.2 million
in 1997 and $360.5 million in 1996.
In 1998, cash used in financing activities increased compared to 1997 mostly
because of the repayment of short-term borrowings that matured, sinking fund
requirements, and early redemption of higher cost securities. Net cash used
would have been higher except we issued more long-term debt and common stock in
1998 compared to 1997.
In 1997, cash used in financing activities increased from 1996 mostly because of
the repayment of long-term debt and short-term borrowings that matured, sinking
fund requirements, and early redemptions of higher cost securities. Net cash
used would have been higher except we issued more long-term debt in 1997
compared to 1996.
Security Ratings
Independent credit-rating agencies rate our fixed-income securities. The ratings
indicate the agencies' assessment of our ability to pay interest, distributions,
dividends, and principal on these securities. These ratings affect how much it
will cost us to sell these securities. The better the rating, the lower the cost
of the securities to us when we sell them. Our securities ratings at the date of
this report are shown in the following table.
Standard Moody's Duff & Phelps'
& Poors' Investors Credit
Rating Group Service Rating Co.
- -----------------------------------------------------------------------
Mortgage Bonds AA- A1 AA-
Unsecured Debt A A2 A+
Trust Originated
Preferred Securities
& Preference Stock A- "a2" A
- --------------------------------------------------------------------------------
Capital Resources
Our business requires a great deal of capital. Our actual capital requirements
for the years 1996 through 1998, along with estimated annual amounts for the
years 1999 through 2001, are shown in the table on page 33. For the year ended
December 31, 1998, our ratio of earnings to fixed charges was 2.94 and our ratio
of earnings to combined fixed charges and preferred and preference dividend
requirements was 2.60.
Investment requirements for 1999 through 2001 include estimates of funding for
existing and anticipated projects. We continuously review and modify those
estimates. Actual investment requirements may vary from the estimates included
in the table on page 33 because of a number of factors including:
o regulation, legislation, and competition,
o load growth,
o environmental protection standards,
o the type and number of projects selected for development,
o the effect of market conditions on those projects,
o the cost and availability of capital, and
o the availability of cash from operations.
Our estimates are also subject to additional factors. Please see "Forward
Looking Statements" section.
32
1996 1997 1998 1999 2000 2001
- -------------------------------------------------------------------------------------------------------------------
(In millions)
Utility Business Capital Requirements:
Construction expenditures (excluding AFC)
Electric $ 219 $ 238 $ 239 $ 285 $ 269 $ 290
Gas 84 89 55 74 70 69
Common 46 38 35 25 20 18
- -------------------------------------------------------------------------------------------------------------------
Total construction expenditures 349 365 329 384 359 377
AFC 10 8 10 11 13 19
Nuclear fuel (uranium purchases and processing charges) 47 44 50 50 50 48
Deferred conservation expenditures 31 27 16 1 -- --
Retirement of long-term debt and
redemption of preference stock 184 243 222 341 253 195
- -------------------------------------------------------------------------------------------------------------------
Total utility business capital requirements 621 687 627 787 675 639
- -------------------------------------------------------------------------------------------------------------------
Diversified Business Capital Requirements:
Investment requirements 118 156 325 423 480 500
Retirement of long-term debt 52 188 232 200 273 363
- -------------------------------------------------------------------------------------------------------------------
Total diversified business capital requirements 170 344 557 623 753 863
- -------------------------------------------------------------------------------------------------------------------
Total capital requirements $ 791 $1,031 $1,184 $1,410 $1,428 $1,502
===================================================================================================================
Capital Requirements of Our Utility Business
Our estimates of future electric construction expenditures do not include costs
to build more generating units. Electric construction expenditures include
improvements to generating plants and to our transmission and distribution
facilities. They also include estimated costs for replacing the steam generators
and extending the operating licenses at Calvert Cliffs. The operating licenses
expire in 2014 for Unit 1 and in 2016 for Unit 2. We estimate these Calvert
Cliffs costs to be:
o $34 million in 1999,
o $44 million in 2000, and
o $58 million in 2001.
We estimate that during the two-year period 2002 through 2003, we will spend an
additional $151 million to complete the replacement of the steam generators and
extend the operating licenses at Calvert Cliffs. We discuss the license
extension process further in the "Calvert Cliffs License Extension" section.
If we do not replace the steam generators, we estimate that Calvert Cliffs could
not operate for the full term of its current operating licenses. We expect the
steam generator replacements to occur during the 2002 refueling outage for Unit
1 and during the 2003 refueling outage for Unit 2.
Additionally, our estimates of future electric construction expenditures include
the costs of complying with Environmental Protection Agency (EPA) and State of
Maryland 65% nitrogen oxides emissions (NOx) reduction regulations as follows:
o $29 million in 1999,
o $28 million in 2000,
o $33 million in 2001, and
o $14 million in 2002.
We discuss the NOx regulations further in Note 10.
Our utility operations provided about 108% in 1998, 105% in 1997, and 96% in
1996 of the cash needed to meet our capital requirements, excluding cash needed
to retire debt and redeem preference stock.
We will continue to have cash requirements for:
o working capital needs including the payments of interest, distributions,
and dividends,
o capital expenditures, and
o the retirement of debt and redemption of preference stock.
During the three years from 1999 through 2001, we expect utility operations to
provide about 115% of the cash needed to meet our capital requirements,
excluding cash needed to retire debt and redeem preference stock.
When we cannot meet our utility capital requirements internally, we sell debt
and equity securities. We also sell securities when market conditions permit us
to refinance existing debt or preference stock at a lower cost. The amount of
cash we need and market conditions determine when and how much we sell.
Future funding for capital expenditures, the retirement of debt, redemption of
preference stock, and payments of interest and dividends is expected to be
provided by internally generated funds, commercial paper issuances, available
capacity under credit facilities, and/or the issuance of long-term debt, trust
securities, or equity.
33
At December 31, 1998, we have the authority from the Federal Energy Regulatory
Commission to issue up to $700 million of short-term borrowings. In addition, we
maintain $113 million in committed bank lines of credit and we have $100 million
in bank revolving credit agreements to support the commercial paper program as
discussed in Note 6.
Capital Requirements of Our Diversified Businesses
Certain of our diversified businesses expect to expand their businesses which
will require additional investments. These investment requirements include
funding for:
o growing our power marketing and trading business,
o the development and acquisition of power projects, as well as loans to
project entities,
o investments in financial limited partnerships, and
o funding for construction of cooling system projects.
The investment requirements exclude BGE's commitment to contribute up to $175
million in equity to Constellation Power Source, Inc. to fund its investment in
Orion Power Holdings, Inc.
Our diversified businesses have met their capital requirements in the past
through borrowing, cash from their operations, and from time to time equity
contributions from BGE. Our diversified businesses plan to raise the cash needed
to meet capital requirements in the future through these same methods. BGE Home
Products & Services may also meet capital requirements through sales of
receivables.
If we can get a reasonable value for our real estate projects, additional cash
may be obtained by selling real estate projects. The ability to sell or
liquidate assets will depend on market conditions, and we cannot give assurances
that these sales or liquidations could be made. We discuss the real estate
business and market in the "Other Diversified Businesses" section and in the
Notes to Consolidated Financial Statements.
Our diversified businesses also have revolving credit agreements totaling $270
million to provide additional liquidity for short-term financial needs,
including the issuance of up to $135 million of letters of credit.
In 1998, a subsidiary of Constellation Enterprises, Inc. issued $157 million of
two- and three-year notes to several institutional investors in a private
placement offering.
In 1997, our diversified businesses issued $289 million of three- and four-year
notes.
We discuss our short-term borrowings in Note 6 and long-term debt in Note 7.
- --------------------------------------------------------------------------------
Market Risk
We are exposed to market risk, including changes in interest rates, certain
commodity prices, equity prices, and foreign currency. To manage our market
risk, we may enter into various derivative instruments including swaps, forward
contracts, futures contracts, and options. Please refer to the "Forward Looking
Statements" section. We discuss our market risk and the related use of
derivative instruments in this section.
Interest Rate Risk
We are exposed to changes in interest rates as a result of financing through our
issuance of variable-rate debt, fixed-rate debt, and preferred and preference
securities. The following table provides information about our obligations that
are sensitive to interest rate changes.
Principal Payments and Interest Rate Detail by Contractual Maturity Date
Fair value at
1999 2000 2001 2002 2003 Thereafter Total Dec. 31, 1998
- -----------------------------------------------------------------------------------------------------------------------------
(In millions)
Long-term debt
Variable-rate debt $ 306.5 $ 40.9 $ 75.0 $ 0.9 $ 6.6 $ 278.3 $ 708.2 $ 708.2
Average interest rate 5.59% 5.97% 5.92% 7.79% 6.89% 4.20% 5.11%
Fixed-rate debt $ 228.2 $ 485.1 $ 482.8 $ 154.6 $ 286.6 $ 1,329.7 $ 2,967.0 $ 3,076.6
Average interest rate 7.85% 7.16% 7.08% 7.31% 6.51% 6.72% 6.95%
Preference Stock
Fixed-rate preference stock $ 7.0 $ -- $ -- $ -- $ -- $-- $ 7.0 $ 7.2
Average interest rate 7.85% --% --% --% --% --% 7.85%
34
Commodity Price Risk
We are exposed to the impact of market fluctuations in the price and
transportation costs of natural gas, electricity, and other trading commodities.
Currently, our gas business and energy services businesses use derivative
instruments to manage changes in their respective commodity prices.
Gas Business
Our gas business may enter into gas futures, options, and swaps to hedge its
price risk under our market based rates incentive mechanism and our off-system
gas sales program. We discuss this further in Note 1. At December 31, 1998, our
exposure to commodity price risk for our gas business was not material.
Energy Services Businesses
With respect to our energy services businesses, Constellation Power Source
manages its commodity price risk inherent in its energy trading activities on a
portfolio basis, subject to established trading and risk management policies.
Commodity price risk arises from the potential for changes in the value of
energy commodities and related derivatives due to: changes in commodity prices,
volatility of commodity prices, and fluctuations in interest rates. A number of
factors associated with the structure and operation of the electricity market
significantly influence the level and volatility of prices for electricity and
related derivative products. These factors include:
o seasonal changes in the demand for electricity,
o hourly fluctuations in demand due to weather conditions,
o available generation resources,
o transmission availability and reliability within and between regions, and
o procedures used to maintain the integrity of the physical electricity system
during extreme conditions.
These factors can affect energy commodity and derivative prices in different
ways and to different degrees. These effects may vary throughout the country and
result from regional differences in:
o weather conditions,
o market liquidity,
o capability and reliability of the physical electricity
system, and
o the nature and extent of electricity deregulation.
Constellation Power Source uses various methods, including a value at risk
model, to measure its exposure to market risk from energy trading activities.
Value at risk is a statistical model that attempts to predict risk of loss based
on historical market price and volatility data. Constellation Power Source
calculates value at risk using a variance/covariance technique that models
option positions using a linear approximation of their value. Additionally,
Constellation Power Source estimates variances and correlation using historical
market movements over the most recent rolling three-month period.
The value at risk amount represents the potential loss in the fair value of
assets and liabilities from trading activities over a one-day holding period
with a 99.6% confidence level. Using this confidence level, Constellation Power
Source would expect a one-day change in fair value greater than or equal to the
daily value at risk at least once per year. As of December 31, 1998,
Constellation Power Source's value at risk was $6.0 million.
Constellation Power Source's calculation includes all assets and liabilities
from trading activities, including energy commodities and derivatives that do
not require cash settlements. We believe that this represents a more complete
calculation of our value at risk from energy trading activities.
Due to the relative immaturity of the competitive market for electricity and
related derivatives and the seasonality of changes in market prices, the value
at risk calculation may not reflect the full extent of our commodity price risk
exposure. Additionally, actual changes in the value of options may differ from
the value at risk calculated using a linear approximation inherent in our
calculation method.
We discuss Constellation Power Source's trading business in the "Power Marketing
and Trading" section and in Note 1.
The commodity price risk for our remaining energy services businesses was not
material.
Equity Price Risk
We are exposed to price fluctuations in equity markets primarily through our
financial investments business and our nuclear decommissioning trust fund. We
are required by the Nuclear Regulatory Commission (NRC) to maintain a trust to
fund the costs of decommissioning Calvert Cliffs. At December 31, 1998, equity
price risk was not material. We discuss our nuclear decommissioning trust fund
in more detail in Note 1. We also describe our financial investments in more
detail in Note 3.
Foreign Currency Risk
We are exposed to foreign currency risk primarily through our power projects
business. Our power projects business has $183.4 million invested in 15
international power generation and distribution projects as of December 31,
1998. To manage our exposure to foreign currency risk, the majority of our
contracts are denominated in or indexed to the U.S. dollar. At December 31,
1998, foreign currency risk was not material. We discuss our international
projects in the "Power Projects" section.
35
Other Matters
Calvert Cliffs License Extension
In 1998, we filed an application for a 20-year license extension for Calvert
Cliffs with the NRC to extend its license beyond 2014 for Unit 1 and 2016 for
Unit 2. License renewal evaluations focus on age-related issues in long-lived
passive components (passive components include buildings, the reactor vessel,
piping, ventilation ducts, electric cables, etc.). We must demonstrate that we
can ensure that these passive components will continue to perform their intended
functions through the renewal period. The NRC will also consider the impact of
the 20-year license extension on the environment.
We began the license extension process in 1998 because the NRC may not rule on
our application until 2002 or 2003. If the NRC denies our application, we must
have adequate time to begin replacement power source planning. We cannot predict
the timing of, or impact, if any, of the NRC's decision on our financial
results. If our application is denied, it could have a material effect on our
financial results.
Environmental Matters
You will find details of our environmental matters in Note 10 and in Item 1.
Business--Environmental Matters. These details include financial information.
Some of the information is about environmental costs that may be material to our
financial results.
Year 2000 Readiness Disclosure
We have not experienced any significant year 2000 problems to date and we do not
expect any significant problems to impair our operations as we transition to the
new century. However, due to the magnitude and complexity of the year 2000
issue, even the most conscientious efforts cannot guarantee that every problem
will be found and corrected prior to January 1, 2000. We are focusing on
critical operating and business systems and expect to have contingency plans in
place to deal with any problems, if they should occur. Please refer to "Forward
Looking Statements" section.
Utility Business
We established a year 2000 Program Management Office (PMO). Based on a work plan
developed by the PMO, we have targeted the following six key areas:
o digital systems (devices with embedded microprocessors such as power
instrumentation, controls, and meters),
o telecommunications systems,
o major suppliers,
o information technology applications (our customer, business, and human
resources information systems),
o computer hardware and software infrastructure, and
o contingency plans.
Of these areas, digital systems have the most impact on our ability to provide
electric and gas service. Telecommunications, major suppliers, and certain
information technology applications also impact our ability to provide electric
and gas service.
Year 2000 Project Phases
Our year 2000 project is divided into two phases:
o Phase I--initial assessment and detailed analysis, and
o Phase II--testing, remediation, certification, and contingency planning.
Phase I involves conducting an inventory of all systems and identifying
appropriate resources. We have identified the following appropriate resources
for each system or piece of equipment:
o BGE employees familiar with each system or piece of equipment,
o specialized contractors, and
o specific vendors.
Phase I also includes developing action plans to ensure that the key areas
identified above are year 2000 ready. The action plans for each system or piece
of equipment include:
o our budget,
o schedules for Phase I and II, and
o our remediation approach--repair, upgrade, replace or retire.
In evaluating our risks and estimating our costs, we utilized employees with
expertise in each line of business to perform the activities under Phase I. We
believe our employees are the most familiar with their systems or equipment and
therefore will provide a reliable estimate of our risks and costs.
Phase II includes converting and testing all of our systems. Each system will be
tested by those employees used in Phase I following formal guidelines developed
by the PMO. Each system or piece of equipment will then be certified by a tester
and the PMO, following testing guidelines developed with the help of outside
consultants. We are currently evaluating whether we will have our year 2000
testing independently certified. Phase II also includes identifying our major
suppliers and developing contingency plans. We have identified our major
suppliers and have assessed their year 2000 readiness through surveys. We are
currently following-up with our major suppliers via interviews.
Contingency Planning
Year 2000 operational contingency planning is underway. Staffing and initial
planning was completed in 1998. Contingency plans are expected to be completed,
including company-wide training, by September 1999. We are developing
contingency plans using the contingency guidelines issued by the Nuclear Energy
Institute (which are endorsed by the NRC), the contingency guidelines issued by
the North American Electric Reliability Council (NERC), and guidance from
consultants.
36
We are also addressing the impact of electric power grid problems that may occur
outside of our own electric system. We have started year 2000 electric power
grid impact planning through our various electric interconnection affiliations.
The PJM interconnection has drafted year 2000 operational preparedness plans and
restoration scenarios and will continue to develop these plans during the first
half of 1999 in cooperation with NERC. The NERC has started monthly assessments
of the electric utility industry to communicate the readiness of the national
electric grid for year 2000. The NERC has scheduled two industry-wide tests for
1999.
Through the Electric Power Research Institute (EPRI), an industry-wide effort
has been established to deal with year 2000 problems affecting digital systems
and equipment used by the nation's electric power companies. Under this effort,
participating utilities are working together to assess specific vendors' system
problems and test plans. The assessment was shared by the industry as a whole to
facilitate year 2000 problem solving.
BGE has joined the American Gas Association (AGA) in an initiative similar to
the one with EPRI to facilitate year 2000 problem solving among gas utilities.
The AGA and its affiliates has initiated quarterly assessments of the gas
utility industry to communicate the readiness of its members for the year 2000.
Current Status
The most reasonably likely worst case scenario faced by our utility business is
any interruption in providing electric and gas service to our customers. We
cannot predict the impact of any interruption on our results of operations, but
the impact could be material. The following table shows our estimate as of the
date of this report of the percentage completed for Phases I and II and our
expected year 2000 readiness target dates for the six key areas:
Year 2000
readiness
Phase I Phase II target date
- ----------------------------------------------------------
(approximate % complete)
Digital systems 100% 65% June 1999
Telecommunications
systems 100% 90% June 1999
Major suppliers 100% 90% June 1999
Information technology
applications 100% 70% June 1999
Computer hardware
and software
infrastructure 100% 85% June 1999
Contingency plans -- 30% September 1999
The completion percentages listed above are reviewed by our PMO in monthly
status meetings with the personnel responsible for each project and their
supervision. Monthly progress is also monitored by senior BGE management.
Costs
In the following table, we show the breakdown of our total costs between normal
system replacements that will be capitalized (included in the Consolidated
Balance Sheets) and the costs that will be expensed (included in our
Consolidated Statements of Income) through operations and maintenance (O&M)
cost. We also show the breakdown of non-incremental (previously included in our
information technology budget) and incremental O&M cost:
Actual Estimated
Cost Costs Total
1996 1997 1998 1999 2000 Costs
- --------------------------------------------------------------------------------
(In millions)
Total Cost $ 0.1 $1.7 $18.9 $19.5 $2.0 $ 42.2
Less: Capital
cost -- -- 7.3 5.7 -- 13.0
- --------------------------------------------------------------------------------
O&M cost 0.1 1.7 11.6 13.8 2.0 29.2
Less: non-
incremental
O&M cost 0.1 1.7 4.6 7.0 1.0 14.4
- --------------------------------------------------------------------------------
Incremental
O&M cost $ -- $ -- $ 7.0 $ 6.8 $1.0 $ 14.8
================================================================================
The costs incurred in 1996 and 1997 were for Phase I. The costs incurred in 1998
were for Phases I and II. Costs incurred in 1999 and 2000 will be for Phases I
and II.
In 1998 and 1999, we had and expect to have the equivalent of approximately 110
full-time employees assigned to our year 2000 project.
Diversified Businesses
Overview
Our diversified businesses have established year 2000 task forces to address
their year 2000 issues and are completing their initial assessments. As the
initial assessments are completed, the businesses have developed, and will be
developing, action plans to prepare their systems for the year 2000. Outside
consultants have been retained by several of our diversified businesses to help
complete the initial assessment and detailed analysis phase, and to assist in
the testing, remediation, and certification phase of their year 2000 projects.
The action plans developed are similar to those used by our utility business,
including a test certification process. All systems are expected to be certified
by December 1999. Our diversified businesses are evaluating whether they will
have their year 2000 testing independently certified.
In evaluating their risks and estimating their costs, our diversified businesses
utilized employees with expertise in each line of business to perform initial
assessments. We believe our diversified businesses' employees are the most
familiar with their systems or equipment and therefore will provide a reliable
estimate of our risks and costs.
37
The progress of our diversified businesses' year 2000 projects are reviewed by
their year 2000 task forces in monthly status meetings with the personnel
responsible for each project and their supervision. Monthly progress is also
monitored by senior management for each business and periodic updates are
provided to BGE senior management.
Contingency Planning
Each of our diversified businesses will develop contingency plans, which are
expected to be completed by December 1999.
Current Status
The most reasonably likely worst case scenarios faced by our energy services
businesses and our other diversified businesses are discussed below. However, if
any of these scenarios actually occurred, the impact is not expected to be
material to our consolidated financial results.
Energy Services
- ---------------
The most reasonably likely worst case scenarios for any one of our power
projects would be:
o a shutdown of the plant's systems (most of which can be manually
overridden),
o inability of the purchasing utility to take the plant's power, or
o lack of fuel.
Personnel at each plant are currently assessing their particular year 2000
issues and certain plants have started the testing, remediation, and
certification phase of their year 2000 project.
For our power marketing and trading business and our energy products and
services business, the most reasonably likely worst case scenario would be
encountering any Internet access problems with trading partners, transmission
service providers, independent operators, power exchanges, and various
electronic bulletin boards. Each of these businesses have two Internet service
providers and are contracting with a third provider for alternate routing to
critical Internet sites necessary to perform day-to-day business functions. Both
are currently assessing their year 2000 issues.
For our home products and commercial building systems business, the most
reasonably likely worst case scenarios would be any interruption in billing
customers or renewing maintenance contracts. This business has substantially
completed the assessment and detailed analysis phase and has started the
testing, remediation, and certification phase of its year 2000 project.
Other Diversified Businesses
- ----------------------------
The most reasonably likely worst case scenarios for our financial investments
business would be a breakdown in the systems of the brokers or safekeeping banks
which it uses to trade, or the failure of its investment managers' computer
programs that set investment strategy. This business is currently surveying and
monitoring the year 2000 readiness of its banks, brokers, and investment
managers.
For our real estate and senior-living facilities business, the most reasonably
likely worst case scenario is a failure of the systems that support the health,
safety, and welfare of residents in the senior-living facilities. Personnel at
each facility are involved in assessing their particular year 2000 issues.
Costs
We estimate our total year 2000 costs for our power
projects business to be approximately $4.2 million, of which $1.2 million is
related to our year 2000 efforts for our Panamanian electric distribution
company. The total estimated year 2000 costs for our remaining diversified
businesses are approximately $2.8 million.
Accounting Standards Issued and Adopted
We discuss recently issued and adopted accounting standards in Note 1.
38
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The information required by this item with respect to market risk is set
forth in Item 7 of Part II of this Form 10-K under the heading "Market Risk".
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders of Baltimore Gas and Electric Company
We have audited the consolidated financial statements and the financial
statement schedule of Baltimore Gas and Electric Company and Subsidiaries
listed in Item 14(a) of this Form 10-K. These financial statements and the
financial statement schedule are the responsibility of the Company's
Management. Our responsibility is to express an opinion on these financial
statements and financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by Management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the consolidated financial position of
Baltimore Gas and Electric Company and Subsidiaries as of December 31, 1998 and
1997, and the consolidated results of their operations and their cash flows for
each of the three years in the period ended December 31, 1998 in conformity
with generally accepted accounting principles. In addition, in our opinion, the
financial statement schedule referred to above, when considered in relation to
the basic financial statements taken as a whole, presents fairly, in all
material respects, the information required to be included therein.
We have also previously audited, in accordance with generally accepted
auditing standards, the consolidated balance sheets and statements of
capitalization at December 31, 1996, 1995, and 1994, and the related
consolidated statements of income, cash flows, common shareholders' equity, and
income taxes for each of the two years in the period ended December 31, 1995
(none of which are presented herein); and we expressed unqualified opinions on
those consolidated financial statements. In our opinion, the information set
forth in the Summary of Operations and Summary of Financial Condition included
in the Selected Financial Data for each of the five years in the period ended
December 31, 1998, appearing on page 22 is fairly stated in all material
respects in relation to the financial statements from which it has been
derived.
/s/ PRICEWATERHOUSECOOPERS LLP
- --------------------------------------------------------------------------------
PRICEWATERHOUSECOOPERS LLP
Baltimore, Maryland
January 15, 1999
39
Consolidated Statements of Income Baltimore Gas and Electric Company and
Subsidiaries
YEAR ENDED DECEMBER 31, 1998 1997 1996
- ---------------------------------------------------------------------------------------------------------
(In millions, except per share amounts)
Revenues
Electric $2,219.2 $2,191.7 $2,208.7
Gas 449.4 521.6 517.3
Diversified businesses 689.5 594.3 427.2
- ---------------------------------------------------------------------------------------------------------
Total revenues 3,358.1 3,307.6 3,153.2
Expenses Other Than Interest and Income Taxes
Electric fuel and purchased energy 505.7 519.7 547.4
Disallowed replacement energy costs (see Note 10) -- -- 95.4
Gas purchased for resale 208.6 292.1 284.4
Operations 554.1 518.3 526.4
Maintenance 177.5 178.5 174.1
Diversified businesses--selling, general, and administrative 550.9 444.9 311.1
Write-downs of real estate investments (see Note 3) 23.7 70.8 --
Depreciation and amortization 377.1 342.9 330.2
Taxes other than income taxes 219.4 216.8 214.7
- ---------------------------------------------------------------------------------------------------------
Total expenses other than interest and income taxes 2,617.0 2,584.0 2,483.7
- ---------------------------------------------------------------------------------------------------------
Income from Operations 741.1 723.6 669.5
Other Income (Expense)
Write-off of merger costs (see Note 2) -- (57.9) --
Allowance for equity funds used during construction 6.3 5.3 6.5
Equity in earnings of Safe Harbor Water Power Corporation 5.0 5.0 4.6
Net other expense (5.6) (5.2) (5.0)
- ---------------------------------------------------------------------------------------------------------
Total other income (expense) 5.7 (52.8) 6.1
- ---------------------------------------------------------------------------------------------------------
Income Before Interest and Income Taxes 746.8 670.8 675.6
Interest Expense
Interest charges 247.9 241.2 217.6
Capitalized interest (3.6) (8.4) (15.6)
Allowance for borrowed funds used during construction (3.4) (2.8) (3.5)
- ---------------------------------------------------------------------------------------------------------
Net interest expense 240.9 230.0 198.5
- ---------------------------------------------------------------------------------------------------------
Income Before Income Taxes 505.9 440.8 477.1
Income Taxes 178.2 158.0 166.3
- ---------------------------------------------------------------------------------------------------------
Net Income 327.7 282.8 310.8
Preferred and Preference Stock Dividends 21.8 28.7 38.5
- ---------------------------------------------------------------------------------------------------------
Earnings Applicable to Common Stock $ 305.9 $ 254.1 $ 272.3
=========================================================================================================
Average Shares of Common Stock Outstanding 148.5 147.7 147.6
Earnings Per Common Share and
Earnings Per Common Share--Assuming Dilution $2.06 $1.72 $1.85
=========================================================================================================
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Baltimore Gas and Electric Company and Subsidiaries
YEAR ENDED DECEMBER 31, 1998 1997 1996
- ---------------------------------------------------------------------------------------------------------
(In millions)
Net Income $ 327.7 $ 282.8 $ 310.8
Other comprehensive gain/(loss), net of taxes 1.2 (0.8) 1.7
- ---------------------------------------------------------------------------------------------------------
Comprehensive Income $ 328.9 $ 282.0 $ 312.5
=========================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
40
Consolidated Balance Sheets Baltimore Gas and Electric Company and Subsidiaries
AT DECEMBER 31, 1998 1997
- ---------------------------------------------------------------------------------------------------------
(In millions)
Assets
Current Assets
Cash and cash equivalents $ 173.7 $ 162.6
Accounts receivable (net of allowance for uncollectibles
of $20.3 and $24.1 respectively) 401.8 419.8
Trading securities 119.7 119.7
Fuel stocks 85.4 87.6
Materials and supplies 145.1 164.2
Prepaid taxes other than income taxes 68.8 65.2
Assets from energy trading activities 160.2 9.4
Other 21.4 27.4
- ---------------------------------------------------------------------------------------------------------
Total current assets 1,176.1 1,055.9
- ---------------------------------------------------------------------------------------------------------
Investments and Other Assets
Real estate projects and investments 353.9 446.8
Power projects 656.8 451.7
Financial investments 198.0 196.5
Nuclear decommissioning trust fund 181.4 145.3
Net pension asset 108.0 113.0
Safe Harbor Water Power Corporation 34.4 34.4
Senior-living facilities 93.5 62.2
Other 115.4 98.7
- ---------------------------------------------------------------------------------------------------------
Total investments and other assets 1,741.4 1,548.6
- ---------------------------------------------------------------------------------------------------------
Utility Plant
Plant in service
Electric 6,890.3 6,725.6
Gas 921.3 846.9
Common 552.8 554.1
- ---------------------------------------------------------------------------------------------------------
Total plant in service 8,364.4 8,126.6
Accumulated depreciation (3,087.5) (2,843.4)
- ---------------------------------------------------------------------------------------------------------
Net plant in service 5,276.9 5,283.2
Construction work in progress 223.0 215.2
Nuclear fuel (net of amortization) 132.5 127.9
Plant held for future use 24.3 25.2
- ---------------------------------------------------------------------------------------------------------
Net utility plant 5,656.7 5,651.5
- ---------------------------------------------------------------------------------------------------------
Deferred Charges
Regulatory assets (net) 565.7 597.3
Other 55.1 46.7
- ---------------------------------------------------------------------------------------------------------
Total deferred charges 620.8 644.0
- ---------------------------------------------------------------------------------------------------------
Total Assets $9,195.0 $8,900.0
=========================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
41
Consolidated Balance Sheets Baltimore Gas and Electric Company and Subsidiaries
AT DECEMBER 31, 1998 1997
- ---------------------------------------------------------------------------------------------------------
(In millions)
Liabilities and Capitalization
Current Liabilities
Short-term borrowings $ -- $ 316.1
Current portions of long-term debt and preference stock 541.7 271.9
Accounts payable 249.6 203.0
Customer deposits 35.5 30.1
Accrued taxes 6.5 5.5
Accrued interest 58.6 58.4
Dividends declared 66.1 66.3
Accrued vacation costs 34.7 36.2
Liabilities from energy trading activities 126.2 8.6
Other 45.3 44.3
- ---------------------------------------------------------------------------------------------------------
Total current liabilities 1,164.2 1,040.4
- ---------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes 1,309.1 1,294.9
Postretirement and postemployment benefits 217.0 185.5
Deferred investment tax credits 118.0 126.6
Decommissioning of federal uranium enrichment facilities 30.8 34.9
Other 56.3 58.4
- ---------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 1,731.2 1,700.3
- ---------------------------------------------------------------------------------------------------------
Capitalization
Long-term debt 3,128.1 2,988.9
Redeemable preference stock -- 90.0
Preference stock not subject to mandatory redemption 190.0 210.0
Common shareholders' equity 2,981.5 2,870.4
- ---------------------------------------------------------------------------------------------------------
Total capitalization 6,299.6 6,159.3
- ---------------------------------------------------------------------------------------------------------
Commitments, Guarantees, and Contingencies--See Note 10
Total Liabilities and Capitalization $9,195.0 $8,900.0
=========================================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
42
Consolidated Statements of Cash Flows Baltimore Gas and Electric Company and
Subsidiaries
YEAR ENDED DECEMBER 31, 1998 1997 1996
- ---------------------------------------------------------------------------------------------------------
(In millions)
Cash Flows From Operating Activities
Net income $ 327.7 $ 282.8 $ 310.8
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization 429.4 396.8 383.1
Deferred income taxes 17.5 7.4 26.0
Investment tax credit adjustments (8.8) (7.5) (7.6)
Deferred fuel costs (8.3) 18.3 0.5
Deferred conservation revenues -- -- 28.5
Disallowed replacement energy costs -- -- 95.4
Accrued pension and postemployment benefits 41.6 (18.0) (13.8)
Write-off of merger costs -- 57.9 --
Write-downs of real estate investments 23.7 70.8 --
Allowance for equity funds used during construction (6.3) (5.3) (6.5)
Equity in earnings of affiliates and joint ventures (net) (54.5) (42.5) (48.3)
Changes in assets from energy trading activities (150.8) (9.4) --
Changes in liabilities from energy trading activities 117.6 8.6 --
Changes in other current assets 39.2 (54.7) (88.0)
Changes in other current liabilities 56.1 42.6 (4.9)
Other (3.3) (21.8) 26.7
- ---------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 820.8 726.0 701.9
- ---------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Utility construction expenditures (including AFC) (339.4) (373.2) (360.5)
Allowance for equity funds used during construction 6.3 5.3 6.5
Nuclear fuel expenditures (50.5) (43.6) (46.8)
Deferred conservation expenditures (16.2) (27.1) (31.4)
Contributions to nuclear decommissioning trust fund (17.6) (17.6) (25.5)
Merger costs -- (20.9) (28.5)
Purchases of marketable equity securities (33.3) (23.0) (32.7)
Sales of marketable equity securities 32.8 46.5 39.7
Other financial investments 14.6 (0.4) 7.1
Real estate projects and investments 21.5 24.2 (55.3)
Power projects (166.2) (44.3) (5.3)
Other (77.0) (46.7) (34.3)
- ---------------------------------------------------------------------------------------------------------
Net cash used in investing activities (625.0) (520.8) (567.0)
- ---------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Proceeds from issuance of
Short-term borrowings 1,962.2 2,719.0 3,970.8
Long-term debt 831.3 622.0 383.2
Common stock 51.8 -- 3.7
Repayment of short-term borrowings (2,278.3) (2,736.1) (3,916.9)
Reacquisition of long-term debt (355.2) (343.3) (158.5)
Redemption of preference stock (127.9) (104.5) (112.6)
Common stock dividends paid (246.0) (239.2) (233.1)
Preferred and preference stock dividends paid (21.0) (29.7) (37.0)
Other (1.6) 2.5 8.8
- ---------------------------------------------------------------------------------------------------------
Net cash used in financing activities (184.7) (109.3) (91.6)
- ---------------------------------------------------------------------------------------------------------
Net Increase in Cash and Cash Equivalents 11.1 95.9 43.3
Cash and Cash Equivalents at Beginning of Year 162.6 66.7 23.4
- ---------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 173.7 $ 162.6 $ 66.7
=========================================================================================================
Other Cash Flow Information
Cash paid during the year for:
Interest (net of amounts capitalized) $ 236.7 $ 224.2 $ 193.6
Income taxes $ 164.3 $ 171.2 $ 160.1
Noncash Investing and Financing Activities
In 1998, Corporate Office Properties Trust (COPT) assumed approximately $62
million of Constellation Real Estate Group's (CREG) debt and issued to CREG 7.0
million common shares and 985,000 convertible preferred shares. In exchange,
COPT received 14 operating properties and two properties under development from
CREG.
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH THE CURRENT
YEAR'S PRESENTATION.
43
Consolidated Statements of Common Shareholders' Equity
Baltimore Gas and Electric Company and Subsidiaries
Accumulated
Other
Common Stock Retained Comprehensive Total
YEARS ENDED DECEMBER 31, 1998, 1997, AND 1996 Shares Amount Earnings Income Amount
- ---------------------------------------------------------------------------------------------------------
(DOLLAR AMOUNTS IN MILLIONS, NUMBER OF SHARES IN THOUSANDS)
Balance at December 31, 1995 147,527 $1,425.8 $1,381.4 $ 4.0 $2,811.2
Net income 310.8 310.8
Dividends declared
Preferred and preference stock (38.5) (38.5)
Common stock ($1.59 per share) (234.6) (234.6)
Common stock issued 140 3.7 3.7
Other 0.4 0.4
Net unrealized gain on securities 2.6 2.6
Deferred taxes on net unrealized gain on securities (0.9) (0.9)
- ---------------------------------------------------------------------------------------------------------
Balance at December 31, 1996 147,667 1,429.9 1,419.1 5.7 2,854.7
Net income 282.8 282.8
Dividends declared
Preference stock (28.7) (28.7)
Common stock ($1.63 per share) (240.7) (240.7)
Other 3.1 3.1
Net unrealized loss on securities (1.2) (1.2)
Deferred taxes on net unrealized loss on securities 0.4 0.4
- ---------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 147,667 1,433.0 1,432.5 4.9 2,870.4
Net income 327.7 327.7
Dividends declared
Preference stock (21.8) (21.8)
Common stock ($1.67 per share) (248.1) (248.1)
Common stock issued 1,579 51.8 51.8
Other 0.3 0.3
Net unrealized gain on securities 1.8 1.8
Deferred taxes on net unrealized gain on securities (0.6) (0.6)
- ---------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 149,246 $1,485.1 $1,490.3 $6.1 $2,981.5
=========================================================================================================
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH THE CURRENT
YEAR'S PRESENTATION.
44
Consolidated Statements of Capitalization Baltimore Gas and Electric Company
and Subsidiaries
AT DECEMBER 31, 1998 1997
- ---------------------------------------------------------------------------------------------------------
(In millions)
Long-Term Debt
First Refunding Mortgage Bonds of BGE
Floating rate series, due April 15, 1999 $ 125.0 $ 125.0
8.40% Series, due October 15, 1999 91.1 91.1
5 1/2% Series, due July 15, 2000 125.0 125.0
8 3/8% Series, due August 15, 2001 122.3 122.3
7 1/4% Series, due July 1, 2002 124.5 124.5
5 1/2% Installment Series, due July 15, 2002 9.1 9.8
6 1/2% Series, due February 15, 2003 124.8 124.8
6 1/8% Series, due July 1, 2003 124.9 124.9
5 1/2% Series, due April 15, 2004 125.0 125.0
Remarketed floating rate series, due September 1, 2006 125.0 125.0
7 1/2% Series, due January 15, 2007 123.5 123.5
6 5/8% Series, due March 15, 2008 124.9 124.9
7 1/2% Series, due March 1, 2023 125.0 125.0
7 1/2% Series, due April 15, 2023 84.1 100.0
- ---------------------------------------------------------------------------------------------------------
Total First Refunding Mortgage Bonds of BGE 1,554.2 1,570.8
- ---------------------------------------------------------------------------------------------------------
Other long-term debt of BGE
Medium-term notes, Series B 60.0 100.0
Medium-term notes, Series C 116.0 143.0
Medium-term notes, Series D 215.0 225.0
Medium-term notes, Series E 200.0 183.5
Medium-term notes, Series G 140.0 --
Pollution control loan, due July 1, 2011 36.0 36.0
Port facilities loan, due June 1, 2013 48.0 48.0
Adjustable rate pollution control loan, due July 1, 2014 20.0 20.0
5.55% Pollution control revenue refunding loan, due July 15, 2014 47.0 47.0
Economic development loan, due December 1, 2018 35.0 35.0
6.00% Pollution control revenue refunding loan, due April 1, 2024 75.0 75.0
Variable rate pollution control loan, due June 1, 2027 8.8 8.8
- ---------------------------------------------------------------------------------------------------------
Total other long-term debt of BGE 1,000.8 921.3
- ---------------------------------------------------------------------------------------------------------
Company obligated mandatorily redeemable trust
preferred securities of subsidiary trust holding
solely 7.16% deferrable interest subordinated
debentures of the Company due June 30, 2038 250.0 --
- ---------------------------------------------------------------------------------------------------------
Long-term debt of diversified businesses
Loans under revolving credit agreements 74.0 22.0
Mortgage and construction loans
8.69% mortgage note, due January 28, 1998 -- 28.4
7.90% mortgage note, due September 12, 2000 8.3 8.6
8.00% mortgage note, due July 31, 2001 0.1 0.1
8.00% mortgage note, due October 30, 2003 1.8 1.6
7.50% mortgage note, due October 9, 2005 -- 9.7
Variable rate mortgage notes and construction loans, due through 2004 149.5 93.5
7.357% mortgage note, due March 15, 2009 5.1 5.5
9.65% mortgage note, due February 1, 2028 9.6 9.7
8.00% mortgage note, due November 1, 2033 5.8 1.2
Unsecured notes 616.0 579.1
- ---------------------------------------------------------------------------------------------------------
Total long-term debt of diversified businesses 870.2 759.4
- ---------------------------------------------------------------------------------------------------------
Unamortized discount and premium (12.4) (13.7)
Current portion of long-term debt (534.7) (248.9)
- ---------------------------------------------------------------------------------------------------------
Total long-term debt $3,128.1 $2,988.9
- ---------------------------------------------------------------------------------------------------------
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH THE CURRENT
YEAR'S PRESENTATION.
CONTINUED ON PAGE 46
45
Consolidated Statements of Capitalization Baltimore Gas and Electric Company
and Subsidiaries
AT DECEMBER 31, 1998 1997
- -----------------------------------------------------------------------------------------------------------------
(In millions)
Preference Stock
Cumulative, $100 par value, 6,500,000 shares authorized
Redeemable preference stock
7.50%, 1986 Series, 335,000 shares redeemed at $102.50 per share on July 17, 1998;
30,000 shares redeemed at par on October 1, 1998 $ -- $ 36.5
6.75%, 1987 Series, 30,000 shares redeemed at par on April 1, 1998; 395,000
shares redeemed at $102.25 on July 17, 1998 -- 42.5
8.625%, 1990 Series, 130,000 shares redeemed at par on July 1, 1998 -- 13.0
7.85%, 1991 Series, 70,000 shares outstanding and 140,000 shares
redeemed at par on July 1, 1998 7.0 21.0
Current portion of redeemable preference stock (7.0) (23.0)
- -----------------------------------------------------------------------------------------------------------------
Total redeemable preference stock -- 90.0
- -----------------------------------------------------------------------------------------------------------------
Preference stock not subject to mandatory redemption
7.78%, 1973 Series, 200,000 shares redeemed at $101 per share on July 17, 1998 -- 20.0
7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003 40.0 40.0
6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003 50.0 50.0
6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004 40.0 40.0
6.99%, 1995 Series, 600,000 shares outstanding, not callable prior to October 1, 2005 60.0 60.0
- -----------------------------------------------------------------------------------------------------------------
Total preference stock not subject to mandatory redemption 190.0 210.0
- -----------------------------------------------------------------------------------------------------------------
Common Shareholders' Equity
Common stock without par value, 175,000,000 shares authorized; 149,245,641 and
147,667,114 shares issued and outstanding at December 31, 1998 and
1997, respectively. (At December 31, 1998, 166,893 shares were reserved
for the Employee Savings Plan and 2,372,531 shares were reserved for the
Shareholder Investment Plan.) 1,485.1 1,433.0
Retained earnings 1,490.3 1,432.5
Accumulated other comprehensive income 6.1 4.9
- -----------------------------------------------------------------------------------------------------------------
Total common shareholders' equity 2,981.5 2,870.4
- -----------------------------------------------------------------------------------------------------------------
Total Capitalization $6,299.6 $6,159.3
=================================================================================================================
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH THE CURRENT
YEAR'S PRESENTATION.
46
Consolidated Statements of Income Taxes Baltimore Gas and Electric Company and
Subsidiaries
YEAR ENDED DECEMBER 31, 1998 1997 1996
- -------------------------------------------------------------------------------------------------------------------
(Dollar amounts in millions)
Income Taxes
Current $169.5 $158.1 $147.9
- -------------------------------------------------------------------------------------------------------------------
Deferred
Change in tax effect of temporary differences 14.2 (1.0) 22.0
Change in income taxes recoverable through future rates 3.9 8.0 4.9
Deferred taxes credited (charged) to shareholders' equity (0.6) 0.4 (0.9)
- -------------------------------------------------------------------------------------------------------------------
Deferred taxes charged to expense 17.5 7.4 26.0
Investment tax credit adjustments (8.8) (7.5) (7.6)
- -------------------------------------------------------------------------------------------------------------------
Income taxes per Consolidated Statements of Income $178.2 $158.0 $166.3
===================================================================================================================
Reconciliation of Income Taxes Computed at Statutory
Federal Rate to Total Income Taxes
Income before income taxes $505.9 $440.8 $477.1
Statutory federal income tax rate 35% 35% 35%
- -------------------------------------------------------------------------------------------------------------------
Income taxes computed at statutory federal rate 177.1 154.3 167.0
Increases (decreases) in income taxes due to
Depreciation differences not normalized on regulated activities 13.6 13.9 12.6
Allowance for equity funds used during construction (2.2) (1.9) (2.3)
Amortization of deferred investment tax credits (8.8) (7.5) (7.7)
Tax credits flowed through to income (0.3) (0.5) (0.5)
Amortization of deferred tax rate differential on regulated activities (2.3) (2.3) (1.9)
State income taxes 9.8 6.2 4.1
Other (8.7) (4.2) (5.0)
- -------------------------------------------------------------------------------------------------------------------
Total income taxes $178.2 $158.0 $166.3
===================================================================================================================
Effective federal income tax rate 35.2% 35.8% 34.9%
AT DECEMBER 31, 1998 1997
- ----------------------------------------------------------------------------------------------
(In millions)
Deferred Income Taxes
Deferred tax liabilities
Accelerated depreciation $1,009.9 $ 953.5
Allowance for funds used during construction 204.5 206.7
Income taxes recoverable through future rates 88.4 89.8
Deferred termination and postemployment costs 32.3 41.1
Deferred fuel costs 4.5 1.5
Leveraged leases 22.6 25.2
Percentage repair allowance 36.8 38.7
Conservation expenditures 18.9 24.5
Energy trading activities 44.0 2.4
Other 182.6 187.7
- ----------------------------------------------------------------------------------------------
Total deferred tax liabilities 1,644.5 1,571.1
- ----------------------------------------------------------------------------------------------
Deferred tax assets
Accrued pension and postemployment benefit costs 54.3 37.6
Deferred investment tax credits 41.3 44.3
Capitalized interest and overhead 46.6 44.5
Contributions in aid of construction 45.6 39.7
Nuclear decommissioning liability 22.8 20.8
Energy trading activities 30.9 1.4
Other 93.9 87.9
- ----------------------------------------------------------------------------------------------
Total deferred tax assets 335.4 276.2
- ----------------------------------------------------------------------------------------------
Deferred tax liability, net $1,309.1 $1,294.9
==============================================================================================
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
47
Notes to Consolidated Financial Statements
Baltimore Gas and Electric Company and Subsidiaries
Note 1
Significant Accounting Policies
Nature of Our Business
Baltimore Gas and Electric Company (BGE) is the parent company and conducts our
primary business--the electric and gas utility business. That business serves
Baltimore City and all or part of 10 Central Maryland counties. We also conduct
various diversified businesses in subsidiary companies. We describe our
operating segments in Note 2.
Consolidation Policy
We use three different accounting methods to report our investments in our
subsidiaries or other companies: consolidation, the equity method, and the cost
method.
Consolidation
We use consolidation when we own a majority of the voting stock of the
subsidiary. This means the accounts of our subsidiaries are combined with our
accounts. We eliminate intercompany balances and transactions when we
consolidate these accounts. Our consolidated financial statements include the
accounts of:
o BGE,
o Constellation Enterprises, Inc. and Subsidiaries,
o District Chilled Water General Partnership (ComfortLink), and
o BGE Capital Trust I (See Note 7).
The Equity Method
We usually use the equity method to report investments, corporate joint
ventures, partnerships, and affiliated companies (including power projects)
where we hold a 20% to 50% voting interest. Under the equity method, we report:
o our interest in the entity as an investment in our Consolidated Balance
Sheets, and
o our percentage share of the earnings from the entity in our Consolidated
Statements of Income.
The only time we do not use this method is if we can exercise control over the
operations and policies of the company. If we have control, accounting rules
require us to use consolidation.
We report our investment in Safe Harbor Water Power Corporation (Safe Harbor)
under the equity method. Safe Harbor is a producer of hydroelectric power. BGE
owns two-thirds of Safe Harbor's total capital stock, including one-half of the
voting stock, and a two-thirds interest in its retained earnings.
The Cost Method
We usually use the cost method if we hold less than a 20% voting interest in an
investment. Under the cost method, we report our investment at cost in our
Consolidated Balance Sheets. The only time we do not use this method is when we
can exercise significant influence over the operations and policies of the
company. If we have significant influence, accounting rules require us to use
the equity method.
Regulation of Utility Business
The Maryland Public Service Commission (Maryland PSC) regulates our utility
business. Generally, we use the same accounting policies and practices used by
nonregulated companies for financial reporting under generally accepted
accounting principles. However, sometimes the Maryland PSC orders an accounting
treatment different from that used by nonregulated companies to determine the
rates we charge our customers. When this happens, we must defer certain utility
expenses and income in our Consolidated Balance Sheets as regulatory assets and
liabilities. We have recorded these regulatory assets and liabilities in our
Consolidated Balance Sheets in accordance with Statement of Financial Accounting
Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of
Regulation. We summarize and discuss our regulatory assets and liabilities
further in Note 4.
In 1997, the Financial Accounting Standards Board (FASB) through its Emerging
Issues Task Force (EITF) issued EITF 97-4, Deregulation of the Pricing of
Electricity--Issues Related to the Application of FASB Statements No. 71 and
101. The EITF concluded that a company should cease to apply SFAS No. 71 when
either legislation is passed or a regulatory body issues an order that contains
sufficient detail to determine how the transition plan will affect the
deregulated portion of the business. Additionally, a company would continue to
recognize regulated assets and liabilities in the Consolidated Balance Sheets to
the extent that the transition plan provides for their recovery.
At December 31, 1998, we met the requirements of SFAS No. 71. We discuss our
transition proposal for electric utility competition filed with the Maryland PSC
in the "Competition and Response to Regulatory Change" section of Management's
Discussion and Analysis.
48
Utility Revenues
We record utility revenues in our Consolidated Statements of Income when we
provide service to customers.
Fuel and Purchased Energy Costs
We incur costs for:
o the fuel we use to generate electricity,
o purchases of electricity from others, and
o natural gas that we resell.
These costs are shown in our Consolidated Statements of Income as "Electric fuel
and purchased energy" and "Gas purchased for resale." We discuss each of these
separately below.
Fuel Used to Generate Electricity and Purchases of Electricity From Others
Under the electric fuel rate clause set by the Maryland PSC, we charge our
electric customers for:
o the fuel we use to generate electricity (nuclear fuel,
coal, gas, or oil), and
o the net cost of purchases and sales of electricity
(primarily with other utilities).
We charge the actual costs of these items to customers with no profit to us. To
do this, we must keep track of what we spend and what we collect from customers
under the fuel rate in a given period. Usually these two amounts are not the
same because there is a difference between the time we spend the money and the
time we collect it from our customers.
Under the electric fuel rate clause, we defer (include as an asset or liability
in our Consolidated Balance Sheets and exclude from our Consolidated Statements
of Income) the difference between our actual costs of fuel and energy and what
we collect from customers under the fuel rate in a given period. We either bill
or refund our customers that difference in the future. We discuss this further
in Note 4.
We calculate the electric fuel rate using three factors:
o the mix of generating plants we used over the last
24 months,
o the latest three-month average fuel cost for each
generating unit, and
o the net cost of purchases and sales of electricity over
the last 24 months.
We may change the fuel rate only if the calculated rate is more than 5% above or
below the rate in effect. The fuel rate is affected most by the amount of
electricity generated at our Calvert Cliffs Nuclear Power Plant (Calvert Cliffs)
because the cost of nuclear fuel is cheaper than coal, gas, or oil.
We also report two other items as "Electric fuel and purchased energy" in our
Consolidated Statements of Income:
o amortization of nuclear fuel (described under "Utility Plant" later in this
note). We amortize nuclear fuel based on the energy produced over the life of
the fuel. We pay quarterly fees to the Department of Energy for the future
disposal of spent nuclear fuel, and accrue these fees based on the
kilowatt-hours of electricity sold. We bill our customers for nuclear fuel as
described earlier in this note, and
o amortization of deferred costs of decommissioning and decontaminating the
Department of Energy's uranium enrichment facilities. We discuss these costs
further in Note 4.
Extended outages at Calvert Cliffs increase fuel costs and may result in fuel
rate proceedings before the Maryland PSC. In these proceedings, the Maryland PSC
would consider whether any portion of the extra fuel costs should be paid by BGE
instead of passed on to customers. We discuss the financial impact of past
extended outages in Note 10.
Natural Gas
We charge our gas customers for the natural gas they purchase from us using "gas
cost adjustment clauses" set by the Maryland PSC. These clauses operate
similarly to the electric fuel rate clause described earlier in this note.
However, effective October 1996, the Maryland PSC approved a modification of the
gas cost adjustment clauses to provide a market based rates incentive mechanism.
Under market based rates our actual cost of gas is compared to a market index (a
measure of the market price of gas in a given period). The difference between
our actual cost and the market index is shared equally between shareholders and
customers.
Risk Management
We engage in risk management activities in our gas business and in our
diversified businesses. We separately describe these activities for each
business below.
Gas Business
We use basis swaps in the winter months (November through March) to hedge our
price risk associated with natural gas purchases under our market based rates
incentive mechanism. We also use fixed-to-floating and floating-to-fixed swaps
to hedge our price risk associated with our off-system gas sales. The fixed
portion represents a specific dollar amount that we will pay or receive and the
floating portion represents a fluctuating amount based on a published index that
we will receive or pay.
49
Our gas business internal guidelines do not permit the use of swap agreements
for any other purpose than to hedge price risk.
We defer, as unrealized gains or losses, the net amount we are due (unrealized
gains) or owe (unrealized losses) under the swap agreements in our Consolidated
Balance Sheets.
When amounts are paid under the agreements, we report the payments as gas costs
in our Consolidated Statements of Income.
Diversified Businesses
Our subsidiary, Constellation Power Source, engages in power marketing
activities, which include trading electricity, other energy commodities, and
related derivatives (such as futures, forwards, options, and swaps).
Constellation Power Source uses the mark-to-market method of accounting for its
trading activities.
Under the mark-to-market method of accounting, we report:
o commodity positions and derivatives at fair value as "Assets from energy
trading activities" or "Liabilities from energy trading activities" in our
Consolidated Balance Sheets, and
o changes in fair value as components of "Diversified business revenues" in
our Consolidated Statements of Income.
Taxes
We summarize our income taxes in our Consolidated Statements of Income Taxes. As
you read this section, it may be helpful to refer to those statements.
Income Tax Expense
We have two categories of income taxes in our Consolidated Statements of
Income--current and deferred. We describe each of these below.
Our current income tax expense consists solely of regular tax less applicable
tax credits. Our 1996 current income tax expense amount includes alternative
minimum tax credits of $30 million. The alternative minimum tax can be carried
forward indefinitely and used as tax credits in years when our regular tax
liability exceeds the alternative minimum tax liability. We do not have any
remaining alternative minimum tax credits.
Our deferred income tax expense is equal to the changes in the net deferred
income tax liability, excluding amounts charged or credited to common
shareholders' equity. Our deferred income tax expense is increased or reduced
for changes to the net regulatory asset (described later in this note) during
the year.
Investment Tax Credits
We have deferred the investment tax credit associated with our regulated utility
business in our Consolidated Balance Sheets. The investment tax credit is
amortized evenly to income over the life of each property. We reduce income tax
expense in our Consolidated Statements of Income for the investment tax credit
and other tax credits associated with our diversified businesses, other than
leveraged leases.
Deferred Income Tax Assets and Liabilities
We must report some of our revenues and expenses differently for our financial
statements than we do for income tax purposes. The tax effects of the
differences in these items are reported as deferred income tax assets or
liabilities in our Consolidated Balance Sheets. We measure the assets and
liabilities using income tax rates that are currently in effect.
A portion of our total deferred income tax liability relates to our utility
business, but has not been reflected in the rates we charge our customers. We
refer to this portion of the liability as "Income taxes recoverable or payable
through future rates." We have recorded that portion of the net liability as a
regulatory asset in our Consolidated Balance Sheets.
We discuss this further in Note 4.
Franchise Taxes
We pay Maryland public service company franchise tax instead of state income tax
on our utility revenue from sales in Maryland. We include the franchise tax in
"Taxes other than income taxes" in our Consolidated Statements of Income.
Inventory
We report the majority of our fuel stocks and materials and supplies at average
cost.
Real Estate Projects and Investments
In Note 3, we summarize the real estate projects and investments that are in our
Consolidated Balance Sheets. The projects and investments consist of:
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,
o senior-living facilities, and
o beginning in 1998, a 41.9% equity interest in Corporate Office Properties
Trust, a real estate investment trust.
The costs incurred to acquire and develop properties are included as part of the
cost of the properties.
50
Evaluation of Assets for Impairment
SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of, applies particular requirements to some of
our assets that have long lives. (Some examples are utility property and
equipment and real estate.) We determine if those assets are impaired by
comparing their undiscounted expected future cash flows to their carrying amount
in our accounting records. We recognize an impairment loss if the undiscounted
expected future cash flows are less than the carrying amount of the asset.
Financial Investments and Trading Securities
In Note 3, we summarize the financial investments that are in our Consolidated
Balance Sheets.
SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities,
applies particular requirements to some of our investments in debt and equity
securities. We report those investments at fair value, and we use specific
identification to determine their cost for computing realized gains or losses.
We classify these investments as either trading securities or available-for-sale
securities, which we describe separately below. We report investments that are
not covered by SFAS No. 115 at their cost.
Trading Securities
Our diversified businesses classify some of their investments in marketable
equity securities and financial limited partnerships as trading securities. We
include any unrealized gains or losses on these securities in "Diversified
business revenues" in our Consolidated Statements of Income.
Available-for-Sale Securities
We classify our investments in the nuclear decommissioning trust fund as
available-for-sale securities. We include any unrealized gains or losses on the
trust assets as a change in the decommissioning reserve. We describe the nuclear
decommissioning trust and the reserve under the heading "Decommissioning Costs"
later in this note.
In addition, our diversified businesses classify some of their investments in
marketable equity securities as available-for-sale securities. We include any
unrealized gains or losses on these securities in "Accumulated other
comprehensive income" in our Consolidated Statements of Common Shareholders'
Equity and in the Consolidated Statements of Capitalization. We also include our
diversified businesses' portion of unrealized gains or losses on securities of
equity-method (described earlier in this note) investees in our Consolidated
Statements of Common Shareholders' Equity.
Utility Plant, Depreciation, Amortization, and Decommissioning
Utility Plant
Utility plant is the term we use to describe our utility business property and
equipment that is in use, being held for future use, or under construction. We
summarize utility plant in our Consolidated Balance Sheets. We report our
utility plant at its original cost, which includes:
o material and labor,
o contractor costs,
o construction overhead costs (where applicable), and
o an allowance for funds used during construction (described later in this
note).
We charge retired or otherwise-disposed-of utility plant to accumulated
depreciation.
We own an undivided interest in the Keystone and Conemaugh electric generating
plants in Western Pennsylvania, as well as in the transmission line that
transports the plants' output to the joint owners' service territories. Our
ownership interests in these plants are 20.99% in Keystone and 10.56% in
Conemaugh. These ownership interests represented a net investment of $152
million at December 31, 1998 and 1997. We report these properties in the same
accounts we use for our other utility plant (described above).
Depreciation Expense
Generally, we compute depreciation by applying composite, straight-line rates
(approved by the Maryland PSC) to the average investment in classes of
depreciable property. We depreciate vehicles based on their estimated useful
lives.
Amortization Expense
Amortization is an accounting process of reducing an amount in our Consolidated
Balance Sheets evenly over a period of time. When we reduce amounts in our
Consolidated Balance Sheets, we increase amortization expense in our
Consolidated Statements of Income. An amount is considered fully amortized when
it has been reduced to zero.
Decommissioning Costs
We must accumulate a reserve for the costs that we expect to incur in the future
to decommission the radioactive portion of Calvert Cliffs. We do this based on a
sinking fund methodology. The Maryland PSC authorized us to record
decommissioning expense based on a facility-specific cost estimate so we can
accumulate a decommissioning reserve of $521.0 million in 1993 dollars by the
end of Calvert Cliffs' service life in 2016, adjusted to reflect expected
inflation. We have reported the decommissioning reserve in "Accumulated
depreciation" in our Consolidated Balance Sheets. The total reserve was $244.0
million at December 31, 1998 and $201.6 million at December 31, 1997.
51
To fund the costs we expect to incur to decommission the plant, we established
an external decommissioning trust in accordance with Nuclear Regulatory
Commission (NRC) regulations. We report the assets in the trust in "Nuclear
decommissioning trust fund" in our Consolidated Balance Sheets. The NRC requires
utilities to provide financial assurance that they will accumulate sufficient
funds to pay for the cost of nuclear decommissioning based upon either a generic
NRC formula or a facility-specific decommissioning cost estimate. We use the
facility-specific cost estimate for funding these costs and providing the
required financial assurance.
Allowance for Funds Used During Construction and Capitalized Interest
Allowance for Funds Used During Construction (AFC)
We finance construction projects with borrowed funds and equity funds. We are
allowed by the Maryland PSC to record the costs of these funds as part of the
cost of construction projects in our Consolidated Balance Sheets. We do this
through the AFC, which we calculate using a rate authorized by the Maryland PSC.
We bill our customers for the AFC plus a return after the utility plant is
placed in service.
The AFC rates are 9.04% for gas plant, 9.36% for common plant, and 9.40% for
electric plant. We compound AFC annually.
Capitalized Interest
Our diversified businesses capitalize interest costs incurred to finance real
estate developed for internal use and certain power projects.
Long-Term Debt
We defer (include as an asset or liability in our Consolidated Balance Sheets
and exclude from our Consolidated Statements of Income) all costs related to the
issuance of long-term debt. These costs include underwriters' commissions,
discounts or premiums, and other costs such as legal, accounting and regulatory
fees, and printing costs. We amortize these costs over the life of the debt.
When we incur gains or losses on debt that we retire prior to maturity, we
amortize those gains or losses over the remaining original life of the debt.
Cash Flows
For the purpose of reporting our cash flows, we define cash equivalents as
highly liquid investments that mature in three months or less.
Use of Accounting Estimates
Management makes estimates and assumptions when preparing financial statements
under generally accepted accounting principles. These estimates and assumptions
affect various matters, including:
o our reported amounts of assets and liabilities in our Consolidated Balance
Sheets at the dates of the financial statements,
o our disclosure of contingent assets and liabilities at the dates of the
financial statements, and
o our reported amounts of revenues and expenses in our Consolidated Statements
of Income during the reporting periods.
These estimates involve judgments with respect to, among other things, future
economic factors that are difficult to predict and are beyond management's
control. As a result, actual amounts could differ from these estimates.
Reclassifications
We have reclassified certain prior-year amounts for comparative purposes. These
reclassifications did not affect consolidated net income for the years
presented.
Accounting Standards Adopted
We adopted SFAS No. 130, Reporting Comprehensive Income, effective January 1,
1998. Comprehensive income includes net income plus all changes in shareholders'
equity for the period, excluding shareholder transactions (some examples are
stock issuances and dividend payments). Our comprehensive income includes net
income plus the effect of unrealized gains or losses on available-for-sale
securities. We have presented comprehensive income in the Consolidated
Statements of Comprehensive Income, and accumulated other comprehensive income
in the Consolidated Statements of Common Shareholders' Equity and in the
Consolidated Statements of Capitalization.
We adopted SFAS No. 131, Disclosures about Segments of an Enterprise and Related
Information, effective January 1, 1998. SFAS No. 131 establishes standards for
the way that we report information about operating segments in annual financial
statements and requires that we report selected information about operating
segments in interim financial reports. SFAS No. 131 also establishes standards
for related disclosures about products and services, geographic areas, and major
customers. The adoption of this statement did not affect results of operations
or financial position, but did affect the disclosure of segment information. See
Note 2.
52
We adopted SFAS No. 132, Employers' Disclosures about Pensions and Other
Postretirement Benefits, effective January 1, 1998. SFAS No. 132 establishes
standards for the way that we report our pension and postretirement benefits as
well as requiring additional information on changes in the benefit obligations
and fair values of plan assets. The adoption of this statement did not affect
results of operations or financial position, but did affect the disclosure of
pension and postretirement benefits information. See Note 5.
Accounting Standards Issued
In March 1998, the American Institute of Certified Public Accountants (AICPA)
issued Statement of Position (SOP) 98-1, Accounting for the Costs of Computer
Software Developed or Obtained for Internal Use. SOP 98-1 establishes the
accounting for the costs of computer software developed or obtained for internal
use. We must adopt the requirements of this statement in our financial
statements for the year ending December 31, 1999.
In April 1998, the AICPA issued SOP 98-5, Reporting on the Costs of Start-up
Activities. SOP 98-5 establishes the accounting for the costs of start-up
activities. We must adopt the requirements of this statement in our financial
statements for the year ending December 31, 1999.
We do not expect the adoption of these statements to have a material impact on
our financial results.
In June 1998, the FASB issued SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities. SFAS No. 133 establishes the accounting and
disclosure standards for derivative financial instruments and hedging
Activities. We must adopt the requirements of this standard beginning with our
financial statements for the quarter ending March 31, 2000. We have not
determined the effects of SFAS No. 133 on our financial results.
In November 1998, the EITF reached a consensus on EITF 98-10, Accounting for
Energy Trading and Risk Management Activities, requiring that energy trading
activities be accounted for on a mark-to-market basis. We must adopt the
requirements of this consensus in our financial statements for the year ending
December 31, 1999. We do not expect the adoption of this consensus to have a
material impact on our financial results.
- --------------------------------------------------------------------------------
Note 2
Information by Operating Segment
We have three reportable operating segments: Electric, Gas, and Energy Services:
o our Electric business generates, purchases, and sells electricity,
o our Gas business purchases, transports, and sells natural gas, and
o our Energy Services businesses consist of certain diversified businesses
that:
-- engage in power projects,
-- provide marketing and risk management services,
-- sell natural gas through mass marketing efforts, sell and service
electric and gas appliances, heating and air conditioning systems, and
engage in home improvements, and
-- provide cooling services to commercial customers in Baltimore.
Our remaining diversified businesses:
o engage in financial investments, and
o develop, own, and manage real estate and
senior-living facilities.
These reportable segments are strategic businesses based principally upon
regulations, products, and services that require different technology and
marketing strategies. The segments have the same accounting policies as those
described in the summary of significant accounting policies in Note 1. We
evaluate the performance of these segments based on net income. We account for
intersegment revenues using market prices.
A summary of information by operating segment is shown on page 54.
53
Energy Other Unallocated
Electric Gas Services Diversified Corporate
Business Business Businesses Businesses Items (A) Eliminations Consolidated
- ---------------------------------------------------------------------------------------------------------------------------
(In millions)
1998
Unaffiliated revenues $2,219.2 $449.4 $ 524.1 $165.4 $ -- $ -- $3,358.1
Intersegment revenues 1.6 1.7 12.0 0.5 -- (15.8) --
- ---------------------------------------------------------------------------------------------------------------------------
Total revenues 2,220.8 451.1 536.1 165.9 -- (15.8) 3,358.1
Depreciation and amortization 313.0 45.4 9.2 9.3 0.2 -- 377.1
Equity in earnings of equity-
method investees (B) 5.0 -- -- -- -- -- 5.0
Net interest expense 164.9 23.6 16.0 38.6 (1.9) (0.3) 240.9
Income tax expense (benefit) 146.6 13.4 34.1 (15.8) (0.1) -- 178.2
Net income (loss) (C) 278.7 28.8 43.4 (24.2) (0.1) 1.1 327.7
Segment assets 6,342.8 934.6 1,235.0 811.6 (14.0) (115.0) 9,195.0
Utility construction expenditures 279.0 60.4 -- -- -- -- 339.4
1997
Unaffiliated revenues $2,191.7 $521.6 $ 399.4 $194.9 $ -- $ -- $3,307.6
Intersegment revenues 0.3 -- 0.6 9.7 -- (10.6) --
- ---------------------------------------------------------------------------------------------------------------------------
Total revenues 2,192.0 521.6 400.0 204.6 -- (10.6) 3,307.6
Depreciation and amortization 286.5 39.3 6.9 9.9 0.3 -- 342.9
Equity in earnings of equity-
method investees (B) 5.0 -- -- -- -- -- 5.0
Net interest expense 160.7 20.3 10.1 32.5 6.4 -- 230.0
Income tax expense (benefit) 135.7 13.9 23.8 (13.5) (1.9) -- 158.0
Net income (loss) (D) 249.6 28.8 27.4 (21.1) (3.6) 1.7 282.8
Segment assets 6,404.4 907.7 700.9 885.4 10.7 (9.1) 8,900.0
Utility construction expenditures 278.7 94.5 -- -- -- -- 373.2
1996
Unaffiliated revenues $2,208.7 $517.3 $ 313.3 $113.9 $ -- $ -- $3,153.2
Intersegment revenues 0.3 -- 1.0 5.8 -- (7.1) --
- ---------------------------------------------------------------------------------------------------------------------------
Total revenues 2,209.0 517.3 314.3 119.7 -- (7.1) 3,153.2
Depreciation and amortization 279.3 37.8 3.2 9.6 0.3 -- 330.2
Equity in earnings of equity-
method investees (B) 4.6 -- -- -- -- -- 4.6
Net interest expense 150.6 17.5 7.2 24.4 (1.2) -- 198.5
Income tax expense (benefit) 121.7 16.0 23.8 8.9 (4.1) -- 166.3
Net income (loss) (E) 230.9 33.9 30.6 16.8 (1.7) 0.3 310.8
Segment assets 6,466.5 826.8 485.5 901.4 11.0 (13.0) 8,678.2
Utility construction expenditures 262.5 98.0 -- -- -- -- 360.5
(A) A holding company for our diversified businesses does not allocate the items
presented in the table to our Energy Services and Other Diversified
businesses.
(B) Our Energy Services and our Other Diversified businesses record their equity
in earnings of equity-method investees in their unaffiliated revenues.
(C) Our Energy Services businesses recorded $10.4 million for its share of
earnings in a partnership as discussed in Note 3 and a $5.5 million
write-off of an energy services investment as discussed in the "Other Energy
Services" section of Management's Discussion and Analysis. In addition, our
Other Diversified businesses recorded a $15.4 million write-down of a real
estate project as discussed in Note 3.
(D) Our Electric business recorded a $37.5 million write-off related to the
terminated merger with Potomac Electric Power Company as discussed in the
"Write-Off of Merger Costs" section of Management's Discussion and Analysis.
In addition, our Other Diversified businesses recorded a $46.0 million
write-down of two real estate projects as discussed in Note 3.
(E) Our Electric business recorded a $62.1 million write-off of electric
replacement energy costs as discussed in Note 10. In addition, our Energy
Services businesses recorded $14.6 million for its share of earnings in a
partnership and $16.2 million of write-offs of several power projects as
discussed in Note 3.
54
Note 3
Investments
Real Estate Projects and Investments
Real estate projects and investments held by Constellation Real Estate Group
(CREG), consist of the following:
At December 31, 1998 1997
- ---------------------------------------------------------
(In millions)
Properties under development $210.6 $220.8
Rental and operating properties
(net of accumulated depreciation) 38.9 225.6
Equity interest in real estate
investment trust 104.0 --
Other real estate ventures 0.4 0.4
- ---------------------------------------------------------
Total real estate projects
and investments $353.9 $446.8
=========================================================
In 1998, CREG recorded a $15.4 million after-tax write-down of the investment in
Church Street Station--an entertainment, dining, and retail complex in Orlando,
Florida--which occurred because the fair value of the project has declined based
upon recent competitive bids. CREG is attempting to sell this complex during
1999.
In 1998, CREG entered into an agreement with Corporate Office Properties Trust
(COPT), a real estate investment trust based in Philadelphia.
Under the terms of the agreement, COPT assumed approximately $62 million of
CREG's outstanding debt, paid CREG approximately $22.8 million in cash, and
issued to CREG approximately 7.0 million common shares, representing a 41.9%
equity interest in COPT, and 985,000 convertible preferred shares. Each
convertible preferred share yields 5.5% per year, and is convertible after two
years into 1.8748 common shares.
In exchange, COPT received 14 operating properties and two properties under
development from CREG as well as certain other assets, options, and first
refusal rights. These options and first refusal rights are related to
approximately 91 acres of identified properties which are adjacent to operating
properties being acquired by COPT. These options and first refusal rights have
terms that range from 2-5 years.
By July 1999, COPT is expected to acquire one retail property from CREG for
approximately $3.5 million in cash, unless that property is sold to another
party prior to that time.
In 1997, CREG recorded the following write-downs of real estate projects:
o a $14.1 million after-tax write-down of the investment in Church Street
Station--which occurred because CREG decided to sell rather than keep the
project, and
o a $31.9 million after-tax write-down of the investment in Piney Orchard--a
mixed-use, planned-unit development--which occurred because the expected
future cash flow from the project was less than CREG's investment in the
project.
Power Projects
Power projects held by our diversified businesses consist of the following:
At December 31, 1998 1997
- ----------------------------------------------
(In millions)
Domestic
East $ 39.8 $ 41.3
West 426.2 377.7
International
South America 21.6 18.3
Central America 161.8 5.2
Other 7.4 9.2
- ----------------------------------------------
Total power projects $656.8 $451.7
==============================================
Our Domestic-West power projects include investments of $310.6 million in 1998
and $261.4 million in 1997 that sell electricity in California under power
purchase agreements called "Interim Standard Offer No. 4" agreements. We discuss
these projects further in Note 10.
In 1998, our power projects business recorded a $10.4 million after-tax gain for
its share of earnings in a partnership. The partnership recognized a gain on the
sale of its ownership interest in a power sales contract.
In 1996, our power projects business recorded a $14.6 million after-tax gain for
its share of earnings in a partnership. The partnership recognized a gain on the
sale of a power purchase agreement. In addition, our power projects business had
the following write-offs:
o a $7.0 million after-tax write-off of an investment in two geothermal
wholesale power generating projects that sell electricity under California
power purchase agreements. These projects were written off because the
expected future cash flow from the projects were less than the investments in
the projects,
o a $3.0 million after-tax write-off of development costs for a coal-fired
power project when development efforts on the project were terminated, and
o a $6.2 million after-tax write-off of a portion of an investment in a solar
power project to reflect a settlement with the project's lender.
Financial Investments
Financial investments consist of the following:
At December 31, 1998 1997
- -----------------------------------------------
(In millions)
Insurance company $102.5 $ 88.8
Marketable equity securities 25.3 33.3
Financial limited partnerships 41.9 43.6
Leveraged leases 28.3 30.8
- -----------------------------------------------
Total financial investments $198.0 $196.5
===============================================
55
Investments Classified as Available-for-Sale
We classify our investments in the nuclear decommissioning trust fund as
available-for-sale. In addition, we classify some of our diversified businesses'
marketable equity securities as available-for-sale. This means we do not expect
to hold them to maturity and we do not consider them trading securities.
We show the fair values, gross unrealized gains and losses, and amortized cost
bases for all of our available-for-sale securities, exclusive of $6.2 million in
1998 and $3.5 million in 1997 of unrealized net gains on securities of
equity-method investees, in the following tables:
Amortized Unrealized Unrealized Fair
At December 31, 1998 Cost Basis Gains Losses Value
- ------------------------------------------------------------------------
(In millions)
Marketable Equity
Securities $ 82.9 $24.2 $(0.4) $106.7
U.S. Government agency 12.7 0.4 -- 13.1
State municipal bonds 64.8 2.7 -- 67.5
- ------------------------------------------------------------------------
Totals $160.4 $27.3 $(0.4) $187.3
========================================================================
Amortized Unrealized Unrealized Fair
At December 31, 1997 Cost Basis Gains Losses Value
- ------------------------------------------------------------------------
(In millions)
Marketable Equity
Securities $ 77.3 $12.0 $(0.5) $ 88.8
U.S. Government agency 14.9 0.2 -- 15.1
State municipal bonds 65.5 2.2 -- 67.7
- ------------------------------------------------------------------------
Totals $157.7 $14.4 $(0.5) $171.6
========================================================================
These tables include $23.9 million in 1998 and $10.0 million in 1997 of
unrealized net gains associated with the nuclear decommissioning trust fund
which are reflected as a change in the nuclear decommissioning trust fund on the
Consolidated Balance Sheets.
Gross and net realized gains and losses on available-for-sale securities were as
follows:
1998 1997 1996
- -----------------------------------------------
(In millions)
Gross realized gains $4.2 $ 9.3 $ 4.3
Gross realized losses (0.7) (0.6) (0.2)
- -----------------------------------------------
Net realized gains $3.5 $ 8.7 $ 4.1
===============================================
The U.S. Government agency obligations and state municipal bonds mature on the
following schedule:
At December 31, 1998 Amount
- --------------------------------------------------
(In millions)
Less than 1 year $ --
1-5 years 33.5
5-10 years 29.9
More than 10 years 17.2
- --------------------------------------------------
Total maturities of debt securities $ 80.6
==================================================
- --------------------------------------------------------------------------------
Note 4
Regulatory Assets (net)
As discussed in Note 1, the Maryland PSC regulates our utility business.
Generally, we use the same accounting policies and practices used by
nonregulated companies for financial reporting under generally accepted
accounting principles. However, sometimes the Maryland PSC orders an accounting
treatment different from that used by nonregulated companies to determine the
rates we charge our customers. When this happens, we must defer certain utility
expenses and income in our Consolidated Balance Sheets as regulatory assets and
liabilities. We then record them in our Consolidated Statements of Income (using
amortization) when we include them in the rates we charge our customers.
We summarize our regulatory assets and liabilities in the following table, and
we discuss each of them separately on page 57.
At December 31, 1998 1997
- ------------------------------------------------------------
(In millions)
Income taxes recoverable
through future rates (net) $252.6 $256.5
Deferred postretirement and
postemployment benefit costs 90.0 96.4
Deferred nuclear expenditures 73.3 77.7
Deferred conservation expenditures 53.4 55.8
Deferred costs of decommissioning
federal uranium enrichment facilities 38.5 42.4
Deferred environmental costs 33.4 38.8
Deferred fuel costs (net) 12.7 4.4
Deferred termination benefit costs 2.2 21.0
Other (net) 9.6 4.3
- ------------------------------------------------------------
Total regulatory assets (net) $565.7 $597.3
============================================================
56
Income Taxes Recoverable Through Future Rates (net)
As described in Note 1, income taxes recoverable through future rates are the
portion of our net deferred income tax liability that is applicable to our
utility business, but has not been reflected in the rates we charge our
customers. These income taxes represent the tax effect of temporary differences
in depreciation and the allowance for equity funds used during construction,
offset by differences in deferred tax rates and deferred taxes on deferred
investment tax credits. We amortize these amounts as the temporary differences
reverse.
Deferred Postretirement and Postemployment Benefit Costs
Deferred postretirement and postemployment benefit costs are the costs we
recorded under SFAS No. 106 (for postretirement benefits) and SFAS No. 112 (for
postemployment benefits) in excess of the costs we included in the rates we
charge our customers. We began amortizing these costs over a 15-year period in
1998. We discuss these costs further in Note 5.
Deferred Nuclear Expenditures
Deferred nuclear expenditures are the net unamortized balance of certain
operations and maintenance costs at Calvert Cliffs. These expenditures consist
of:
o costs incurred from 1979 through 1982 for inspecting and repairing seismic
pipe supports,
o expenditures incurred from 1989 through 1994 associated with nonrecurring
phases of certain nuclear operations projects, and
o expenditures incurred during 1990 for investigating leaks in the pressurizer
heater sleeves.
We are amortizing these costs over the remaining life of the plant in accordance
with the Maryland PSC's orders.
Deferred Conservation Expenditures
Deferred conservation expenditures include two components:
o operations costs (labor, materials, and indirect costs) associated with
conservation programs approved by the Maryland PSC, which we are amortizing
over periods of four to five years in accordance with the Maryland PSC's
orders, and
o revenues we collected from customers in 1996 in excess of our profit limit
under the conservation surcharge.
The Maryland PSC allows us to collect from customers money spent on conservation
programs under a "conservation surcharge." However, under this surcharge the
Maryland PSC limits what our profit can be. If, at the end of the year, we have
exceeded our allowed profit, we defer the excess in that year and we lower the
amount of future surcharges to our customers to correct the amount of overage,
plus interest.
During 1996, we exceeded our profit limit under the conservation surcharge. As a
result, we deferred $28.5 million of our 1996 revenue from surcharge billings as
a regulatory liability. To correct the overage, we lowered the surcharge on our
customers' bills over a 12-month period beginning July 1997 through June 1998.
Deferred Costs of Decommissioning Federal Uranium Enrichment Facilities
Deferred costs of decommissioning federal uranium enrichment facilities are the
unamortized portion of our required contributions to a fund for decommissioning
and decontaminating the Department of Energy's uranium enrichment facilities. We
are required, along with other domestic utilities, by the Energy Policy Act of
1992 to make contributions to the fund. The contributions are generally payable
over 15 years with escalation for inflation and are based upon the proportionate
amount of uranium enriched by the Department of Energy for each utility. We are
amortizing these costs over the contribution period as a cost of fuel. We also
discuss this in Note 1.
Deferred Environmental Costs
Deferred environmental costs are the estimated costs of investigating and
cleaning up contaminated sites we own. We discuss this further in Note 10. We
are amortizing $21.6 million of these costs (the amount we had incurred through
October 1995) over a 10-year period in accordance with the Maryland PSC's
November 1995 order.
Deferred Fuel Costs
As described in Note 1, deferred fuel costs are the difference between our
actual costs of electric fuel, net purchases and sales of electricity, and
natural gas and our fuel rate revenues collected from customers. We reduce
deferred fuel costs as we collect them from or refund them to our customers.
We show our deferred fuel costs in the following table:
At December 31, 1998 1997
- ---------------------------------------------------------
(In millions)
Electric over-recovered fuel costs $(11.5) $(19.0)
Gas deferred fuel costs 24.2 23.4
- ---------------------------------------------------------
Deferred fuel costs (net) $ 12.7 $ 4.4
=========================================================
Deferred Termination Benefits
Deferred termination benefit costs are the net unamortized balance of the cost
of certain termination benefits offered to employees of our regulated utility
operations in 1992 and 1993. We are amortizing these costs over a five-year
period in accordance with the Maryland PSC's orders.
57
Note 5
Pension, Postretirement, Other Postemployment, and Employee Savings Plan
Benefits
We offer pension, postretirement, other postemployment, and employee savings
plan benefits. We describe each of these separately below.
Pension Benefits
We sponsor several defined benefit pension plans for our employees. A defined
benefit plan specifies the amount of benefits a plan participant is to receive
using information about the participant. Our largest plan covers nearly all BGE
employees and certain employees of our subsidiaries. Our other plans, which are
not material in amount, provide supplemental benefits to certain key employees.
Our employees do not contribute to these plans. Generally, we calculate the
benefits under these plans based on age, years of service, and pay.
Sometimes we amend the plans retroactively. These retro-
active plan amendments require us to recalculate benefits related to
participants' past service. We amortize the change in the benefit costs from
these plan amendments on a straight-line basis over the average remaining
service period of active employees.
We fund the plans by contributing at least the minimum amount required under
Internal Revenue Service regulations. We calculate the amount of funding using
an actuarial method called the projected unit credit cost method. The assets in
all of the plans at December 31, 1998 were mostly marketable equity and fixed
income securities, and group annuity contracts.
Postretirement Benefits
We sponsor defined benefit postretirement health care and life insurance plans
which cover nearly all BGE employees and certain employees of our subsidiaries.
Generally, we calculate the benefits under these plans based on age, years of
service, and pension benefit levels.
We do not fund these plans.
For nearly all of the health care plans, retirees make contributions to cover a
portion of the plan costs. Contributions for employees who retire after June 30,
1992 are calculated based on age and years of service. The amount of retiree
contributions increases based on expected increases in medical costs. For the
life insurance plan, retirees do not make contributions to cover a portion of
the plan costs.
Effective January 1, 1993, we adopted SFAS No. 106, Employers' Accounting for
Postretirement Benefits Other Than Pensions. The adoption of that statement
caused:
o a transition obligation, which we are amortizing over
20 years, and
o an increase in annual postretirement benefit costs.
For our diversified businesses, we expense all postretirement benefit costs. For
our utility business, we accounted for the increase in annual postretirement
benefit costs under two Maryland PSC rate orders:
o in an April 1993 rate order, the Maryland PSC allowed us to expense one-half
and defer, as a regulatory asset (see Note 4), the other half of the increase
in annual postretirement benefit costs related to our electric and gas
businesses, and
o in a November 1995 rate order, the Maryland PSC allowed us to expense all of
the increase in annual postretirement benefit costs related to our gas
business.
Beginning in 1998, the Maryland PSC authorized us to:
o expense all of the increase in annual postretirement benefit costs related to
our electric business, and
o amortize the regulatory asset for postretirement benefit costs related to
our electric and gas businesses over 15 years.
Obligations, Assets, and Funded Status
We show the change in the benefit obligations, plan assets, and funded status of
the pension and postretirement benefit plans in the following table:
Postretirement
Pension Benefits Benefits
1998 1997 1998 1997
- ----------------------------------------------------------------------------
(In millions)
Change in benefit obligation
Benefit obligation at
January 1, $ 902.0 $846.3 $320.3 $311.0
Service cost 21.6 16.8 6.6 5.4
Interest cost 63.0 61.3 23.4 21.8
Plan participants'
contributions -- -- 2.0 2.0
Actuarial loss (gain) 102.9 35.5 48.9 (2.1)
Benefits paid (58.2) (57.9) (18.1) (17.8)
- ----------------------------------------------------------------------------
Benefit obligation at
December 31, $1,031.3 $902.0 $383.1 $320.3
============================================================================
Change in plan assets
Fair value of plan assets
at January 1, $912.3 $795.4 $ -- $ --
Actual return on plan
assets 116.9 130.0 -- --
Employer contribution 14.5 44.8 16.1 15.8
Plan participants'
contributions -- -- 2.0 2.0
Benefits paid (58.2) (57.9) (18.1) (17.8)
- ----------------------------------------------------------------------------
Fair value of plan assets
at December 31, $985.5 $912.3 $ -- $ --
============================================================================
58
Postretirement
Pension Benefits Benefits
1998 1997 1998 1997
- --------------------------------------------------------------
(In millions)
Funded status
Funded status at
December 31, $ (45.8) $ 10.3 $(383.1) $(320.3)
Unrecognized net
actuarial loss 137.6 84.2 59.7 10.9
Unrecognized prior
service cost 16.9 19.4 -- --
Unrecognized transition
obligation -- -- 159.3 170.6
Unamortized net asset
from adoption of
SFAS No. 87 (0.7) (0.9) -- --
- --------------------------------------------------------------
Prepaid (accrued)
benefit cost $108.0 $113.0 $(164.1) $(138.8)
==============================================================
Net Periodic Benefit Cost
We show the components of net periodic pension benefit cost in the following
table:
Year Ended December 31, 1998 1997 1996
- ------------------------------------------------------------------
(In millions)
Components of net periodic
pension benefit cost
Service cost $21.6 $16.8 $16.1
Interest cost 63.0 61.3 59.9
Expected return on plan assets (72.1) (66.9) (62.8)
Amortization of transition asset (0.2) (0.2) (0.2)
Amortization of prior service cost 2.5 2.5 2.5
Recognized net actuarial loss 5.6 4.6 4.9
Amount capitalized as
construction cost (3.8) (2.5) (2.4)
- ------------------------------------------------------------------
Net periodic pension
benefit cost $16.6 $15.6 $18.0
==================================================================
We show the components of net periodic postretirement benefit cost in the
following table:
Year Ended December 31, 1998 1997 1996
- -----------------------------------------------------------------
(In millions)
Components of net periodic
postretirement benefit cost
Service cost $ 6.6 $ 5.4 $ 5.5
Interest cost 23.4 21.8 21.9
Amortization of transition
obligation 11.4 11.4 11.4
Recognized net actuarial loss 0.2 0.1 0.2
Amount capitalized as
construction cost (8.1) (7.6) (6.2)
Amount deferred -- (7.2) (7.4)
- -----------------------------------------------------------------
Net periodic postretirement
benefit cost $33.5 $23.9 $25.4
=================================================================
Assumptions
We made the assumptions below to calculate our pension and postretirement
benefit cost and obligations.
Postretirement
Pension Benefits Benefits
At December 31, 1998 1997 1998 1997
- --------------------------------------------------------------
Discount rate 6.50% 7.25% 6.50% 7.25%
Expected return on
plan assets 9.00 9.00 N/A N/A
Rate of compensation
increase 4.00 4.00 4.00 4.00
We assumed the health care inflation rates to be:
o in 1998, 6.0% for both Medicare-eligible retirees and retirees not covered
by Medicare, and
o in 1999, 7.5% for Medicare-eligible retirees and 9.0% for retirees not
covered by Medicare.
After 1999, we assumed both inflation rates will decrease by 0.5% annually to a
rate of 5.5% in the years 2003 and 2006.
A 1% increase in the health care inflation rate from the assumed rates would
increase the accumulated postretirement benefit obligation by approximately
$52.8 million as of December 31, 1998 and would increase the combined service
and interest costs of the postretirement benefit cost by approximately $4.5
million annually.
A 1% decrease in the health care inflation rate from the assumed rates would
decrease the accumulated postretirement benefit obligation by approximately
$41.7 million as of December 31, 1998 and would decrease the combined service
and interest costs of the postretirement benefit cost by approximately $3.5
million annually.
Other Postemployment Benefits
We provide the following postemployment benefits:
o health and life insurance benefits to our employees and certain employees of
our subsidiaries who are found to be disabled under our Disability Insurance
Plan, and
o income replacement payments for employees found to be disabled before
November 1995. (Payments for employees found to be disabled after that date
are paid by an insurance company, and the cost is paid by employees.)
The liability for these benefits totaled $52.9 million as of December 31, 1998
and $45.4 million as of December 31, 1997.
Effective December 31, 1993, we adopted SFAS No. 112, Employers' Accounting for
Postemployment Benefits. We deferred, as a regulatory asset (see Note 4), the
postemployment benefit liability attributable to our utility business as of
December 31, 1993, consistent with the Maryland
59
PSC's orders for postretirement benefits (described earlier in this note). We
began to amortize the regulatory asset over 15 years beginning in 1998. The
Maryland PSC authorized us to reflect this change in our current electric and
gas base rates to recover the higher costs in 1998.
We assumed the discount rate for other postemployment benefits to be 4.5% in
1998 and 6.0% in 1997.
Employee Savings Plan Benefits
We also sponsor a defined contribution savings plan that is offered to all
eligible BGE employees and certain employees of our subsidiaries. In a defined
contribution plan, the benefits a participant is to receive result from regular
contributions to a participant account. Under this plan, we make matching
contributions to participant accounts. We made matching contributions to this
plan of:
o $10.1 million in 1998,
o $8.5 million in 1997, and
o $9.4 million in 1996.
- --------------------------------------------------------------------------------
Note 6
Short-Term Borrowings
Summary of Short-Term Borrowings
Our short-term borrowings may include bank loans, commercial paper notes, and
bank lines of credit. Short-term borrowings mature within one year from the date
of the financial statements. We pay commitment fees to banks for providing us
lines of credit. When we borrow under the lines of credit, we pay market
interest rates.
As of December 31, 1998, we had no short-term borrowings outstanding. As of
December 31, 1997, we had $316.1 million outstanding consisting entirely of BGE
commercial paper notes.
We had unused bank lines of credit supporting our commercial paper notes of $113
million at December 31, 1998 and $231 million at December 31, 1997. These
amounts do not include unused revolving credit agreements of $100 million at
December 31, 1998 and 1997 that are discussed in Note 7.
Constellation Enterprises, Inc. has a $135 million unsecured revolving credit
agreement that matures December 20, 1999, to provide liquidity for general
corporate purposes including financing requirements of subsidiaries and to
provide for the issuance of letters of credit to meet subsidiary business
requirements. At December 31, 1998, letters of credit totaling $2.3 million were
issued under this credit facility.
Weighted-Average Interest Rates
Our weighted-average effective interest rate for BGE's commercial paper notes
was 5.65% for the year ended December 31, 1998 and 5.66% for 1997.
- --------------------------------------------------------------------------------
Note 7
Long-Term Debt
Long-term debt matures more than one year from the date of the financial
statements. We summarize our long-term debt in the Consolidated Statements of
Capitalization. As you read this section, it may be helpful to refer to those
statements. We discuss BGE's and our diversified businesses' long-term debt
separately below.
BGE's Long-Term Debt
BGE's First Refunding Mortgage Bonds
BGE's first refunding mortgage bonds are secured by a mortgage lien on nearly
all of its assets, including all utility properties and franchises and its
subsidiary capital stock. BGE's subsidiary capital stock pledged under the
mortgage is that of Safe Harbor Water Power Corporation and Constellation
Enterprises, Inc.
BGE is required to make an annual sinking fund payment each August 1 to the
mortgage trustee. The amount of the payment is equal to 1% of the highest
principal amount of bonds outstanding during the preceding 12 months. The
trustee uses these funds to retire bonds from any series through repurchases or
calls for early redemption. However, the trustee cannot call the following bonds
for early redemption:
o 5 1/2% Installment Series, o 6 1/2% Series, due 2003
due 2002 o 6 1/8% Series, due 2003
o 8.40% Series, due 1999 o 5 1/2% Series, due 2004
o 5 1/2% Series, due 2000 o 7 1/2% Series, due 2007
o 8 3/8% Series, due 2001 o 6 5/8% Series, due 2008
o 7 1/4% Series, due 2002
60
Holders of the Remarketed Floating Rate Series Due September 1, 2006 have the
option to require BGE to repurchase their bonds at face value on September 1 of
each year. BGE is required to repurchase and retire at par any bonds that are
not remarketed or purchased by the remarketing agent. BGE also has the option to
redeem all or some of these bonds at face value each September 1.
BGE's Other Long-Term Debt
We show the weighted-average interest rates and maturity dates for BGE's
fixed-rate medium-term notes outstanding at December 31, 1998 in the following
table:
Weighted-Average
Series Interest Rate Maturity Dates
- ------------------------------------------------
B 8.10% 2000-2006
C 7.34 1999-2003
D 6.66 2001-2006
E 6.66 2006-2012
G 6.08 2008
Some of the medium-term notes include a "put option." These put options allow
the holders to sell their notes back to BGE on the put option dates at a price
equal to 100% of the principal amount. The following is a summary of medium-term
notes with put options:
Series E Notes Principal Put Option Dates
- ------------------------------------------------------
(In millions)
6.75%, due 2012 $60.0 June 2002 and 2007
6.75%, due 2012 25.0 June 2004 and 2007
6.73%, due 2012 25.0 June 2004 and 2007
BGE has $100 million of revolving credit agreements with several banks that are
available through 2000 to 2001. At December 31, 1998, BGE had no outstanding
borrowings under these agreements. These banks charge us commitment fees based
on the daily average of the unborrowed amount, and we pay market interest rates
on any borrowings. These agreements also support BGE's commercial paper notes,
as described in Note 6.
Company Obligated Mandatorily Redeemable Trust Preferred Securities
On June 15, 1998, BGE Capital Trust I (Trust), a Delaware business trust
established by BGE, issued 10,000,000 Trust Originated Preferred Securities
(TOPrS) for $250 million ($25 liquidation amount per preferred security) with a
distribution rate of 7.16%.
The Trust used the net proceeds from the issuance of common securities and the
preferred securities to purchase a series of 7.16% Deferrable Interest
Subordinated Debentures due June 30, 2038 (Debentures) from BGE in the aggregate
principal amount of $257.7 million with the same terms as the TOPrS. The Trust
must redeem the TOPrS at $25 per preferred security plus accrued but unpaid
distributions when the Debentures are paid at maturity or upon any earlier
redemption. BGE has the option to redeem the Debentures at any time on or after
June 15, 2003 or at any time when certain tax or other events occur.
The interest paid on the Debentures, which the Trust will use to make
distributions on the TOPrS, is included in "Interest Expense" in the
Consolidated Statements of Income and is deductible for income tax purposes.
BGE fully and unconditionally guarantees the TOPrS based on its various
obligations relating to the trust agreement, indentures, Debentures, and the
preferred security guarantee agreement.
The Debentures are the only assets of the Trust. The Trust is wholly owned by
BGE because we own all the common securities of the Trust that have general
voting power.
For the payment of dividends and in the event of liquidation of BGE, the
Debentures are ranked prior to preference stock and common stock.
Diversified Businesses' Long-Term Debt
Revolving Credit Agreements
A subsidiary of Constellation Enterprises, Inc. has a $75 million unsecured
revolving credit agreement that matures December 9, 1999, to provide liquidity
for general corporate purposes. Our diversified businesses pay a commitment fee
based on the daily average of the unborrowed portion of the commitment. At
December 31, 1998, our diversified businesses had $45.0 million outstanding
under this agreement.
Constellation Energy Source has a $10 million revolving credit agreement that
matures February 1, 2000. At December 31, 1998, Constellation Energy Source had
no outstanding borrowings under this agreement. Constellation Energy Source pays
a facility fee based on the total amount of the commitment.
ComfortLink has a $50 million unsecured revolving credit agreement that matures
September 26, 2001. Under the terms of the agreement, ComfortLink has the option
to obtain loans at various rates for terms up to nine months. ComfortLink pays a
facility fee on the total amount of the commitment. At December 31, 1998,
ComfortLink had $29 million outstanding under this agreement.
Mortgage and Construction Loans
Our diversified businesses' mortgage and construction loans have varying terms.
The following mortgage notes require monthly principal and interest payments:
o 7.90%, due in 2000 o 7.357%, due in 2009
o 8.00%, due in 2001 o 9.65%, due in 2028
The 8.00% mortgage note due in 2003 requires interest payments until maturity.
The variable rate mortgage notes and construction loans require periodic payment
of principal and interest. The 8.00% mortgage note due in 2033, requires
interest payments initially then monthly principal and interest payments.
61
Unsecured Notes
The unsecured notes mature on the following schedule:
Amount
- ------------------------------------------------------
(In millions)
7.30%, due April 22, 1999 $ 90.0
8.73%, due October 15, 1999 15.0
7.125%, due March 13, 2000 15.0
7.55%, due April 22, 2000 35.0
7.50%, due May 5, 2000 139.0
7.43%, due September 9, 2000 30.0
5.43%, due October 15, 2000 5.0
7.66%, due May 5, 2001 135.0
5.67%, due May 5, 2001 152.0
- ------------------------------------------------------
Total unsecured notes at December 31, 1998 $616.0
======================================================
Maturities of Long-Term Debt
All of our long-term borrowings mature on the following schedule (includes
sinking fund requirements):
Diversified
Year BGE Businesses
- ------------------------------------------------------
(In millions)
1999 $ 334.5 $200.2
2000 252.6 273.4
2001 195.2 362.6
2002 154.0 1.5
2003 284.3 8.9
Thereafter 1,584.4 23.6
- ------------------------------------------------------
Total long-term debt at
December 31, 1998 $2,805.0 $870.2
======================================================
At December 31, 1998, BGE had long-term loans totaling $255.0 million that
mature after 2002 (including $110 million of medium-term notes discussed in this
note under "BGE's Other Long-Term Debt") that lenders could potentially require
us to repay early. Of this amount, $145.0 million could potentially be repaid in
1999, $60.0 million in 2002, and $50.0 million thereafter. We have the ability
and intent to refinance such debt by issuing medium-term notes or by borrowing
under our revolving credit agreements, if necessary.
Weighted-Average Interest Rates for Variable Rate Debt
Our weighted-average interest rates for variable rate debt were:
Year Ended December 31, 1998 1997
- --------------------------------------------------------------------------------
BGE
Floating rate series mortgage bonds 5.90% 6.11%
Remarketed floating rate
series mortgage bonds 5.70 5.75
Medium-term notes, Series D 5.74 5.78
Pollution control loan 3.48 3.63
Port facilities loan 3.61 3.71
Adjustable rate pollution control loan 3.75 3.90
Economic development loan 3.59 3.69
Variable rate pollution control loan 3.45 3.73
Diversified Businesses
Loans under credit agreement 6.02 6.04
Mortgage and construction loans 8.17 8.10
- --------------------------------------------------------------------------------
Note 8
Redeemable Preference Stock
Priority
For the payment of dividends and in the event of liquidation of BGE, preference
stock is ranked prior to common stock. All preference stock are ranked equally.
Redemptions in 1998 and 1999
During 1998, BGE redeemed all remaining shares of the following:
o the 7.50%, 1986 series,
o the 6.75%, 1987 series, and
o the 8.625%, 1990 series.
The redemptions were a combination of mandatory and optional sinking fund
redemptions and early redemptions.
The remaining 70,000 shares of the 7.85%, 1991 series will be redeemed on July
1, 1999 under mandatory sinking fund provisions.
62
Note 9
Leases
There are two types of leases--operating and capital. Capital leases qualify as
sales or purchases of property and are reported in the Consolidated Balance
Sheets. All other leases are operating leases and are reported in the
Consolidated Statements of Income. We present information about our operating
leases below.
Incoming Lease Rentals
Some of our diversified businesses, as landlords, lease retail space to others.
These operating leases expire over periods ranging from one to 20 years, and
have options to renew. At December 31, 1998, our diversified businesses had
property under operating leases with a net book value of $32.4 million. At
December 31, 1998, tenants owed our diversified businesses future minimum
rentals under operating leases as follows:
Year
- --------------------------------------------------
(In millions)
1999 $ 3.4
2000 3.3
2001 3.1
2002 2.7
2003 2.7
Thereafter 24.3
- --------------------------------------------------
Total future minimum lease rentals $39.5
==================================================
Outgoing Lease Payments
We, as lessee, lease some facilities and equipment used in our businesses. The
lease agreements expire on various dates and have various renewal options. We
expense all lease payments associated with our regulated utility operations.
Lease expense was:
o $10.5 million in 1998,
o $9.5 million in 1997, and
o $11.6 million in 1996.
At December 31, 1998, we owed future minimum payments for long-term,
noncancelable, operating leases as follows:
Year
- -------------------------------------------------
(In millions)
1999 $ 6.7
2000 5.4
2001 4.1
2002 3.4
2003 2.2
Thereafter 5.5
- -------------------------------------------------
Total future minimum lease payments $27.3
=================================================
- --------------------------------------------------------------------------------
Note 10
Commitments, Guarantees, and Contingencies
Commitments
We have made substantial commitments in connection with our utility construction
program for future years. In addition, our electric business has entered into
two long-term contracts for the purchase of electric generating capacity and
energy. The contracts expire in 2001 and 2013. We made payments under these
contracts of:
o $70.7 million in 1998,
o $65.6 million in 1997, and
o $64.1 million in 1996.
At December 31, 1998, we estimate our future payments for capacity and energy
that we are obligated to buy under these contracts to be:
Year
- ------------------------------------------------------------
(In millions)
1999 $ 61.9
2000 63.1
2001 33.4
2002 12.3
2003 12.3
Thereafter 128.3
- ------------------------------------------------------------
Total estimated future payments for
capacity and energy under long-term contracts $311.3
============================================================
Some of our diversified businesses have committed to contribute additional
capital and to make additional loans to some affiliates, joint ventures, and
partnerships in which they have an interest. At December 31, 1998, the total
amount of investment requirements committed to by our diversified businesses was
$19.9 million.
63
In March 1998, our power marketing and trading business, Constellation Power
Source, Inc. 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 BGE has committed to contribute up
to $175 million in equity to Constellation Power Source to fund its investment
in Orion.
BGE and BGE Home Products & Services have agreements to sell on an ongoing basis
an undivided interest in a designated pool of customer receivables. Under the
agreements, BGE can sell up to a total of $40 million, and BGE Home Products &
Services can sell up to a total of $50 million. Under the terms of the
agreements, the buyer of the receivables has limited recourse against BGE and
has no recourse against BGE Home Products & Services. BGE and BGE Home Products
& Services have recorded a reserve for credit losses. At December 31, 1998, BGE
had sold $33.6 million and BGE Home Products & Services had sold $45.3 million
of receivables under these agreements.
Guarantees
BGE guarantees two-thirds of certain debt of Safe Harbor Water Power
Corporation. The maximum amount of our guarantee is $23 million. At December 31,
1998, Safe Harbor Water Power Corporation had outstanding debt of $23.6 million,
of which $15.7 million is guaranteed by BGE.
BGE has issued guarantees in an amount up to $162 million related to credit
facilities and contractual performance of certain of its diversified
subsidiaries. At December 31, 1998, letters of credit totaling $2.3 million were
issued under one of the credit facilities.
At December 31, 1998, our diversified businesses had guaranteed outstanding
loans and letters of credit of certain power projects and real estate projects
totaling $59.7 million. Our diversified businesses also guarantee certain other
borrowings of various power projects and real estate projects.
We assess the risk of material loss from these guarantees to be minimal.
Environmental Matters
Clean Air
The Clean Air Act of 1990 contains two titles designed to reduce emissions of
sulfur dioxides and nitrogen oxides (NOx) from electric generating
stations--Title IV and Title I.
Title IV addresses emissions of sulfur dioxides. Compliance is required in two
phases:
o Phase I became effective January 1, 1995. We met the requirements of this
phase by installing flue gas desulfurization system, 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 which took effect 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 Baltimore City Circuit Court ordered the 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 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 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.
Waste Disposal
The EPA and several state agencies have notified us that we are considered a
potentially responsible party with respect to the cleanup of certain
environmentally contaminated sites owned and operated by others. We cannot
estimate the cleanup costs for all of these sites. We can, however, estimate
that our current 15.42% share of the reasonably possible cleanup costs at one of
these sites, Metal Bank of America (a metal reclaimer in Philadelphia), could be
as much as $4.9 million higher than amounts we have recorded as a liability on
our Consolidated Balance Sheets. This estimate is based on a Record of Decision
issued by the EPA. The cleanup costs for some of the remaining sites could be
significant, but we do not expect them to have a material effect on our
financial position or results of operations.
64
Also, we are coordinating investigation of several sites where gas was
manufactured in the past. The investigation of these sites includes reviewing
possible actions to remove coal tar. In late December 1996, we signed a consent
order with the MDE that requires us to implement remedial action plans for
contamination at and around the Spring Gardens site, located in Baltimore,
Maryland. We submitted the required remedial action plans and they have been
approved by the MDE. Based on the remedial action plans, the costs we consider
to be probable to remedy the contamination are estimated to total $47 million in
nominal dollars (including inflation). We have recorded these costs as a
liability on our Consolidated Balance Sheets and have deferred these costs, net
of accumulated amortization and amounts we recovered from insurance companies,
as a regulatory asset. We discuss this further in Note 4. 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 costs, but still "reasonably possible"
of being incurred at these sites. Because of the results of studies at these
sites, it is reasonably possible that these additional costs could exceed the
amount we recognized by approximately $14 million in nominal dollars ($7 million
in current dollars, plus the impact of inflation at 3.1% over a period of up to
36 years).
Nuclear Insurance
If there were an accident or an extended outage at either unit of the Calvert
Cliffs Nuclear Power Plant (Calvert Cliffs), it could have a substantial adverse
financial effect on BGE. The primary contingencies that would result from an
incident at Calvert Cliffs could include:
o physical damage to the plant,
o recoverability of replacement power costs, and
o our liability to third parties for property damage and
bodily injury.
We have insurance policies that cover these contingencies, but the policies have
certain exclusions. Furthermore, the costs that could result from a covered
major accident or a covered extended outage at either of the Calvert Cliffs
units could exceed our insurance coverage limits.
Insurance for Calvert Cliffs and Third Party Claims
For physical damage to Calvert Cliffs, we have $2.75 billion of property
insurance from an industry mutual insurance company. If an outage at either of
the two units at Calvert Cliffs is caused by an insured physical damage loss and
lasts more than 17 weeks, we have insurance coverage for replacement power costs
up to $494.2 million per unit, provided by an industry mutual insurance company.
This amount can be reduced by up to $98.8 million per unit if an outage at both
units of the plant is caused by a single insured physical damage loss. If
accidents at any insured plants cause a shortfall of funds at the industry
mutual insurance company, all policyholders could be assessed, with our share
being up to $23.2 million.
In addition we, as well as others, could be charged for a portion of any third
party claims associated with a nuclear incident at any commercial nuclear power
plant in the country. At the date of this report, the limit for third party
claims from a nuclear incident is $9.71 billion under the provisions of the
Price Anderson Act. If third party claims exceed $200 million (the amount of
primary insurance), our share of the total liability for third party claims
could be up to $176.2 million per incident. That amount would be payable at a
rate of $20 million per year.
Insurance for Worker Radiation Claims
As an operator of a commercial nuclear power plant in the United States, we are
required to purchase insurance to cover radiation injury claims of certain
nuclear workers. On January 1, 1998, a new insurance policy became effective for
all operators requiring coverage for current operations. Waiving the right to
make additional claims under the old policy was a condition for acceptance under
the new policy. We describe both the old and new policies below.
o BGE nuclear worker claims reported on or after January 1, 1998 are covered by
a new insurance policy with an annual industry aggregate limit of $200
million for radiation injury claims against all those insured by this policy.
o All nuclear worker claims reported prior to January 1, 1998 are still
covered by the old insurance policies. Insureds under the old policies, with
no current operations, are not required to purchase the new policy described
above, and may still make claims against the old policies for the next nine
years. If radiation injury claims under these old policies exceed the policy
reserves, all policyholders could be assessed, with our share being up to
$6.3 million.
If claims under these polices exceed the coverage limits, the provisions of the
Price Anderson Act (discussed above) would apply.
Recoverability of Electric Fuel Costs
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 will 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.
65
The Maryland PSC, under the Generating Unit Performance Program, measures
annually whether we have maintained the productive capacity of our generating
plants at reasonable levels. To do this, the program uses a system-wide
generating performance target and an individual performance target for each base
load generating unit. In fuel rate hearings, actual generating performance
adjusted for planned outages will be compared first to the system-wide target.
If that target is met, it should mean that the requirements of Maryland law have
been met. If the system-wide target is not met, each unit's adjusted actual
generating performance will be compared to its individual performance target to
determine if the requirements of Maryland law have been met and, if not, to
determine the basis for possibly imposing a penalty on BGE. Even if we meet
these targets, parties to fuel rate hearings may still question whether we used
all reasonable and cost-effective procedures to try to prevent an outage. If the
Maryland PSC decides we were deficient in some way, the Maryland PSC may not
allow us to recover the cost of replacement energy.
The two units at Calvert Cliffs use the cheapest fuel. As a result, the costs of
replacement energy associated with outages at these units can be significant. We
cannot estimate the amount of replacement energy costs that could be challenged
or disallowed in future fuel rate proceedings, but such amounts could be
material.
During 1989 through 1991 we had extended outages at Calvert Cliffs. These
outages drove up fuel costs, and resulted in fuel rate proceedings before the
Maryland PSC for several years. 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. All costs associated with the outages in excess of $118 million
have already been collected from customers through the fuel rate. 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. The 1996 write-offs,
together, reduced after-tax earnings by $57.6 million.
Also in 1996, we wrote off $6.8 million of fuel costs related to earlier outages
that were disallowed by the Maryland PSC. This write-off reduced 1996 after-tax
earnings by $4.5 million.
We have reported all of the 1996 write-offs as "Disallowed replacement energy
costs" in our Consolidated Statements of Income.
California Power Purchase Agreements
Constellation Power, Inc. and subsidiaries and Constellation Investments, Inc.
(whose power projects are managed by Constellation Power) have $310.6 million
invested in 15 projects that sell electricity in California under power purchase
agreements called "Interim Standard Offer No. 4" agreements. In 1998, earnings
from these projects were $41.3 million, or $.28 per share.
Under these agreements, the projects supply electricity to utility companies at:
o a fixed rate for capacity and energy for the first 10 years of the
agreements, and
o a fixed rate for capacity plus a variable rate for energy based on the
utilities' avoided cost for the remaining term of the agreements.
Generally, a "capacity rate" is paid to a power plant for its availability to
supply electricity, and an "energy rate" is paid for the electricity actually
generated. "Avoided cost" generally is the cost of a utility's cheapest
next-available source of generation to service the demands on its system.
We use the term transition period to describe the time frame when the 10-year
periods for fixed energy rates expire for these 15 power generation projects and
they begin supplying electricity at variable rates. The transition period for
some of the projects began in 1996 and will continue for the remaining projects
through 2000. At the date of this report, eight projects had already
transitioned to variable rates and seven other projects will transition in 1999
and 2000.
The projects that have already transitioned to variable rates have had lower
revenues under variable rates than they did under fixed rates. However, we have
not yet experienced total lower earnings from the California projects because
the combined revenues from the remaining projects, which continue to supply
electricity at fixed rates, are high enough to offset the lower revenues from
the variable-rate projects. When the remaining projects transition to variable
rates, we expect the revenues from those projects also to be lower than they are
under fixed rates.
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 financings to improve the financing terms, and
o selling its ownership interests in the projects.
The California projects that make the highest revenues will transition to
variable rates in 1999 and 2000. The projects which transition in 1999
contributed $10.7 million, or $.07 per share to 1998 earnings, while those
changing over in 2000 contributed $24.0 million, or $.16 per share to 1998
earnings. We expect earnings to ultimately decrease by similar amounts beginning
in 1999 as these projects transition.
66
Constellation Real Estate
Most of Constellation Real Estate Group's (CREG) real estate projects are in the
Baltimore-Washington corridor. The area has had a surplus of available land in
recent years and as a result these projects have been economically hurt.
CREG's real estate projects have continued to incur carrying costs and
depreciation over the years. Additionally, CREG has been charging interest
payments to expense rather than capitalizing them for some undeveloped land
where development activities have stopped. These carrying costs, depreciation,
and interest expenses have decreased earnings and are expected to continue to do
so.
Cash flow from real estate operations has not been enough to make the monthly
loan payments on some of these projects. Cash shortfalls have been covered by
cash obtained from the cash flows of, or additional borrowings by, other
diversified subsidiaries.
We consider market demand, interest rates, the availability of financing, and
the strength of the economy in general when making decisions about our real
estate projects. If we were to decide to sell our real estate projects, we could
have write-downs. In addition, if we were to sell our remaining 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.
Management's current real estate strategy is to hold each real estate project
until we can realize a reasonable value for it, except for Church Street Station
which we intend to sell as discussed in Note 3. Management evaluates strategies
for all its businesses, including real estate, on an ongoing basis. We
anticipate that competing demands for our financial resources and changes in the
utility industry will cause us to evaluate thoroughly all diversified business
strategies on a regular basis so we use capital and other resources in a manner
that is most beneficial.
It may be helpful for you to understand when we are required, by accounting
rules, to write down the value of a real estate project to market value. A
write-down is required in either of two cases. The first is if we change our
intent about a project from an intent to hold to an intent to sell and the
market value of that project is below book value. The second is if the expected
future cash flow from the project is less than the investment in the project. We
discuss our real estate projects and investments further in Note 3.
Year 2000 Project
We have not experienced any significant year 2000 problems to date and we do not
expect any significant problems to impair our operations as we transition to the
new century. However, due to the magnitude and complexity of the year 2000
issue, even the most conscientious efforts cannot guarantee that every problem
will be found and corrected prior to January 1, 2000. We discuss our year 2000
project further in the "Year 2000 Readiness Disclosure" section of Management's
Discussion and Analysis.
- --------------------------------------------------------------------------------
Note 11
Fair Value of Financial Instruments
The fair value of a financial instrument represents the amount at which the
instrument could be exchanged in a current transaction between willing parties,
other than in a forced sale or liquidation. Significant differences can occur
between the fair value and carrying amount of financial instruments that are
recorded at historical amounts. We used the following methods and assumptions in
estimating fair value disclosures for financial instruments.
o Cash and cash equivalents, net accounts receivable, other current assets,
certain current liabilities, short-term borrowings, current portions of
long-term debt and preference stock and certain deferred credits and other
liabilities: The amounts reported in the Consolidated Balance Sheets
approximate fair value.
o Investments and other assets where it was practicable to estimate fair value:
The fair value is based on quoted market prices where available.
o Fixed-rate long-term debt, and redeemable preference stock: The fair value is
based on quoted market prices where available or by discounting remaining cash
flows at current market rates. The carrying amount of variable-rate long-term
debt approximates fair value.
We show the carrying amounts and fair values of financial instruments included
in our Consolidated Balance Sheets in the following table.
At December 31, 1998 1997
- --------------------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- --------------------------------------------------------------------------
(In millions)
Investments and other
assets for which it is:
Practicable to
estimate fair value $ 213.0 $ 213.0 $ 197.4 $ 198.8
Not practicable to
estimate fair value 56.5 N/A 57.5 N/A
Fixed-rate long-term
debt 2,954.7 3,076.6 2,637.5 2,718.4
Redeemable preference
stock 7.0 7.2 113.0 116.5
67
It was not practicable to estimate the fair value of investments held by our
diversified businesses in:
o several financial partnerships that invest in nonpublic debt and equity
securities,
o several partnerships that own solar powered energy production
facilities, and
o a company involved in developing international power projects with a carrying
amount of $3.7 million at December 31, 1998 and $3.0 million at December 31,
1997.
This is because the timing and amount of cash flows from these investments are
difficult to predict. We report these investments at their original cost in our
Consolidated Balance Sheets.
The investments in financial partnerships totaled $41.9 million at December 31,
1998 and $43.6 million at December 31, 1997, representing ownership interests up
to 10%. The total assets of all of these partnerships totaled $5.8 billion at
December 31, 1997 (which is the latest information available).
The investments in solar powered energy production facility partnerships totaled
$10.9 million at December 31, 1998 and 1997, representing ownership interests up
to 13%. The total assets of all of these partnerships totaled $41.5 million at
December 31, 1997 (which is the latest information available).
Guarantees
It was not practicable to determine the fair value of certain loan guarantees of
BGE and its diversified businesses. BGE guaranteed outstanding debt and other
obligations totaling $18.0 million at December 31, 1998 and $20 million at
December 31, 1997. Our diversified businesses guaranteed outstanding debt
totaling $59.7 million at December 31, 1998 and $43 million at December 31,
1997. We do not anticipate that we will need to fund these guarantees.
- --------------------------------------------------------------------------------
Note 12
Quarterly Financial Data (Unaudited)
Our quarterly financial information has not been audited but, in management's
opinion, includes all adjustments necessary for a fair presentation. Our utility
business is seasonal in nature with the peak sales periods generally occurring
during the summer and winter months. Accordingly, comparisons among quarters of
a year may not represent overall trends and changes in operations.
1998 QUARTERLY DATA
Earnings Earnings
Income Applicable Per Share
From Net to Common of Common
Revenues Operations Income Stock Stock
- ----------------------------------------------------------------------------------------
(In millions, except per share amounts)
Quarter Ended:
March 31 $ 866.1 $183.4 $ 80.2 $ 74.4 $0.50
June 30 767.6 156.2 63.2 57.4 0.39
September 30 934.0 320.4 167.7 160.9 1.08
December 31 790.4 81.1 16.6 13.2 0.09
- ----------------------------------------------------------------------------------------
Year Ended:
December 31 $3,358.1 $741.1 $327.7 $305.9 $2.06
========================================================================================
Our third quarter results include a $10.4 million after-tax gain for earnings in
a partnership (see Note 3).
Our fourth quarter results include:
o a $15.4 million after-tax write-off of a real estate investment (see Note 3),
and
o a $5.5 million after-tax write-off of an energy services investment. (See
the "Other Energy Services" section of Management's Discussion and Analysis.)
1997 Quarterly Data
Earnings Earnings
Income Applicable Per Share
From Net to Common of Common
Revenues Operations Income Stock Stock
- ----------------------------------------------------------------------------------------
(In millions, except per share amounts)
Quarter Ended:
March 31 $ 887.7 $163.9 $ 72.1 $ 64.2 $0.43
June 30 746.4 78.8 15.0 7.1 0.05
September 30 860.8 321.0 171.4 164.4 1.11
December 31 812.7 159.9 24.3 18.4 0.12
- ----------------------------------------------------------------------------------------
Year Ended:
December 31 $3,307.6 $723.6 $282.8 $254.1 $1.72
========================================================================================
Our first quarter results include a $12.0 million after-tax write-down of a real
estate project (see Note 3).
Our second quarter results include a $31.9 million after-tax write-down of a
real estate project (see Note 3).
Our fourth quarter results include:
o a $37.5 million after-tax write-off of merger costs (see Note 2), and
o a $2.1 million after-tax write-down of a real estate project (see Note 3).
THE SUM OF THE QUARTERLY EARNINGS PER SHARE AMOUNTS MAY NOT EQUAL THE TOTAL FOR
THE YEAR DUE TO THE EFFECTS OF ROUNDING.
68
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item with respect to directors is set
forth on pages 19 through 22 under "Election of BGE Directors" in the Proxy
Statement and is incorporated herein by reference.
The information required by this item with respect to executive officers
is, pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K,
set forth in Item 4 of Part I of this Form 10-K under "Executive Officers of
the Registrant," except that information with regard to a late filing of a
Section 16(a) report by an executive officer is set forth on page 22 under
"Section 16(a) Beneficial Ownership Reporting Compliance" in the Proxy
Statement and is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is set forth on pages 21 and 22
under "Directors' Compensation" on pages 24 through 28 under "Executive
Compensation," and "Common Stock Performance Graph" and on pages 29 through 31
under "Report of Committee on Management on Executive Compensation" in the
Proxy Statement and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item regarding security ownership of
management is set forth on page 23 under "Security Ownership" in the Proxy
Statement and is incorporated herein by reference.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
NAME OF TITLE AMOUNT OF PERCENT
BENEFICIAL OF BENEFICIAL OF
OWNER CLASS OWNERSHIP CLASS
- ------------------------ -------- ------------------- --------
Capital Research and Common 10,225,000 shares 6.9%
Management Company Stock
333 South Hope Street
Los Angeles,
CA 90071 ............
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is set forth on page 22 under
"Certain Relationships and Transactions" in the Proxy Statement and is
incorporated herein by reference.
69
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as a part of this Report:
1. Financial Statements:
Report of Independent Accountants dated January 15, 1999 of
PricewaterhouseCoopers LLP
Consolidated Statements of Income for three years ended December 31, 1998
Consolidated Statements of Comprehensive Income for three years ended
December 31, 1998
Consolidated Balance Sheets at December 31, 1998 and December 31, 1997
Consolidated Statements of Cash Flows for three years ended December 31,
1998
Consolidated Statements of Common Shareholders' Equity for three years
ended December 31, 1998
Consolidated Statements of Capitalization at December 31, 1998 and
December 31, 1997
Consolidated Statements of Income Taxes for three years ended December 31,
1998
Notes to Consolidated Financial Statements
2. Financial Statement Schedules:
Schedule II -- Valuation and Qualifying Accounts
Schedules other than Schedule II are omitted as not applicable or not
required.
3. Exhibits Required by Item 601 of Regulation S-K.
70
EXHIBIT
NUMBER
- --------------------------------------------------------------------------------
*2 -- Agreement and Plan of Share Exchange between Baltimore Gas and
Electric Company and Constellation Energy Group, Inc. dated as of
February 19, 1999. (Designated as Exhibit No. 2 in Form S-4 dated
March 3, 1999, File No. 33-64799.)
*3(a) -- Charter of BGE, restated as of August 16, 1996. (Designated as
Exhibit No. 3 in Form 10-Q dated November 14, 1996, File No. 1-1910.)
*3(b) -- By-Laws of BGE, as amended to October 16, 1998. (Designated as
Exhibit No. 3 in Form 10-Q dated November 13, 1998, File No. 1-1910.)
*4(a) -- Supplemental Indenture between BGE and Bankers Trust Company, as
Trustee, dated as of June 20, 1995, supplementing, amending and
restating Deed of Trust dated February 1, 1919. (Designated as
Exhibit No. 4 in Form 10-Q dated August 11, 1995, File No. 1-1910.);
and the following Supplemental Indentures between BGE and Bankers
Trust Company, Trustee:
DESIGNATED IN
----------------------------------------------------------------------------
EXHIBIT
DATED FILE NO. NUMBER
- ---------------------- ---------- --------------------
*July 15, 1977 2-59772 2-3
(3 Indentures)
*October 15, 1989 1-1910 (Form 10-Q dated November 14, 1989) 4(a)
*August 15, 1991 33-45259 (Form S-3 Registration) 4(a)(i)
*January 15, 1992 33-45259 (Form S-3 Registration) 4(a)(ii)
*July 1, 1992 1-1910 (Form 8-K Report for January 29, 1993) 4(a)
*February 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(i)
*March 1, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(ii)
*March 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(iii)
*April 15, 1993 1-1910 (Form 10-Q dated May 13, 1993) 4
*July 1, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(a)
*July 15, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(b)
*October 15, 1993 1-1910 (Form 10-Q dated November 12, 1993) 4
*March 15, 1994 1-1910 (Form 10-K Annual Report for 1993) 4(a)
*June 15, 1996 1-1910 (Form 10-Q dated August 13, 1996) 4
*4(b) -- Indenture dated July 1, 1985, between BGE and The Bank of New York
(Successor to Mercantile-Safe Deposit and Trust Company), Trustee.
(Designated in Registration File No. 2-98443 as Exhibit 4(a)); as
supplemented by Supplemental Indentures dated as of October 1, 1987
(Designated in Form 8-K, dated November 13, 1987, File No. 1-1910
as Exhibit 4(a)) and as of January 26, 1993 (Designated in Form
8-K, dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).)
*4(c) -- Form of Subordinated Indenture between the Company and The Bank of
New York, as Trustee in connection with the issuance of the Junior
Subordinated Debentures (Designated as Exhibit 4(d) in Form S-3
dated May 28, 1998, File No. 333-53767).
*4(d) -- Form of Supplemental Indenture between the Company and The Bank of
New York, as Trustee in connection with the issuances of the Junior
Subordinated Debentures (Designated as Exhibit 4(e) in Form S-3
dated May 28, 1998, File No. 333-53767).
*4(e) -- Form of Preferred Securities Guarantee (Designated as Exhibit 4(f)
in Form S-3 dated May 28, 1998, File No. 333-53767).
*4(f) -- Form of Junior Subordinated Debenture (Designated as Exhibit 4(h)
in Form S-3 dated May 28, 1998, File No. 333-53767).
*4(g) -- Form of Amended and Restated Declaration of Trust (including Form
of Preferred Security) (Designated as Exhibit 4(c) in Form S-3
dated May 28, 1998, File No. 333-53767).
*10(a) -- Baltimore Gas and Electric Company Executive Benefits Plan, as
amended and restated. (Designated as Exhibit No. 10(a) in Form 10-Q
dated November 14, 1996, File No. 1-1910.)
*10(b) -- Executive Incentive Plan of the Baltimore Gas and Electric Company.
(Designated as Exhibit No. 10(b) to the Annual Report on Form 10-K
for the year ended December 31, 1992, File No. 1-1910.)
*10(c) -- Baltimore Gas and Electric Company 1995 Long-Term Incentive Plan.
(Designated as Exhibit No. 10(c) to the Annual Report on Form 10-K
for the year ended December 31, 1994, File No. 1-1910.)
*10(d) -- Baltimore Gas and Electric Company Nonqualified Deferred
Compensation Plan, as amended and restated. (Designated as Exhibit
No. 10(d) to the Annual Report on Form 10-K for the year ended
December 31, 1996, File No. 1-1910.)
71
*10(e) -- Amended and Restated Baltimore and Gas and Electric Company
Deferred Compensation Plan for Non-Employee Directors. (Designated
as Exhibit No. 10 in Form 10-Q dated November 13, 1997, File No.
1-1910.)
*10(f) -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee
Directors, as amended and restated. (Designated as Exhibit No.
10(f) to the Annual Report on Form 10-K for the year ended December
31, 1994, File No. 1-1910.) (Terminated effective August 1, 1997.)
10(g) -- Summary of severance arrangement for a named executive officer.
*10(h) -- Grantor Trust Agreement Dated as of July 31, 1994 between Baltimore
Gas and Electric Company and Citibank, N.A. (Designated as Exhibit
No. 10(h) to the Annual Report on Form 10-K for the year ended
December 31, 1994, File No. 1-1910.)
*10(i) -- Summary of Constellation Holdings, Inc. Annual Incentive Plan.
(Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K
for the year ended December 31, 1992, File No. 1-1910.)
*10(j) -- Severance Agreements between Baltimore Gas and Electric Company and
eight key employees. (Designated as Exhibit No. 10(k) to the Annual
Report on Form 10-K for the year ended December 31, 1997, File No.
1-1910.)
10(k) -- Form of amendment to Severance Agreements between Baltimore Gas and
Electric Company and eight key employees.
10(l) -- Constellation Enterprises, Inc. Deferred Compensation Plan for
Non-Employee Directors.
10(m) -- Summary of enhanced retirement benefits for a named executive
officer.
*10(n) -- Grantor Trust Agreement dated as of June 1, 1996 between Baltimore
Gas and Electric Company and T. Rowe Price Trust Company.
(Designated as Exhibit No. 10(b) in Form 10-Q dated August 13,
1996, File No. 1-1910.)
12 -- Computation of Ratio of Earnings to Fixed Charges and Computation
of Ratio of Earnings to Combined Fixed Charges and Preferred and
Preference Dividend Requirements.
21 -- Subsidiaries of the Registrant.
23 -- Consent of PricewaterhouseCoopers LLP, Independent Accountants.
27 -- Financial Data Schedule.
*99(a) -- Indemnification of Directors and Officers of the Company.
(Designated as Exhibit No. 28(a) to the Annual Report on Form 10-K
for the year ended December 31, 1988, File No. 1-1910.)
- ----------
* Incorporated by Reference.
(b) Reports on Form 8-K:
None.
72
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- -------------------------------------------- ----------- ------------------------------- ------------------ ----------
ADDITIONS
-------------------------------
BALANCE CHARGED
AT TO COSTS CHARGED TO OTHER BALANCE
BEGINNING AND ACCOUNTS -- (DEDUCTIONS) -- AT END OF
DESCRIPTION OF PERIOD EXPENSES DESCRIBE DESCRIBE PERIOD
- -------------------------------------------- ----------- ---------- ------------------ ------------------ ----------
(IN MILLIONS)
Reserves deducted in the Balance Sheet from
the assets to which they apply:
Accumulated Provision for Uncollectibles
1998 ................................... $ 24.1 $ 28.0 $ -- $( 31.8)(A) $ 20.3
1997 ................................... 18.0 34.4 -- ( 28.3)(A) 24.1
1996 ................................... 16.4 24.9 -- ( 23.3)(A) 18.0
Valuation Allowance --
Net unrealized (gain) loss on available
for sale securities
1998 ................................... ( 7.6) -- ( 1.8)(B) -- ( 9.4)
1997 ................................... ( 8.8) -- 1.2(B) -- ( 7.6)
1996 ................................... ( 6.2) -- ( 2.6)(B) -- ( 8.8)
Valuation Allowance --
Net unrealized (gain) loss on nuclear
decommissioning trust fund
1998 ................................... (10.0) -- (13.9)(C) -- (23.9)
1997 ................................... ( 3.7) -- ( 6.3)(C) -- (10.0)
1996 ................................... ( 2.2) -- ( 1.5)(C) -- ( 3.7)
Provision for possible disallowance of
replacement energy costs
1998 ................................... -- -- -- -- --
1997 ................................... 118.0 -- -- (118.0)(D) --
1996 ................................... 35.0 83.0 -- -- 118.0
Energy projects under development
reserves
1998 ................................... -- -- -- -- --
1997 ................................... 5.2 0.3 -- ( 5.5)(E) --
1996 ................................... 0.3 5.2 -- ( 0.3)(E) 5.2
- ----------
(A) Represents principally net amounts charged off as uncollectible.
(B) Represents net unrealized (gains)/losses (credited)/charged to accumulated
other comprehensive income.
(C) Represents net unrealized gains credited to accumulated depreciation.
(D) Represents removal of a reserve based on actual disallowance of replacement
energy costs.
(E) Represents removal of a reserve associated with an energy project of a
subsidiary that was abandoned.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
73
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, Baltimore Gas and Electric Company, the Registrant, has
duly caused this Report to be signed on its behalf by the undersigned,
thereunto duly authorized.
BALTIMORE GAS AND ELECTRIC COMPANY
(REGISTRANT)
Date: March 18, 1999 By /s/ C. H. POINDEXTER
-------------------------------------
C. H. POINDEXTER
CHAIRMAN OF THE BOARD, PRESIDENT, AND
CHIEF EXECUTIVE OFFICER
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below by the following persons on behalf of Baltimore
Gas and Electric Company, the Registrant, and in the capacities and on the
dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
Principal executive officer and director:
By /s/ C. H. POINDEXTER Chairman of the Board, President, March 18, 1999
----------------------------------- Chief Executive Officer, and
C. H. POINDEXTER Director
Principal financial and accounting officer:
By /s/ D. A. BRUNE Vice President, Chief Financial March 18, 1999
----------------------------------- Officer and Secretary
D. A. BRUNE
Directors:
/s/ H. F. BALDWIN Director March 18, 1999
- -------------------------------------
H. F. BALDWIN
/s/ D. L. BECKER Director March 18, 1999
- -------------------------------------
D. L. BECKER
/s/ B. B. BYRON Director March 18, 1999
- -------------------------------------
B. B. BYRON
/s/ J. O. COLE Director March 18, 1999
- -------------------------------------
J. O. COLE
/s/ D. A. COLUSSY Director March 18, 1999
- -------------------------------------
D. A. COLUSSY
/s/ E. A. CROOKE Director March 18, 1999
- -------------------------------------
E. A. CROOKE
/s/ J. R. CURTISS Director March 18, 1999
- -------------------------------------
J. R. CURTISS
/s/ J. W. GECKLE Director March 18, 1999
- -------------------------------------
J. W. GECKLE
/s/ F. A. HRABOWSKI III Director March 18, 1999
- -------------------------------------
F. A. HRABOWSKI III
/s/ N. LAMPTON Director March 18, 1999
- -------------------------------------
N. LAMPTON
/s/ C. R. LARSON Director March 18, 1999
- -------------------------------------
C. R. LARSON
74
SIGNATURE TITLE DATE
--------- ----- ----
/s/ G. V. MCGOWAN Director March 18, 1999
- -------------------------------------
G. V. MCGOWAN
/s/ G. L. RUSSELL, JR. Director March 18, 1999
- -------------------------------------
G. L. RUSSELL, JR.
/s/ M. D. SULLIVAN Director March 18, 1999
- -------------------------------------
M. D. SULLIVAN
75
EXHIBIT INDEX
EXHIBIT
NUMBER
- ----------------------------------------------------------------------------------------------------------------
*2 -- Agreement and Plan of Share Exchange between Baltimore Gas and Electric Company and
Constellation Energy Group, Inc. dated as of February 19, 1999. (Designated as Exhibit No. 2 in
Form S-4 dated March 3, 1999, File No. 33-64799.)
*3(a) -- Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 in Form 10-Q dated
November 14, 1996, File No. 1-1910.)
*3(b) -- By-Laws of BGE, as amended to October 16, 1998. (Designated as Exhibit No. 3 in Form 10-Q dated
November 13, 1998, File No. 1-1910.)
*4(a) -- Supplemental Indenture between BGE and Bankers Trust Company, as Trustee, dated as of June 20,
1995, supplementing, amending and restating Deed of Trust dated February 1, 1919. (Designated as
Exhibit No. 4 in Form 10-Q dated August 11, 1995, File No. 1-1910.); and the following
Supplemental Indentures between BGE and Bankers Trust Company, Trustee:
DESIGNATED IN
----------------------------------------------------------------------------
EXHIBIT
DATED FILE NO. NUMBER
- ---------------------- ---------- --------------------
*July 15, 1977 2-59772 2-3
(3 Indentures)
*October 15, 1989 1-1910 (Form 10-Q dated November 14, 1989) 4(a)
*August 15, 1991 33-45259 (Form S-3 Registration) 4(a)(i)
*January 15, 1992 33-45259 (Form S-3 Registration) 4(a)(ii)
*July 1, 1992 1-1910 (Form 8-K Report for January 29, 1993) 4(a)
*February 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(i)
*March 1, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(ii)
*March 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(iii)
*April 15, 1993 1-1910 (Form 10-Q dated May 13, 1993) 4
*July 1, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(a)
*July 15, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(b)
*October 15, 1993 1-1910 (Form 10-Q dated November 12, 1993) 4
*March 15, 1994 1-1910 (Form 10-K Annual Report for 1993) 4(a)
*June 15, 1996 1-1910 (Form 10-Q dated August 13, 1996) 4
*4(b) -- Indenture dated July 1, 1985, between BGE and The Bank of New York
(Successor to Mercantile-Safe Deposit and Trust Company), Trustee.
(Designated in Registration File No. 2-98443 as Exhibit 4(a)); as
supplemented by Supplemental Indentures dated as of October 1, 1987
(Designated in Form 8-K, dated November 13, 1987, File No. 1-1910
as Exhibit 4(a)) and as of January 26, 1993 (Designated in Form
8-K, dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).)
*4(c) -- Form of Subordinated Indenture between the Company and The Bank of
New York, as Trustee in connection with the issuance of the Junior
Subordinated Debentures (Designated as Exhibit 4(d) in Form S-3
dated May 28, 1998, File No. 333-53767).
*4(d) -- Form of Supplemental Indenture between the Company and The Bank of
New York, as Trustee in connection with the issuances of the Junior
Subordinated Debentures (Designated as Exhibit 4(e) in Form S-3
dated May 28, 1998, File No. 333-53767).
*4(e) -- Form of Preferred Securities Guarantee (Designated as Exhibit 4(f)
in Form S-3 dated May 28, 1998, File No. 333-53767).
*4(f) -- Form of Junior Subordinated Debenture (Designated as Exhibit 4(h)
in Form S-3 dated May 28, 1998, File No. 333-53767).
*4(g) -- Form of Amended and Restated Declaration of Trust (including Form
of Preferred Security) (Designated as Exhibit 4(c) in Form S-3
dated May 28, 1998, File No. 333-53767).
*10(a) -- Baltimore Gas and Electric Company Executive Benefits Plan, as
amended and restated. (Designated as Exhibit No. 10(a) in Form 10-Q
dated November 14, 1996, File No. 1-1910.)
*10(b) -- Executive Incentive Plan of the Baltimore Gas and Electric Company.
(Designated as Exhibit No. 10(b) to the Annual Report on Form 10-K
for the year ended December 31, 1992, File No. 1-1910.)
*10(c) -- Baltimore Gas and Electric Company 1995 Long-Term Incentive Plan.
(Designated as Exhibit No. 10(c) to the Annual Report on Form 10-K
for the year ended December 31, 1994, File No. 1-1910.)
76
*10(d) -- Baltimore Gas and Electric Company Nonqualified Deferred
Compensation Plan, as amended and restated. (Designated as Exhibit
No. 10(d) to the Annual Report on Form 10-K for the year ended
December 31, 1996, File No. 1-1910.)
*10(e) -- Amended and Restated Baltimore and Gas and Electric Company
Deferred Compensation Plan for Non-Employee Directors. (Designated
as Exhibit No. 10 in Form 10-Q dated November 13, 1997, File No.
1-1910.)
*10(f) -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee
Directors, as amended and restated. (Designated as Exhibit No.
10(f) to the Annual Report on Form 10-K for the year ended December
31, 1994, File No. 1-1910.) (Terminated effective August 1, 1997.)
10(g) -- Summary of severance arrangement for a named executive officer.
*10(h) -- Grantor Trust Agreement Dated as of July 31, 1994 between Baltimore
Gas and Electric Company and Citibank, N.A. (Designated as Exhibit
No. 10(h) to the Annual Report on Form 10-K for the year ended
December 31, 1994, File No. 1-1910.)
*10(i) -- Summary of Constellation Holdings, Inc. Annual Incentive Plan.
(Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K
for the year ended December 31, 1992, File No. 1-1910.)
*10(j) -- Severance Agreements between Baltimore Gas and Electric Company and
eight key employees. (Designated as Exhibit No. 10(k) to the Annual
Report on Form 10-K for the year ended December 31, 1997, File No.
1-1910.)
10(k) -- Form of amendment to Severance Agreements between Baltimore Gas and
Electric Company and eight key employees.
10(l) -- Constellation Enterprises, Inc. Deferred Compensation Plan for
Non-Employee Directors.
10(m) -- Summary of enhanced retirement benefits for a named executive
officer.
*10(n) -- Grantor Trust Agreement dated as of June 1, 1996 between Baltimore
Gas and Electric Company and T. Rowe Price Trust Company.
(Designated as Exhibit No. 10(b) in Form 10-Q dated August 13,
1996, File No. 1-1910.)
12 -- Computation of Ratio of Earnings to Fixed Charges and Computation
of Ratio of Earnings to Combined Fixed Charges and Preferred and
Preference Dividend Requirements.
21 -- Subsidiaries of the Registrant.
23 -- Consent of PricewaterhouseCoopers LLP, Independent Accountants.
27 -- Financial Data Schedule.
*99(a) -- Indemnification of Directors and Officers of the Company.
(Designated as Exhibit No. 28(a) to the Annual Report on Form 10-K
for the year ended December 31, 1988, File No. 1-1910.)
- ----------
* Incorporated by Reference.
77