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 AND EXCHANGE ACT OF 1934
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For the fiscal year ended 1-1910
December 31, 1996 Commission file number
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BALTIMORE GAS AND ELECTRIC COMPANY
(Exact name of registrant as specified in its charter)
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MARYLAND 52-0280210
(State of incorporation) (I.R.S. Employer Identification No.)
39 W. LEXINGTON STREET,
BALTIMORE, MARYLAND 21201
(Address of principal executive offices) (Zip Code)
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410-783-5920
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
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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.
Preference Stock, Cumulative, $100 Par Value:
7.78%, 1973 Series
7.50%, 1986 Series Philadelphia Stock Exchange, Inc.
6.75%, 1987 Series
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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 .
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Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K (Section 229.405 of this chapter) 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. [X]
Aggregate market value of Common Stock, without par value, held by
non-affiliates as of February 28, 1997 was approximately $4,045,549,228 based
upon New York Stock Exchange composite transaction closing price.
COMMON STOCK, WITHOUT PAR VALUE -- 147,667,114 SHARES OUTSTANDING ON
FEBRUARY 28, 1997.
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TABLE OF CONTENTS
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PAGE
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PART I
Item 1 -- Business
Overview of Consolidated Business........................................................... 1
Consolidated Capital Requirements........................................................... 3
Electric Business
Electric Regulatory Matters and Competition............................................... 4
Electric Rate Matters..................................................................... 5
Nuclear Operations........................................................................ 6
Electric Load Management, Energy, and Capacity Purchases.................................. 7
Fuel for Electric Generation.............................................................. 8
Electric Operating Statistics............................................................. 10
Gas Business
Gas Operating Statistics.................................................................. 11
Gas Regulatory Matters and Competition.................................................... 12
Gas Operations............................................................................ 12
Gas Rate Matters.......................................................................... 13
Franchises.................................................................................. 13
Diversified Businesses...................................................................... 13
Environmental Matters....................................................................... 17
Employees................................................................................... 19
Item 2 -- Properties.................................................................................. 20
Item 3 -- Legal Proceedings........................................................................... 21
Item 4 -- Submission of Matters to a Vote of Security Holders......................................... 21
PART II
Item 5 -- Market for Registrant's Common Equity and Related Stockholder Matters....................... 22
Item 6 -- Selected Financial Data..................................................................... 23
Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of
Operations................................................................................. 24
Item 8 -- Financial Statements and Supplementary Data................................................. 34
Item 9 -- Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure................................................................................. 58
PART III
Item 10 -- Directors and Executive Officers of the Registrant.......................................... 58
Item 11 -- Executive Compensation...................................................................... 62
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
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PART I
ITEM 1. BUSINESS
OVERVIEW OF CONSOLIDATED BUSINESS
Baltimore Gas and Electric Company and Subsidiaries together are called the
Company in this Report. The Company conducts utility operations through
Baltimore Gas and Electric Company, called BGE in this Report. The Company is
engaged in a number of diversified businesses through subsidiaries.
BGE was incorporated under the laws of the State of Maryland on June 20,
1906. BGE is qualified to do business in the District of Columbia where its
federal affairs office is located. BGE is qualified to do business in the
Commonwealth of Pennsylvania where it is participating in the ownership and
operation of two electric generating plants as described under ITEM 2.
PROPERTIES. BGE also owns two-thirds of the outstanding capital stock, including
one-half of the voting securities, of Safe Harbor Water Power Corporation, a
hydroelectric producer on the Susquehanna River at Safe Harbor, Pennsylvania.
(SEE ITEM 2. PROPERTIES -- ELECTRIC.)
OVERVIEW OF UTILITY BUSINESS
Our utility business consists primarily of generating, purchasing, and
selling electricity and purchasing, transporting, and selling natural gas. The
focus of these activities is serving customers in BGE's service territory.
BGE furnishes electric and gas retail services in the City of Baltimore and
in all or part of ten counties in Central Maryland. The electric service
territory includes an area of approximately 2,300 square miles with an estimated
population of 2,650,000. The gas service territory includes an area of more than
600 square miles with an estimated population of 2,000,000. There are no
municipal or cooperative bulk power markets within BGE's service territory.
As discussed throughout this report, the two units at BGE's Calvert Cliffs
Nuclear Power Plant are its principal generating facilities and have the lowest
fuel cost in BGE's system. An extended shutdown of either of these Units could
have a substantial adverse effect on the Company's business and financial
condition. (See NUCLEAR OPERATIONS and NOTE 12 TO CONSOLIDATED FINANCIAL
STATEMENTS for information regarding prior outages at the Plant.) For further
information about utility operations see five other sections in this report --
ELECTRIC BUSINESS, ELECTRIC OPERATING STATISTICS, GAS OPERATING STATISTICS, GAS
BUSINESS, and FRANCHISES.
Competition and the Pending Merger
The utility industry is facing potentially substantial regulatory change
designed to foster competition in the provision of gas and electric services.
The restructuring of the industry was a key consideration for BGE and Potomac
Electric Power Company (PEPCO) agreeing to merge (the Merger). PEPCO is a
neighboring electric utility serving Washington, D.C. and major portions of
Montgomery and Prince George's Counties in Maryland. It is currently anticipated
that the Merger will be completed during the first six months of 1997. The
reasons for the Merger and other information about the Merger are discussed in
more detail under ELECTRIC REGULATORY MATTERS AND COMPETITION and in the
Registration Statement on Form S-4 (Registration No. 33-64799) which is included
as an exhibit to this report by incorporation by reference.
In response to the competitive forces and regulatory changes in the utility
industry, BGE (and after the Merger the new company to be named Constellation
EnergyTM Corporation) from time to time will consider various strategies
designed to enhance its competitive position and to increase its ability to
adapt to and anticipate regulatory changes in its utility business. These
strategies may include internal restructurings involving the complete or partial
separation of its generation, transmission and distribution businesses, other
internal restructurings, mergers or acquisitions of utility or non-utility
businesses, additions to or dispositions of portions of its franchised service
territories, and spin-off or distribution of one or more businesses. BGE and its
subsidiaries may from time to time be engaged in preliminary discussions, either
internally or with third parties, about one or more of these potential
strategies. It is not possible to predict the ultimate effect competition will
have on BGE's earnings in future years. These matters are discussed under
ELECTRIC REGULATORY MATTERS AND COMPETITION and GAS REGULATORY MATTERS AND
COMPETITION.
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OVERVIEW OF DIVERSIFIED BUSINESSES
The Company is engaged in diversified businesses through three groups of
subsidiaries:
BGE Corp. and its subsidiaries -- these businesses include energy marketing
activities, specifically power marketing, natural gas brokering, energy
services, and district heating and cooling projects;
Constellation(TM) Holdings and its subsidiaries (called the "Constellation
Companies" in this report) -- these businesses include power generation outside
BGE's service territory, investment activities, real estate, and senior-living
facilities; and
BGE Home Products & Services, Inc. and its subsidiary -- these businesses
include appliance sales and service, heating and air conditioning sales and
service, and home improvement.
Our diversified businesses are described in more detail under the heading
DIVERSIFIED BUSINESSES.
OPERATING REVENUES AND INCOME
The percentages of Operating Revenues and Operating Income attributable to
electric, gas, and diversified operations are set forth below:
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OPERATING REVENUES OPERATING INCOME*
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ELECTRIC GAS DIVERSIFIED ELECTRIC GAS DIVERSIFIED
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1996.......................................... 70% 16 % 14% 75% 10 % 15%
1995.......................................... 76 14 10 83 7 10
1994.......................................... 76 15 9 85 4 11
1993.......................................... 77 16 7 87 6 7
1992.......................................... 77 16 7 82 8 10
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*Net of income taxes.
BGE currently derives approximately 22% of electric revenues and 40% of gas
revenues from customers located in the City of Baltimore and 78% and 60%,
respectively, from outside the City of Baltimore. No single customer's electric
revenues exceed 4% of total electric revenues and no single customer's gas
revenues exceed 4% of total gas revenues. The disparity between the percentage
of gas operating revenues in relation to the percentage of gas operating income
as compared to the same percentages for electric operations is due to BGE's
level of investment and its fuel costs in each of these segments. BGE's
operating revenue amounts represent recovery of all fuel and operating expenses
plus a return on its investment in the business. BGE's net investment for
ratemaking purposes in the electric business is $4.8 billion while the
comparable investment in its gas business is approximately $605 million. Thus,
operating revenues include a much greater return component for electric
operations than gas operations. Also, as can be seen by referring to ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, CONSOLIDATED STATEMENTS OF INCOME,
gas purchased for resale as a percentage of gas revenues (55%) is greater than
electric fuel and purchased energy as a percentage of electric revenues (25%).
It should be noted that both purchased gas costs (prior to October 1996) and
electric fuel costs are passed through to the customer with no mark-up for
profit. Effective October 1996, the Maryland Commission approved a Market Based
Rates incentive mechanism for pricing gas. This mechanism is discussed in GAS
REGULATORY MATTERS AND COMPETITION. The combined effects of these factors yield
the observed relationship between operating revenues and income for electric
operations.
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CONSOLIDATED CAPITAL REQUIREMENTS
The Company's actual capital requirements for 1994 through 1996, along with
estimated amounts for 1997 through 1999, are set forth below.
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1994 1995 1996 1997 1998 1999
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(IN MILLIONS)
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Utility Business Capital Requirements
Construction expenditures (excluding AFC)
Electric.................................................... $ 345 $ 223 $ 219 $ 230 $ 216 $ 215
Gas......................................................... 68 70 84 72 70 73
Common...................................................... 42 51 46 33 39 37
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Total construction expenditures........................... 455 344 349 335 325 325
AFC (a)........................................................ 34 22 10 7 7 7
Nuclear fuel (uranium purchases and processing charges)........ 42 46 47 49 50 50
Deferred energy conservation expenditures (b).................. 41 46 31 24 19 18
Deferred nuclear expenditures (b).............................. 8 -- -- -- -- --
Retirement of long-term debt and redemption of preference
stock....................................................... 203 279 184 173 117 270
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Total utility business capital requirements............... 783 737 621 588 518 670
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Diversified Business Capital Requirements........................ 88 173 170 322 345 391
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Total capital requirements................................ $ 871 $ 910 $ 791 $ 910 $ 863 $ 1,061
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(a) Allowance for Funds Used During Construction (AFC) is accrued for all
construction projects with a construction period of more than one month.
(See NOTE 1 TO CONSOLIDATED FINANCIAL STATEMENTS for a discussion of AFC.)
(b) See NOTE 5 TO CONSOLIDATED FINANCIAL STATEMENTS for a discussion of deferred
nuclear expenditures and deferred energy conservation expenditures.
Utility business capital requirements do not reflect costs to complete the
pending Merger with PEPCO. These costs, currently estimated to be $150 million,
are discussed in NOTE 12 TO CONSOLIDATED FINANCIAL STATEMENTS.
BGE's actual capital requirements may vary from the estimates set forth
above because of a number of factors such as inflation, economic conditions,
regulation, legislation, load growth, environmental protection standards, and
the cost and availability of capital. Additionally, actual capital requirements
may vary from the estimates set forth above because adjustments which may result
from the pending Merger with PEPCO have not been reflected in those estimates.
The capital requirements for diversified businesses may vary from the estimates
set forth above due to a number of factors including market and economic
conditions. The capital requirements for these businesses are discussed in
detail in two sections of this report: DIVERSIFIED BUSINESS CAPITAL REQUIREMENTS
and ITEM 7. MD&A -- CAPITAL REQUIREMENTS OF OUR DIVERSIFIED BUSINESSES.
BGE's estimated construction, nuclear fuel, and deferred energy
conservation expenditures are expected to amount to approximately $1.6 billion,
$245 million, and $100 million, respectively, for the five-year period
1997-2001. Electric construction expenditures reflect improvements in BGE's
existing generating plants and its transmission and distribution facilities.
Future electric construction expenditures do not include additional generating
units. During the period January 1, 1992 through December 31, 1996, BGE expended
$2.0 billion for gross additions to utility plant or approximately 25% of its
total utility plant (exclusive of nuclear fuel) at December 31, 1996. During the
same period, a total of $423 million of utility plant was retired. Nuclear fuel
expenditures include uranium purchases and processing charges.
BGE presently estimates that approximately $1.1 billion will be required
for retirements and redemptions of long-term debt (including sinking fund
payments) and BGE preference stock during the five-year period 1997-2001. This
estimate does not consider the proposed Merger with PEPCO.
For further information with respect to capital requirements and for a
discussion of internal generation of cash, see ITEM 7. MD&A -- LIQUIDITY AND
CAPITAL RESOURCES.
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ELECTRIC BUSINESS
BGE's electric utility business in Maryland provides the major portion of
revenues and earnings to the consolidated company. This business is discussed
below in six sections titled ELECTRIC REGULATORY MATTERS AND COMPETITION;
ELECTRIC RATE MATTERS; NUCLEAR OPERATIONS; ELECTRIC LOAD MANAGEMENT, ENERGY, AND
CAPACITY PURCHASES; FUEL FOR ELECTRIC GENERATION; AND ELECTRIC OPERATING
STATISTICS. BGE recently announced its intention to enter the electric power
marketing business through a subsidiary, which is discussed under the heading
DIVERSIFIED BUSINESSES.
ELECTRIC REGULATORY MATTERS AND COMPETITION
In recent years BGE focused strategic attention to developments in federal
regulatory policy which are designed to increase competition in the wholesale
market for bulk power and expand competition in the market for generation. In
1993, the BGE Board of Directors formed the Long Range Strategy Committee to
provide an oversight role in the development of BGE's long range strategic goals
and to consider strategic initiatives which Management wished to present to the
BGE Board.
Many of these developments were prompted by the Energy Policy Act of 1992
(the 1992 Act), which granted the Federal Energy Regulatory Commission (FERC)
the authority to order electric utilities to provide transmission service to
other utilities and to other buyers and sellers of electricity in the wholesale
market. The 1992 Act also created a new class of power producers, exempt
wholesale generators, which are exempt from regulation under the Public Utility
Holding Company Act of 1935, as amended (the 1935 Act). This exemption has
increased the number of entrants into the electric generation market. Other
developments resulted from policies at the Securities and Exchange Commission
(SEC), which has liberalized its interpretation and administration of the 1935
Act in ways that have made mergers between utility companies less burdensome,
thereby facilitating the creation of larger industry competitors. Moreover,
state regulatory bodies in certain states had initiated proceedings to review
the basic structure of the industry.
Against this background, BGE and PEPCO agreed to merge in September 1995.
Each company independently reached the conclusion that key factors contributing
to success in a more competitive environment will be maintaining low-cost
production and achieving a size that will enable it to continue to provide high
quality customer service, enhancing its competitive position and attaining a
greater level of financial strength.
BGE, PEPCO, and Constellation Energy Corporation (formerly named R.H.
Acquisition Corp.) entered into the Agreement and Plan of Merger dated as of
September 22, 1995 (the Merger Agreement). The Merger Agreement provides that
upon the receipt of all necessary approvals (including shareholder approval --
obtained in 1996 -- and a number of regulatory approvals -- several of which are
still pending) BGE and PEPCO will be merged into Constellation Energy
Corporation (the Merger). Constellation Energy Corporation is a shell
corporation formed for the sole purpose of accomplishing the Merger. It is
currently anticipated that all such approvals will be obtained during the first
six months of 1997. The status of these approvals through the date of this
report is found in NOTE 12 TO CONSOLIDATED FINANCIAL STATEMENTS.
Preliminary estimates by the managements of PEPCO and BGE indicate that the
synergies resulting from the combination of their utility operations could
generate net cost savings of up to $1.3 billion over a period of 10 years
following the Merger. These estimates indicate that about two-thirds of the
savings will come from reduced labor costs, with the remaining savings split
between nonfuel purchasing and corporate and administrative programs. These
savings are expected to be allocated among shareholders and customers. This
allocation will depend upon the results of regulatory proceedings in the various
jurisdictions in which BGE and PEPCO operate their utility businesses. The
reasons for the Merger, the terms and conditions contained in the Merger
Agreement, and other matters concerning the Merger, PEPCO, and Constellation
Energy Corporation are discussed in more detail in the Registration Statement on
Form S-4 (Registration No. 33-64799) which is included as an exhibit to this
Report on Form 10-K by incorporation by reference. The analyses employed in
order to develop estimates of potential savings as a result of the Merger were
necessarily based upon various assumptions which involve judgments with respect
to, among other things, future national and regional economic and competitive
conditions, inflation rates, regulatory treatment, weather conditions, financial
market conditions, interest rates, future business decisions and other
uncertainties, all of which are difficult to predict and many of which are
beyond the control of BGE and PEPCO. Accordingly, while BGE believes that such
assumptions are reasonable for purposes of the development of estimates of
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potential savings, there can be no assurance that such assumptions will
approximate actual experience or that all such savings will be realized.
State regulators around the United States are also redefining the
regulatory scheme for the electric utility industry. The Maryland Public Service
Commission (Maryland Commission), after hearings in 1995 to consider electric
utility restructuring, the impact of competition, regulatory reform and possible
scenarios ranging from limited to full competition, had concluded that wholesale
competition remains in the best interests of the state's energy consumers in
view of the availability of efficient, reliable, comparatively low-cost power.
During 1996 the pace of other states' actions to allow retail competition
accelerated and two neighboring states, Pennsylvania and New Jersey, initiated
retail competition schemes. In light of these activities, in 1996 the Maryland
Commission started a new inquiry on retail competition and requested during 1997
both:
(Bullet) recommendations from its staff, and
(Bullet) filings from electric utilities with customers in Maryland to show
how unbundled electric rates might be structured.
The first analysis of retail competition by the District of Columbia Public
Service Commission is currently in progress. At the date of this report, we do
not expect any final action from the Maryland or District of Columbia
Commissions regarding retail competition during 1997.
It is not possible to predict the ultimate effect competition will have on
BGE's earnings in the future.
ELECTRIC RATE MATTERS
ENERGY CONSERVATION SURCHARGE
The Maryland Commission approved a base rate surcharge effective July 1,
1992 which provides for the recovery of deferred energy conservation
expenditures, a return thereon, lost revenues, and incentives for achievement of
predetermined goals for certain conservation programs subject to an earnings
test. Effective April 1996 this earnings test is performed on an annual basis.
All or a portion of the compensation for foregone sales due to conservation
programs and the incentives for achieving conservation goals must be refunded to
customers if BGE is earning in excess of its authorized rate of return, as
determined by the Maryland Commission. (See discussion in ITEM 7. MD&A --
RESULTS OF OPERATIONS.) The surcharge is reset on July 1 of each year.
ELECTRIC FUEL RATE PROCEEDINGS
By statute, electric fuel costs are recoverable if the Maryland Commission
finds that BGE demonstrates that, among other things, it has maintained the
productive capacity of its generating plants at a reasonable level. The Maryland
Commission and Maryland's highest appellate court have interpreted this as
permitting a subjective evaluation of each unplanned outage at BGE's generating
plants to determine whether or not BGE had implemented all reasonable and cost
effective maintenance and operating control procedures appropriate for
preventing the outage. The Maryland Commission has established a Generating Unit
Performance Program (GUPP) to measure annual utility compliance with maintaining
the productive capacity of generating plants at reasonable levels by
establishing a system-wide generating performance target and individual
performance targets for each base load generating unit. As a result, actual
generating performance, after adjustment for planned outages, is compared to the
system-wide target and, if met, should signify compliance with the requirements
of Maryland law. Failure to meet the system-wide target will result in review of
each unit's adjusted actual generating performance versus its performance target
in determining compliance with the law, and the basis for possibly imposing a
penalty on BGE. Failure to meet these targets requires BGE to demonstrate that
the outages causing the failure are not the result of mismanagement. Parties to
fuel rate hearings may still question the prudence of BGE's actions or inactions
with respect to any given generating plant outage, which could result in a
disallowance of replacement energy costs. BGE is involved in fuel rate
proceedings annually where issues concerning individual plant outages can be
raised. Recovery of a portion of replacement energy costs has been denied in
past proceedings and BGE cannot estimate the amount that could be denied in
future fuel rate proceedings, but such amounts could be material. (See NUCLEAR
OPERATIONS.)
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BGE is required to submit to the Maryland Commission the actual generating
performance data for each calendar year 45 days after year end. The Maryland
Commission reviews BGE's performance for each calen-
dar year in the first fuel rate proceeding initiated following the submission of
the actual generating performance data for that year. BGE 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
Discussed below are certain events relating to the operations of the
Calvert Cliffs Nuclear Power Plant (the Plant) during the period 1987 to the
present, including issues involving the possible disallowance of replacement
energy costs incurred during unplanned outages at the Plant. All outstanding
issues will be resolved in fuel rate proceedings before the Maryland Commission
which are conducted in accordance with the procedures outlined above under
ELECTRIC RATE MATTERS -- ELECTRIC FUEL RATE PROCEEDINGS.
OPERATIONS IN 1987
The Plant generated 10,069,576 megawatt hours (MWH) in 1987 which resulted
in a capacity factor of 70%. In October 1988, BGE filed a fuel rate application
for a change in its electric fuel rate under GUPP, which covered BGE's operating
performance in 1987. This was the first proceeding filed under this program and
BGE's filing demonstrated that it met the system-wide and individual plant
performance targets for 1987, including the performance target for the Plant.
BGE believed, therefore, it was entitled to recover all fuel costs incurred in
1987 without any disallowances. However, People's Counsel alleged that a number
of the outages at the Plant, including the 66-day outage to document compliance
with NRC mandated environmental qualification requirements, were due to
management imprudence and requested that the Maryland Commission disallow
recovery of the associated replacement energy costs which BGE estimated to be
approximately $33 million. On January 23, 1995, the Hearing Examiner issued his
decision in the 1987 fuel rate proceeding and found that the Company had met the
GUPP standard which establishes a presumption that BGE had operated the Plant at
a reasonably productive capacity level. However, the Order found that the
presumption of reasonableness could be overcome by a showing of mismanagement
and that such a showing was made with respect to the environmental
qualifications outage time. In mitigation for meeting the GUPP standard, the
Hearing Examiner disallowed replacement energy costs recovery for 15.5 days of
the 66-day outage time. The Hearing Examiner's Order was appealed to the
Maryland Commission by both BGE and People's Counsel. The Maryland Commission
upheld the Hearing Examiner's findings with respect to the environmental
qualification related outage time, but disagreed with certain methodologies
applied by the Hearing Examiner. The impact of the Maryland Commission's
decision on the Company's 1996 earnings was approximately $4.5 million. People's
Counsel has filed a motion for rehearing.
OPERATIONS IN 1988
The Plant generated 11,733,900 MWH in 1988 which resulted in a capacity
factor of 81%. BGE filed a fuel rate application under GUPP in May, 1989 in
which it demonstrated that it met the system-wide and individual plant
performance targets for 1988. People's Counsel alleged that BGE imprudently
managed several outages at the Plant and requested that the Maryland Commission
disallow recovery of $2 million of replacement energy costs. On November 14,
1991, a Hearing Examiner at the Maryland Commission issued a proposed Order,
which became final on December 17, 1991 and concluded that no disallowance was
warranted. The Hearing Examiner found that BGE maintained the productive
capacity of the Plant at a reasonable level, noting that it produced a near
record amount of power and exceeded the GUPP standard. Based on this record, the
Order concluded there was sufficient cause to excuse any avoidable failures to
maintain productive capacity at higher levels.
OPERATIONS IN 1989 TO 1991 -- EXTENDED OUTAGE
The Plant generated 2,719,197 MWH in 1989 and 1,251,416 MWH in 1990. In the
Spring of 1989, a leak was discovered around the Unit 2 pressurizer heater
sleeves during a refueling outage. BGE shut down Unit 1 as a precautionary
measure on May 6, 1989 to inspect for similar leaks and none were found at that
time. However, Unit 1 was out of service for the remainder of 1989 and 285 days
of 1990 to undergo maintenance and modification work to enhance the reliability
of various safety systems, to repair equipment, and to perform required periodic
surveillance tests. Unit 2 remained out of service until May 4, 1991 to
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complete repair of the pressurizer, perform maintenance and modification work,
and complete the refueling. The replacement energy costs associated with these
extended outages for both Units at Calvert Cliffs, concluding with the return to
service of Unit 2, were estimated at $458 million. This estimate was based on a
computer simulation comparing the actual operating conditions during the
extended outages with operating conditions assuming the Plant ran at its
targeted capacity factor.
The extended outages experienced at the Plant were reviewed by the Maryland
Commission in the 1989-1991 fuel rate proceeding, and People's Counsel and
others challenged recovery of some part of the associated replacement energy
costs. Extended litigation followed about the amount of replacement energy costs
BGE should be permitted to recover.
In December 1996, BGE entered into a settlement agreement with People's
Counsel and the Maryland Commission Staff proposing a resolution to all fuel
rate issues during the 1989-1991 period. The Maryland Commission approved the
settlement agreement in early 1997. BGE agreed that ratepayers will not fund a
total of $118 million of electric replacement energy costs associated with the
extended outages. This represents $83 million in addition to the $35 million
reserve for possible disallowance of replacement energy costs recorded in 1990.
Therefore, in December 1996, BGE increased the provision for the disallowance of
such costs by $83 million. Additionally, in 1996, BGE wrote off $5.6 million of
accrued carrying charges related to the deferred fuel balances. The remainder of
the replacement energy costs associated with the extended outage had already
been recovered from customers through the fuel rate.
OPERATIONS SUBSEQUENT TO 1991
The Plant generated 10,663,950 MWH in 1992, which resulted in a capacity
factor of 74%. There were no contested performance issues based on 1992
performance and BGE's GUPP filings were approved as filed. The Plant generated
12,300,816 MWH in 1993, which resulted in a capacity factor of 85%. In 1994, the
Plant generated 11,225,977 MWH achieving a capacity factor of 77%. Review of the
GUPP filings in 1993 and 1994 have been completed. There were no significant
performance issues in either of these years and BGE's GUPP filings were approved
as filed. The plant generated 12,940,496 MWH in 1995, which resulted in a
capacity factor of 88%. The plant generated 12,069,937 MWH in 1996, which
resulted in a capacity factor of 82%. A review of 1995 and 1996 performance will
be initiated with BGE's next fuel rate application.
ELECTRIC LOAD MANAGEMENT, ENERGY, AND CAPACITY PURCHASES
BGE has implemented various active load management programs designed to be
used when system operating conditions require a reduction in load. These
programs include customer-owned generation and curtailable service for large
commercial and industrial customers, air conditioning control which is available
to residential and commercial customers, and residential water heater control.
The load reductions typically have been invoked on peak summer days; potential
reduction in the Summer 1997 peak load from active load management is
approximately 475 megawatts (MW). Cost recovery for these load management
programs is attainable through the inclusion in rate base of capital investments
and the appropriate expenses (including credits on customer bills) for recovery
in base rate proceedings.
The generating and transmission facilities of BGE are interconnected with
those of neighboring utility systems to form the Pennsylvania-New
Jersey-Maryland Interconnection (PJM). Under the PJM agreement, the
interconnected facilities are used for substantial energy interchange and
capacity transactions as well as emergency assistance. In addition, BGE enters
into short-term capacity transactions at various times to meet PJM obligations.
BGE has an agreement with Pennsylvania Power & Light Company (PP&L) to
purchase a mix of energy and capacity 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 entitles BGE to 5.94% of the
energy 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 also
enables BGE to treat a portion of PP&L's capacity as BGE's capacity for purposes
of satisfying BGE's installed capacity requirements as a member of the PJM. BGE
is 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. BGE's firm capacity purchases at
7
<PAGE>
December 31, 1996 represented 170 MW of rated capacity of Bethlehem Steel
Corporation's Sparrows Point complex, 57 MW of rated capacity of the Baltimore
Refuse Energy Systems Company, and the 130 MW of Susquehanna capacity from PP&L.
In 1994 PECO Energy won a competitive bidding program to supply 140 MW for
firm electric capacity and associated energy for 25 years beginning June 1,
1998. This contract has been accepted by both FERC and the Maryland Commission.
FUEL FOR ELECTRIC GENERATION
Information regarding BGE's electric generation by fuel type and the cost
of fuels in the five-year period 1992-1996 is set forth in the following tables:
<TABLE>
<CAPTION>
AVERAGE COST OF FUEL CONSUMED
GENERATION BY FUEL TYPE ((CENTS) PER MILLION BTU)
------------------------------------ ----------------------------------------------
1996 1995 1994 1993 1992 1996 1995 1994 1993 1992
---- ---- ---- ---- ---- ---- ---- ---- ---- ----
<S><C>
Nuclear (a)................... 40% 43% 39% 43% 40% 47.29 47.22 52.06 53.01 45.54
Coal.......................... 58 57 56 55 54 143.80 148.64 148.64 151.85 154.76
Oil........................... 1 1 3 3 1 313.33 267.59 245.28 253.36 254.19
Hydro & Gas................... 4 3 3 3 3 -- -- -- -- --
--- --- --- --- ---
103 104 101 104 98
Interchange/
Purchases (b)............... (3) (4) (1) (4) 2
--- --- --- --- ---
100% 100% 100% 100% 100%
=== === === === ===
</TABLE>
(a) Nuclear fuel costs provide for disposal costs associated with long-term
off-site spent fuel storage and shipping, currently set by law at one mill
per kilowatt-hour of nuclear generation (approximately 10 cents per million
Btu) and for contributions to a fund for decommissioning and decontaminating
the Department of Energy's uranium enrichment facility. (See FUEL FOR
ELECTRIC GENERATION -- NUCLEAR.)
(b) Net purchases from (sales to) others.
COAL: BGE obtains a large amount of its coal under supply contracts with
mining operators. The remainder of its coal requirements are obtained through
spot purchases. BGE believes that it will be able to renew such contracts as
they expire or enter into similar contractual arrangements with other coal
suppliers. BGE's Brandon Shores Units 1 and 2 have a total annual requirement of
approximately 3,500,000 tons of coal (combined) with a sulfur content of less
than approximately 0.8%. BGE's Crane Units 1 and 2 have a total annual
requirement of about 700,000 tons of coal (combined) with a low ash melting
temperature. BGE's Wagner Units 2 and 3 have a total annual requirement of
approximately 900,000 tons of coal (combined) with a sulfur content of no more
than 1%.
Coal deliveries to BGE's coal burning facilities are made by rail and
barge. The coal used by BGE is produced from mines located in central and
northern Appalachia.
BGE has 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. 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, BGE's 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 BGE barges from the suppliers'
Baltimore Harbor marine terminal for distribution to the various generating
plant locations.
8
<PAGE>
NUCLEAR: The supply of fuel for nuclear generating stations involves the
acquisition of uranium concentrates, its conversion to uranium hexafluoride,
enrichment of uranium hexafluoride, and the fabrication of nuclear fuel
assemblies. Information is set forth below with respect to fuel for Calvert
Cliffs Units 1 and 2:
<TABLE>
<S> <C>
Uranium Concentrates: BGE has, either in inventory or under contract, sufficient quantities of
uranium to meet at least 90% of its requirements through 2000 and
approximately 70% of its requirements between 2001 and 2004.
Conversion: BGE has contractual commitments providing for the conversion of uranium
concentrates into uranium hexafluoride which will meet approximately 90%
of its requirements through 2000 and approximately 65% between 2001 and
2004.
Enrichment: BGE has a contract with the U.S. Energy Corporation for the enrichment of
100% of BGE's enrichment requirements through 1998, declining to
approximately 50% by 2004.
Fuel Assembly Fabrication: BGE has contracted for the fabrication of fuel assemblies for reloads it
requires through 2000.
</TABLE>
The nuclear fuel market is very competitive and BGE does not anticipate any
problem in meeting its requirements beyond the periods noted above. Expenditures
for nuclear fuel are discussed in ITEM 7. MD&A -- LIQUIDITY AND CAPITAL
RESOURCES.
STORAGE OF SPENT NUCLEAR FUEL: Under the Nuclear Waste Policy Act of 1982
(the 1982 Act), spent fuel discharged from nuclear power plants, including
Calvert Cliffs, is required to be placed into a federal repository. Such
facilities do not currently exist, and, consequently, must be developed and
licensed. BGE cannot now predict when such facilities will be available,
although the 1982 Act obligates the federal government to accept spent fuel
starting in 1998. While BGE cannot now predict what the ultimate cost will be,
the 1982 Act assesses a one mill per kilowatt-hour fee on nuclear electricity
generated and sold. At anticipated operating levels, it is expected that this
fee will be approximately $13 million for Calvert Cliffs each year.
In December 1996, the United States Department of Energy (DOE) notified BGE
and other nuclear utilities that it is unable to meet the 1998 deadline for
accepting spent fuel. BGE is participating 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 are requesting that the court allow them to pay fees, that formerly
went directly to DOE, into escrow instead. Among other remedies, they seek to
force DOE to submit a program with milestones illustrating how DOE will meet the
deadline for accepting spent nuclear fuel and a monthly report to allow the
utilities to monitor DOE's progress.
Maryland law makes it unlawful to establish within the State a facility for
the permanent storage of high-level nuclear waste, unless otherwise expressly
required by federal law. BGE has received a license from the NRC to operate its
on-site independent spent fuel storage facility. BGE now has storage capacity at
Calvert Cliffs that will accommodate spent fuel from operations through the year
2006. In addition, BGE can expand its 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 utilities to
contribute to a fund for decommissioning and decontaminating the Department of
Energy's (DOE) 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 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 "UTILITY PLANT,
DEPRECIATION AND AMORTIZATION, AND DECOMMISSIONING."
GAS: BGE has a firm natural gas transportation entitlement of 3,500
dekatherms a day to provide ignition and banking at certain power plants. Gas
for electric generation is purchased as needed in the spot market using
interruptible transportation arrangements. Certain gas fired units can use
residual fuel oil as an alternative.
9
<PAGE>
ELECTRIC OPERATING STATISTICS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------
1996 1995 1994 1993 1992
---- ---- ---- ---- ----
<S><C>
Electric Output (In Thousands) -- MWH:
Generated................................ 30,107 30,548 28,413 28,907 25,626
Purchased (A)............................ 7,560 7,403 6,270 3,643 4,323
---------- ---------- ---------- ---------- ----------
Subtotal............................ 37,667 37,951 34,683 32,550 29,949
Less Interchange and Other Sales......... 7,580 8,149 5,684 4,149 3,180
---------- ---------- ---------- ---------- ----------
Total Output........................ 30,087 29,802 28,999 28,401 26,769
========== ========== ========== ========== ==========
Power Generated and Purchased at
Times of Peak Load (MW) (one hour):
Generated by Company..................... 4,789 5,162 3,384 5,245 3,679
Net Purchased (A)........................ 1,166 785 2,654 631 1,879
---------- ---------- ---------- ---------- ----------
Peak Load (B)............................ 5,955 5,947 6,038 5,876 5,558
========== ========== ========== ========== ==========
Annual System Load Factor (%).............. 57.5 57.2 54.7 55.2 54.8
Revenues (In Thousands)
Residential.............................. $ 958,736 $ 955,239 $ 931,711 $ 931,643 $ 839,954
Commercial............................... 861,343 879,438 852,989 869,829 842,694
Industrial............................... 207,579 208,441 205,611 199,042 201,950
---------- ---------- ---------- ---------- ----------
System Sales............................. 2,027,658 2,043,118 1,990,311 2,000,514 1,884,598
Interchange and Other Sales.............. 155,877 166,964 118,027 91,543 64,323
Other.................................... 25,492 21,029 19,083 20,090 16,611
---------- ---------- ---------- ---------- ----------
Total............................... $2,209,027 $2,231,111 $2,127,421 $2,112,147 $1,965,532
========== ========== ========== ========== ==========
Sales (In Thousands) -- MWH:
Residential.............................. 11,243 10,966 10,670 10,614 9,735
Commercial............................... 12,591 12,635 12,351 12,395 11,909
Industrial............................... 4,596 4,591 4,433 3,763 3,663
---------- ---------- ---------- ---------- ----------
System Sales............................. 28,430 28,192 27,454 26,772 25,307
Interchange and Other Sales.............. 7,580 8,149 5,684 4,149 3,180
---------- ---------- ---------- ---------- ----------
Total............................... 36,010 36,341 33,138 30,921 28,487
========== ========== ========== ========== ==========
Customers
Residential.............................. 995,197 988,179 978,591 968,212 956,570
Commercial............................... 104,501 103,399 101,957 100,820 99,673
Industrial............................... 4,261 4,161 3,967 3,800 3,761
---------- ---------- ---------- ---------- ----------
Total............................... 1,103,959 1,095,739 1,084,515 1,072,832 1,060,004
========== ========== ========== ========== ==========
Average Cost of Fuel Consumed ((cents) per
million Btu)............................. 108.05 104.78 112.44 112.77 110.20
========== ========== ========== ========== ==========
</TABLE>
BGE achieved an all-time peak load of 6,038 megawatts on January 19, 1994.
(A) Includes purchases from Safe Harbor Water Power Corporation, a hydroelectric
company, of which the Company owns two-thirds of the capital stock.
(B) See ELECTRIC LOAD MANAGEMENT, ENERGY, AND CAPACITY PURCHASES for a
discussion of active load management programs which may be activated at
times of peak load.
10
<PAGE>
GAS OPERATING STATISTICS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------
1996 1995 1994 1993 1992
---- ---- ---- ---- ----
<S><C>
Gas Output (In Thousands) -- DTH:
Purchased.......................................... 70,260 70,391 68,541 71,221 70,211
LNG Withdrawn from Storage......................... 904 815 698 725 742
Produced........................................... 784 528 828 259 92
-------- -------- -------- -------- --------
Total Output.................................. 71,948 71,734 70,067 72,205 71,045
Delivery service gas (A)........................... 45,964 43,854 41,897 38,521 41,048
Off-system sales (B)............................... 10,204 -- -- -- --
-------- -------- -------- -------- --------
Total......................................... 128,116 115,588 111,964 110,726 112,093
======== ======== ======== ======== ========
Peak Day Sendout (DTH)............................... 708,966 706,287 761,900 657,700 609,200
======== ======== ======== ======== ========
Capability on Peak Day (DTH)......................... 870,000 847,000 847,000 847,000 847,000
Revenues (In Thousands)
Residential........................................ $320,105 $248,283 $262,736 $265,601 $242,737
Commercial
Excluding Delivery Service...................... 125,052 109,859 121,005 121,832 112,147
Delivery Service................................ 7,217 3,696 2,285 3,287 3,591
Industrial
Excluding Delivery Service...................... 17,064 16,730 20,140 22,250 21,123
Delivery Service................................ 14,598 16,332 9,635 12,920 14,290
-------- -------- -------- -------- --------
System sales....................................... 484,036 394,900 415,801 425,890 393,888
Off-system sales................................... 26,600 -- -- -- --
Other.............................................. 6,656 5,604 5,448 7,273 6,511
-------- -------- -------- -------- --------
Total......................................... $517,292 $400,504 $421,249 $433,163 $400,399
======== ======== ======== ======== ========
Sales (In Thousands) -- DTH:
Residential........................................ 43,784 40,211 40,279 40,029 39,042
Commercial
Excluding Delivery Service...................... 22,698 23,612 23,712 23,830 23,478
Delivery Service................................ 8,755 6,982 6,490 7,428 7,102
Industrial
Excluding Delivery Service...................... 2,887 4,102 4,410 5,298 5,314
Delivery Service................................ 36,201 35,925 33,837 31,390 33,638
-------- -------- -------- -------- --------
System sales....................................... 114,325 110,832 108,728 107,975 108,574
Off-system sales................................... 10,204 -- -- -- --
-------- -------- -------- -------- --------
Total......................................... 124,529 110,832 108,728 107,975 108,574
======== ======== ======== ======== ========
Customers
Residential........................................ 516,523 506,739 498,152 491,165 486,863
Commercial......................................... 38,861 38,422 37,891 37,518 37,000
Industrial......................................... 1,350 1,334 1,354 1,353 1,412
-------- -------- -------- -------- --------
Total......................................... 556,734 546,495 537,397 530,036 525,275
======== ======== ======== ======== ========
</TABLE>
BGE achieved an all-time peak day sendout of 761,900 DTH on January 19,
1994.
(A) Represents gas purchased by customers directly from suppliers for which BGE
receives a fee for transportation through its system ("delivery service").
(See ITEM 7. MD&A -- RESULTS OF OPERATIONS.)
(B) Represents gas sold to suppliers and end users of natural gas outside BGE's
service territory (beginning first quarter 1996). (See ITEM 7.
MD&A -- RESULTS OF OPERATIONS).
Certain prior year amounts have been reclassified to conform with the
current year's presentation.
11
<PAGE>
GAS BUSINESS
BGE's gas utility business in Maryland is discussed on the previous page
under GAS OPERATING STATISTICS and below in three sections titled REGULATORY
MATTERS AND COMPETITION; GAS OPERATIONS; AND GAS RATE MATTERS. BGE also has a
subsidiary that is active in the gas marketing business, which is discussed
under the heading DIVERSIFIED BUSINESSES.
GAS REGULATORY MATTERS AND COMPETITION
Regulatory changes in the natural gas business are well under way. In 1992,
the Federal Energy Regulatory Commission (FERC) issued Order 636, which
unbundled gas-service elements. This gave gas users the ability to choose
various gas purchasing, transportation, brokering, and storage options. Prior to
Order 636, BGE purchased gas, transportation and storage services primarily from
pipeline companies. Now, BGE and other local distribution companies buy gas
directly from various suppliers and arrange separately for transportation and
storage. BGE's large gas customers are arranging for their own gas supplies and
are contracting with BGE for transportation. The Maryland Commission continues
to encourage BGE and other utilities to offer options for unbundling the gas
services offered by local distribution companies and allowing smaller customers
to arrange for their own gas supplies.
As part of its response to the increase in competition in the natural gas
business, BGE has obtained approval from the Maryland Commission to utilize
profit sharing for earnings from off-system gas sales and capacity release
revenues, and to implement a Market Based Rates (MBR) incentive gas purchasing
mechanism. Off-system gas sales are direct sales to suppliers and end users of
natural gas outside BGE's service territory. BGE makes these sales as part of a
program to balance its supply of, and cost of, natural gas. Under the MBR
mechanism, differences between a market index and BGE's actual cost of gas are
shared equally between BGE's customers and shareholders.
GAS OPERATIONS
BGE distributes natural gas purchased directly from several producers and
marketers. Transportation to BGE's city gate for these purchases is provided by
Columbia Gas Transmission Corporation (Columbia), CNG Transmission Corporation
(CNG), and Transcontinental Gas Pipe Line Corporation under various
transportation agreements. BGE has upstream transportation capacity under
contract on Tennessee Gas Pipeline Company, Texas Eastern Transmission
Corporation, Columbia Gulf Transmission Company and ANR Pipeline Company (ANR).
BGE has storage service agreements with Columbia, CNG and ANR. The
transportation and storage agreements are on file with the Federal Energy
Regulatory Commission (FERC).
BGE's current pipeline firm transportation entitlements to serve its firm
loads are 291,731 dekatherms (DTH) per day during the winter period and 266,731
DTH per day during the summer period. BGE uses the firm transportation capacity
to move gas from the Gulf of Mexico, Louisiana, south central regions of Texas
and Canada to BGE's city gate. The gas is subject to a mix of long and
short-term contracts that are managed to provide economic, reliable and flexible
service. Additional short-term contracts or exchange agreements with other gas
companies can be arranged in the event of short-term emergencies.
BGE has two market area storage contracts to manage weather sensitive gas
demand during the winter period. Current maximum storage entitlements are
181,866 DTH per day. To supplement BGE's gas supply at times of heavy winter
demands and to be available in temporary emergencies affecting gas supply, BGE
has propane air and liquefied natural gas facilities. The liquefied natural gas
facility consists of a plant for the liquefaction and storage of natural gas
with a storage capacity of 1,000,000 DTH and a planned daily capacity of 287,988
DTH. The propane air facility consists of a plant with a mined cavern and
refrigerated storage facilities having a total storage capacity equivalent to
1,000,000 DTH and a daily capacity of 85,000 DTH. BGE has under contract
sufficient volumes of propane for the operation of the propane air facility and
is capable of liquefying sufficient volumes of natural gas during the summer
months for operation of its liquefied natural gas facility during winter
periods.
BGE offers gas for sale to its residential, commercial and industrial
customers on a firm and interruptible basis.
BGE also provides its commercial and industrial customers with a
transportation service across its distribution system so that these customers
may make direct purchase and transportation arrangements with
12
<PAGE>
suppliers and pipelines. Customers with 250 DTH or more of annual gas
consumption may make direct purchase and transportation arrangements. BGE also
plans to conduct a pilot transportation program for up to 25,000 residential
customers beginning in November 1997. A transportation fee is charged by BGE
that is equivalent to its operating margin on gas it sells to similar customers
for the service from the city gate to the customer's facility. This program
enables BGE to maintain throughput at a level which assures that fixed costs are
spread over the maximum number of DTH. BGE is authorized by the Maryland
Commission to provide balancing and gas brokering services for its
transportation customers and to bundle pipeline capacity with gas for off-system
sales.
GAS RATE MATTERS
On November 20, 1995, the Maryland Commission issued an Order (the 1995
Rate Order) authorizing BGE an annualized gas base rate increase of $19.3
million, including $2.4 million to recover higher depreciation expense. The
increase is equivalent to approximately 3.7% of total 1996 gas revenues. In
granting the increase, the Commission provided a return on BGE's higher level of
gas rate base associated with system expansion and improvement and recognized
increases in gas operating expenses associated with maintaining the expanded gas
distribution system. This was partially offset by a reduction in the authorized
gas rate of return to 9.04% from the 9.40% gas rate of return previously
authorized.
The 1995 Rate Order also provided for the recognition of the remaining
portion of postretirement benefits costs not currently included in gas rates and
authorized the Company, effective January 1, 1998, to begin amortizing over a
fifteen-year period the gas portion of postretirement and postemployment benefit
costs deferred prior to December 1995. In addition, the Maryland Commission
authorized the Company to amortize certain environmental costs incurred through
October 1995 over a ten-year period and to defer for future recovery additional
environmental costs incurred after that date.
FRANCHISES
BGE has nonexclusive electric and gas franchises to use streets and other
highways which are adequate and sufficient to permit BGE to engage in its
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 BGE's gas properties in that municipality. Conditions
of the franchises are satisfactory. BGE also has rights-of-way to maintain
26-inch natural gas mains across certain Baltimore City owned property
(principally parks) which expire in 1998 and 2004, each subject to renewal
during the last year thereof for an additional period of 25 years on a fair
revaluation of the rights so granted. Conditions of the grants are satisfactory.
Franchise provisions relating to rates have been superseded by the Public
Service Commission Law of Maryland.
DIVERSIFIED BUSINESSES
The Company is engaged in diversified businesses through three groups of
subsidiaries.
BGE CORP. AND SUBSIDIARIES -- OUR ENERGY MARKETING COMPANIES INCLUDING OUR NEW
POWER MARKETING BUSINESS
BGE Corp. is a wholly owned subsidiary of BGE that serves as the holding
company for our three energy marketing businesses:
(Bullet) Power Marketing -- We recently formed a new subsidiary,
CONSTELLATION POWER SOURCE, INC., for the purpose of entering the
power marketing business. This new business involves the purchase
and sale of electric power and electric power derivatives, and
related activities including power brokering, marketing, risk
management activities, and derivative trading. Goldman Sachs
Power, LLC, an affiliate of Goldman Sachs & Co., the investment
banking firm, is the exclusive advisor to Constellation Power
Source, Inc. for risk management and power marketing.
13
<PAGE>
(Bullet) Natural Gas Brokering -- During 1996 we expanded the activities of
CONSTELLATION ENERGY SOURCE, INC. (formerly named BNG, Inc.). This
subsidiary provides natural gas brokering and related services for
wholesale and retail customers.
(Bullet) Energy Services -- In 1995, we created BGE ENERGY PROJECTS &
SERVICES, INC., which provides energy services including private
electric and gas distribution systems, energy consulting, power
quality, and campus energy systems. We provide district cooling
and heating systems through that subsidiary and through our
partnership with the Poole & Kent Company, called COMFORTLINKTM.
We also sell power quality equipment through another subsidiary,
POWERDIGM SYSTEMS, INC.; and perform energy services contracting
work though a subsidiary SKILES ENERGY CORP.
THE CONSTELLATION COMPANIES -- POWER GENERATION, REAL ESTATE, AND FINANCIAL
INVESTMENTS
The Constellation Companies' businesses are concentrated in three major
areas -- power generation projects, financial investments, and real estate
projects (including senior-living facilities). A significant portion of the
Constellation Companies' activities are conducted through joint ventures in
which they hold varying ownership interests.
The Constellation Companies hold up to a 50% ownership interest in 26 power
generating projects in operation or under construction and indirect ownership of
minority interests in several power generation and distribution projects
accounting for $373 million of the Constellation Companies' assets. These
projects, all of which either are qualifying facilities under the Public Utility
Regulatory Policies Act of 1978 or are otherwise exempt from the Public Utility
Holding Company Act of 1935, are of the following types and aggregate generation
capacities: coal 160 MW, solar 170 MW, geothermal 126 MW, waste coal 182 MW,
wood burning 70 MW, hydro 30 MW, and natural gas 182 MW. In addition, another $4
million has been spent on projects in development. The Constellation Companies
also participate in the operation and maintenance of 15 power generation
projects existing or under construction, 12 of which are projects in which the
Constellation Companies hold an ownership interest. Financial investments
account for $204 million of the Constellation Companies' assets. These assets
include $94 million in internally and externally managed securities portfolios,
$77 million in a monoline financial guaranty (credit enhancement) company, and
$33 million in tax-oriented transactions. Real estate and senior-living projects
account for $562 million of the Constellation Companies' assets. These projects
include raw land, office buildings, retail projects, distribution facility
projects, an entertainment, dining, and retail complex in Orlando, Florida
(which we may sell as discussed below), a mixed-use planned-unit development,
and senior-living facilities. The majority of the real estate projects are in
the Baltimore-Washington area and have been adversely affected by the depressed
real estate and economic market.
The Constellation Companies' investment in wholesale power generating
projects includes $227 million representing ownership interests in 16 projects
that sell electricity in California under Interim Standard Offer No. 4 (SO4)
power purchase agreements. Under these agreements, the projects supply
electricity to purchasing utilities at a fixed rate for the first ten years of
the agreements and thereafter at fixed capacity payments plus variable energy
rates based on the utilities' avoided cost for the remaining term of the
agreements. Avoided cost generally represents a utility's lowest-cost
next-available source of generation to service the demands on its system. These
power generation projects began the conversion to supplying electricity at
avoided cost rates in 1996 and will continue to convert through the end of 2000.
As a result of declines in purchasing utilities' avoided costs subsequent to the
inception of these agreements, revenues at these projects based on current
avoided cost levels would be substantially lower than revenues presently being
realized under the fixed price terms of the agreements. At current avoided cost
levels, the Constellation Companies would experience reduced earnings or incur
losses associated with these projects, which could be significant. While eight
projects transition from fixed to variable energy rates in 1997 and 1998,
revenues from the other projects having SO4 contracts are expected to continue
to increase during this period tending to offset revenue declines on those
projects. Six of the seven largest revenue producing projects will not make the
transition to variable energy rates until the 1999-2000 timeframe such that any
material reductions in revenues would not be anticipated before 2000.
During the second quarter of 1996, the Constellation Companies determined
that successful mitigation measures for two of these plants are now unlikely and
that the investment in these plants was impaired. Accordingly, the Constellation
Companies recorded a $7.0 million after-tax write off of the investment in these
plants.
14
<PAGE>
The Constellation Companies are investigating and pursuing alternatives for
certain of these power generation projects including, but not limited to,
repowering the projects to reduce operating costs, changing fuels to reduce
operating costs, renegotiating the power purchase agreements to improve the
terms, restructuring financings to improve the financing terms, and selling its
ownership interests in the projects.
The Company cannot predict the financial impact that these matters
regarding any of these projects may have on the Constellation Companies or BGE,
but the impact could be material.
FIRST QUARTER EVENT WILL RESULT IN AN ESTIMATED $12 MILLION AFTER TAX WRITEDOWN
AT THE CONSTELLATION COMPANIES
In ITEM 7. MD&A -- CONSTELLATION COMPANIES' OPERATIONS AND NOTE 12 TO
CONSOLIDATED FINANCIAL STATEMENTS, we discuss the real estate market and
financial matters about the Constellation Companies' real estate projects
including:
(Bullet) our current real estate strategy is to hold each real estate
project until we can realize a reasonable value for it,
(Bullet) depending on market conditions, we could have losses on
future sales,
(Bullet) accounting rules require a writedown to market value if either of
two things occurs:
-- we change our intent to hold a project to an intent to sell,
or
-- expected cash flow from a project is less than the investment
in the project.
In mid-March we received an unsolicited offer to buy the Constellation
Companies' Church Street Station, which is an entertainment, dining, and retail
complex in Orlando, Florida. Because of the unique character of Church Street
Station and the geographic distance of this project from our other real estate
holdings in the Baltimore-Washington corridor, we decided that considering a
sale is the appropriate strategy. We plan to negotiate with this potential
purchaser and also to explore whether there are others who are interested in
purchasing the project on better terms.
Based on the accounting rules mentioned above, our decision is a change of
intent, and we are required to write down our investment to the market value.
Determining the market value for such a unique project is difficult, but the
unsolicited offer is the best indication available to us and we used it to
determine the amount of the writedown.
Although all financial data for the first quarter is not yet available,
this means we expect the Constellation Companies' earnings for the first quarter
of 1997 to be generally flat compared to 1996 in spite of this writedown.
BGE HOME PRODUCTS & SERVICES, INC. AND ITS SUBSIDIARY -- OUR HOME PRODUCTS AND
COMMERCIAL BUILDING SYSTEMS BUSINESSES
For many years, BGE sold and serviced appliances and provided home
improvements. In 1994, BGE moved this business into a subsidiary, BGE Home
Products & Services, Inc. This company sells and services appliances, including
televisions, stereo and sound equipment, video cassette recorders, videocameras,
washers, dryers, ranges, refrigerators, microwaves, and other appliances
primarily used by customers at home. It has an active home improvement business
including kitchen and bathroom remodeling, replacement doors and windows,
siding, and roofing. Its subsidiary, Maryland Environmental Systems, Inc.
specializes in the installation and service of commercial and residential
heating, air conditioning, plumbing, and electrical systems.
15
<PAGE>
DIVERSIFIED BUSINESS CAPITAL REQUIREMENTS
Capital requirements for diversified businesses for 1994 through 1996,
along with estimated amounts for 1997 through 1999, are set forth below:
<TABLE>
<CAPTION>
1994 1995 1996 1997 1998 1999
---- ---- ---- ---- ---- ----
(IN MILLIONS)
<S><C>
Diversified Business Capital Requirements
- -----------------------------------------
Investment requirements................................ $51 $118 $118 $214 $180 $205
Retirement of long-term debt........................... 37 55 52 108 165 186
--- ---- ---- ---- ---- ----
Total diversified business capital requirements...... $88 $173 $170 $322 $345 $391
=== ==== ==== ==== ==== ====
</TABLE>
In the past, capital requirements of our diversified businesses only
included the Constellation Companies because they had the only significant
capital requirements. However, we anticipate Constellation Power Source, Inc.
will have significant capital requirements and these are included in the table
for future years. As discussed below under "Investment Requirements," capital
requirements for ComfortLink are also included this year.
Our diversified businesses expect to expand their businesses. This may
include expansion in the energy marketing, power generation, financial
investments, real estate, and senior-living facility businesses. Such expansion
could mean more investments in and acquisition of new projects. Our diversified
businesses have met their capital requirements in the past through borrowing,
cash from their operations, and from time to time, loans or equity contributions
from BGE. Our diversified businesses plan to raise the cash needed to meet
capital requirements in the future through these same methods.
DIVERSIFIED BUSINESS INVESTMENT REQUIREMENTS
The investment requirements shown above include the Constellation
Companies' investments in financial limited partnerships and funding for the
development and acquisition of projects, as well as net loans made to project
partnerships, ComfortLink's funding for construction of district energy
projects, and funding for growing Constellation Power Source's power marketing
business. Investment requirements for the years 1997 through 1999 reflect
estimates of funding during such periods for ongoing and anticipated projects.
Also, guarantees of $47 million may be called which are not included above.
Estimates of our diversified businesses' investment requirements are
subject to continuous review and modification. Actual investment requirements
may vary significantly from the amounts above due to the type and number of
projects selected for development, the impact of market conditions on those
projects, the ability to obtain financing, and the availability of internally
generated cash.
DIVERSIFIED BUSINESS DEBT AND LIQUIDITY
Our diversified businesses plan to meet capital requirements by refinancing
debt as it comes due, by additional borrowing, and with cash generated by the
businesses. This includes cash from operations, sale of assets, and earned tax
benefits. BGE Home Products & Services may also meet capital requirements
through sales of receivables as discussed in NOTE 12 TO CONSOLIDATED FINANCIAL
STATEMENTS.
If the Constellation Companies can get a reasonable value for real estate,
additional cash may be obtained by selling real estate projects. The
Constellation Companies' ability to sell or liquidate assets will depend on
market conditions, and we cannot give assurances that these sales or
liquidations could be made.
In addition, the Constellation Companies have a $75 million revolving
credit agreement and ComfortLink has a $50 million revolving credit agreement to
provide additional cash for short-term financial needs.
See NOTES 3 and 4 TO CONSOLIDATED FINANCIAL STATEMENTS AND ITEM 7.
MD&A -- LIQUIDITY AND CAPITAL RESOURCES -- CAPITAL REQUIREMENTS OF OUR
DIVERSIFIED BUSINESSES for additional information about diversified businesses.
16
<PAGE>
ENVIRONMENTAL MATTERS
The Company is subject to regulation with regard to air and water quality,
waste disposal, and other environmental matters by various federal, state, and
local authorities. Certain of these regulations require substantial expenditures
for additions to utility plant and the use of more expensive low-sulfur fuels.
While the Company cannot now precisely estimate the total effect of existing and
future environmental regulations and standards upon its existing and proposed
facilities and operations, the necessity for compliance with existing standards
and regulations has caused BGE to increase capital expenditures by approximately
$138 million during the five-year period 1992-1996. It is estimated that the
capital expenditures necessary to comply with such standards and regulations
will be approximately $16 million, $38 million, and $14 million for 1997, 1998,
and 1999, respectively.
AIR: The Federal Clean Air Act (the Act) mandates health and welfare
standards for concentrations of air pollutants. The State of Maryland is charged
by the Act with the responsibility for setting limits on all major sources of
these pollutants in the State so that these standards are not exceeded. Except
for Crane Units 1 and 2, BGE's generating units are limited to burning fuel
(coal or oil) with sulfur content of 1% or below. All units are limited to
emitting particulate matter at or below 0.02 grains per standard cubic foot of
exhaust gas for oil fired units and 0.03 grains per standard cubic foot for
coal-fired units. Brandon Shores, a newer plant, is subject to more stringent
standards for sulfur dioxide (1.2 pounds per million Btu), and nitrogen dioxide
(0.7 pounds per million Btu). The Crane Units must meet limits of 3.5 pounds per
million Btu for sulfur dioxide, which is equivalent to a coal sulfur content of
approximately 2.4%. BGE is in compliance with existing air quality regulations.
The Clean Air Act Amendments of 1990 contain two titles designed to reduce
emissions of sulfur dioxide and nitrogen oxide (NOx) from electric generating
stations. Title IV contains provisions for compliance in two phases. Phase I of
Title IV became effective January 1, 1995, and Phase II of Title IV must be
implemented by 2000. BGE met the requirements of Phase I by installing flue gas
desulfurization systems and through fuel switching and unit retirements. BGE is
currently examining what actions will be required in order to comply with Phase
II. However, BGE anticipates that compliance will be attained by some
combination of fuel switching, flue gas desulfurization, unit retirements, or
allowance trading.
At this time, plans for complying with NOx control requirements under Title
I of the Act are less certain because all implementation regulations have not
yet been finalized by the government. It is expected that by the year 1999 these
regulations will require additional NOx controls for ozone attainment at BGE's
generating plants and other BGE facilities. The controls will result in
additional expenditures that are difficult to predict prior to the issuance of
such regulations. Based on existing and proposed ozone nonattainment
regulations, BGE currently estimates that the NOx controls at BGE's generating
plants will cost approximately $90 million. BGE is currently unable to predict
the cost of compliance with the additional requirements at other BGE facilities.
WATER: The discharge of effluents into the waters of the State of Maryland
is regulated by the Maryland Department of the Environment (MDE), in accordance
with the National Pollutant Discharge Elimination System (NPDES) permit program,
established pursuant to the Federal Clean Water Act. At the present time, all of
BGE's steam electric generating plants have the required NPDES permits.
MDE water quality regulations require, among other things, specifying
procedures for determining 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. At this time BGE continually performs studies to
determine whether any modifications will be required to comply with these
regulations.
WASTE DISPOSAL: The United States Environmental Protection Agency (EPA) has
promulgated regulations implementing those portions of the Resource Conservation
and Recovery Act which deal with management of hazardous wastes. These
regulations, and the Hazardous and Solid Waste Amendments of 1984, designate
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 similar regulations governing the
management of hazardous wastes, which closely parallel the federal regulations.
BGE has implemented procedures for compliance with all applicable federal and
state regulations governing the management of hazardous wastes. Certain high
volume utility wastes such as fly ash and bottom ash have been exempted from
these regulations. The Company currently utilizes almost all of its coal fly ash
and bottom
17
<PAGE>
ash as structural fill material in a manner approved by the State of Maryland.
The remainder of the coal ash is sold to the construction industry for a number
of approved applications.
The Federal Comprehensive Environmental Response, Compensation and
Liability Act (Superfund statute) establishes liability for the cleanup of
hazardous wastes found contaminating 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 their predecessors in title at the time of the contamination.
In addition, many states have enacted laws similar to the Superfund statute.
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 BGE and seven
other defendants to recover past and future expenditures associated with cleanup
of a site located at Kane and Lombard Streets in Baltimore. The EPA complaint
was dismissed in November 1995. The State of Maryland intervened by filing a
similar complaint in the same case and court on February 12, 1990. The
complaints allege that BGE arranged for its fly ash to be deposited on the site.
Settlement discussions continue among all parties. Additional investigation was
initiated on the remainder of the site by the MDE for the EPA but was never
completed. BGE and three other defendants agreed to complete the remedial
investigation and feasibility study of groundwater contamination around the site
in a July 1993 consent order. The remedial action, if any, for the remainder of
the site will not be selected until these investigations are concluded.
Therefore, neither the total site cleanup costs, nor BGE's share, can presently
be estimated.
In the early 1970's, BGE 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 (PCBs are hazardous chemicals frequently used as a fire-resistant
coolant in electrical equipment). On December 7, 1987, the EPA notified BGE and
nine other utilities that they are considered potentially responsible parties
(PRPs) with respect to the cleanup of the site. A remedial investigation and
feasibility study (RI/FS) by BGE and the other PRPs was submitted to the EPA on
October 14, 1994. Estimated costs for the various remedies included in the RI/FS
range greatly (from $15 million to $45 million). Until a specific remedy is
chosen, BGE is not able to predict the actual cleanup costs. BGE's share of the
cleanup costs, estimated to be approximately 15.79%, could be material.
From 1985 until 1989, BGE shipped waste oil and other materials to the
Industrial Solvents and Chemical Company in York County, Pennsylvania for
disposal. The Pennsylvania Department of Environmental Resources (Pennsylvania
Department) subsequently investigated this site and found it to be heavily
contaminated by hazardous wastes. The Pennsylvania Department notified BGE on
August 15, 1990, that it and approximately 1,000 other entities were PRPs with
respect to the cost of all remedial activities to be conducted at the site. The
PRPs have agreed to perform waste characterization, remove and dispose of all
tanks and drums of waste, and perform a remedial investigation at the site.
BGE's share of the liability at this site currently is estimated to be
approximately 2.39%, but this may change as additional information about the
site is obtained. The actual cost of remedial activities has not been
determined. As a result of these factors, BGE's potential liability cannot
presently be estimated. However, such liability is not expected to be material.
On August 30, 1994, BGE was named as a defendant in UNITED STATES V.
KEYSTONE SANITATION COMPANY, ET AL. The litigation was instituted by EPA in the
United States District Court for the Middle District of Pennsylvania involving
contamination of the Keystone Sanitation Company landfill Superfund site located
in Adams County, Pennsylvania. BGE was named as a third party defendant based
upon allegations that BGE had drums of asbestos shipped to the site. There are
eleven original defendants, approximately 150 other third party defendants, and
approximately 570 fourth party defendants. Neither the costs of future site
remediation, nor the extent of BGE's potential liability can be estimated at
this time. However, such liability is not expected to be material.
In December 1995, BGE was notified by the EPA that it is 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. BGE, through its 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 a clean up of the site which will consist of removal of
drums of radioactive and hazardous mixed wastes. To date the EPA has processed
approximately one third of the drums and incurred expenses of about $2.2
million. After the EPA completes its drum removal phase of the clean up it will
investigate potential soil and groundwater contamination.
18
<PAGE>
Although BGE's potential liability cannot be estimated, it is believed that such
liability is not likely to be substantial based on the limited amount of waste
shipped to the site from BGE facilities.
In September, 1996, BGE received an information request from the EPA
concerning 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 was spent on the drum removal action. To our
knowledge, no long-term remediation is planned for this site. In addition, we
understand that EPA has sent information requests to approximately 17 other
parties. BGE's records indicate that it sold empty drums to Drumco, Inc. from
approximately 1983-1990. BGE is currently reviewing all relevant documents and
interviewing employees involved in selling the drums to Drumco. BGE's potential
liability cannot be estimated at this time. However we believe that any
liability is not likely to be material based on BGE's records showing that only
empty storage drums were sold to Drumco, Inc.
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. BGE is coordinating an investigation of these former
coal gas plant sites, including exploration of corrective action options to
remove coal tar, with the MDE. In late December 1996, the Maryland Department of
the Environment and BGE signed a consent order that requires BGE to implement
remedial action plans addressing contamination at and related to the Spring
Gardens site. The specific remedial actions for this site will be developed in
the future. As explained in NOTE 12 TO CONSOLIDATED FINANCIAL STATEMENTS, BGE
has recognized estimated environmental costs at all former gas manufacturing
plant sites (based on remedial action options) which are considered probable
totaling $50 million in nominal dollars. These costs, net of accumulated
amortization, have been deferred as a regulatory asset (see NOTE 5 TO
CONSOLIDATED FINANCIAL STATEMENTS). Accounting rules also require BGE to
disclose additional costs deemed by BGE to be less likely than probable costs,
but still "reasonably possible" of being incurred at these sites. Because of the
results of recent studies at these sites, it is reasonably possible that these
additional costs could exceed the amount recognized by approximately $48 million
in nominal dollars ($11 million in current dollars, plus the impact of inflation
at 3.1% over a period of up to 60 years).
As previously disclosed, on May 3, 1994 Constellation Power, Inc. (formerly
"Constellation Energy, Inc.") (CPI) was named as a defendant in REPUBLIC
IMPERIAL ACQUISITION V. STOCKMAR ENERGY, INC., ET AL. Civil No. 940120R(LSP)
(Dist. Ct., So. Dist. California), litigation concerning a waste landfill. In
December 1996, CPI was dismissed from this proceeding.
EMPLOYEES
As of December 31, 1996, BGE employed 7,032 people.
19
<PAGE>
ITEM 2. PROPERTIES
ELECTRIC: The principal electric generating plants of BGE are as follows:
<TABLE>
<CAPTION>
GENERATION
INSTALLED ----------
PLANT LOCATION CAPACITY (MW) PRIMARY FUEL 1996 1995
----- -------- ------------- ------------ ---- ----
(AT DECEMBER 31, 1996)
<S><C>
Steam
Calvert Cliffs Calvert County, MD 1,675 Nuclear 12,069,937 12,937,965
Brandon Shores Anne Arundel County, MD 1,291 Coal 8,849,357 9,091,443
Herbert A. Wagner Anne Arundel County, MD 1,006 Coal/Oil/Gas 3,149,334 3,002,183
Charles P. Crane Baltimore County, MD 380 Coal 2,000,992 1,631,798
Gould Street Baltimore City, MD 104 Oil 49,583 66,851
Riverside Baltimore County, MD 78 Oil/Gas 15,356 40,229
Jointly Owned -- Steam
Keystone Armstrong and 359(A) Coal 2,650,786 2,429,568
Indiana Counties, PA
Conemaugh Indiana County, PA 181(A) Coal 1,202,914 1,244,060
Combustion Turbine
Notch Cliff Baltimore County, MD 128 Gas 12,470 27,702
Perryman Harford County, MD 350 Oil/Gas 91,197 42,875
Westport Baltimore City, MD 121 Gas 6,420 19,133
Riverside Baltimore County, MD 173 Oil/Gas 5,450 7,118
Philadelphia Road Baltimore City, MD 64 Oil 1,829 4,813
Charles P. Crane Baltimore County, MD 14 Oil 707 1,237
Herbert A. Wagner Anne Arundel County, MD 14 Oil 513 971
----- ---------- ----------
Totals 5,938 30,106,845 30,547,946
===== ========== ==========
</TABLE>
(A) BGE-owned proportionate interest and entitlement. These totals include
diesel capacity of 2 megawatts and 1 megawatt for Keystone and Conemaugh,
respectively.
BGE also owns two-thirds of the outstanding capital stock of Safe Harbor Water
Power Corporation, and is currently entitled to 277 megawatts of the rated
capacity of the Safe Harbor Hydroelectric Project. Safe Harbor is operated under
a FERC license which expires in the year 2030.
GAS: BGE has propane air and liquefied natural gas facilities as described in
GAS OPERATIONS.
GENERAL: All of the principal plants and other important units of BGE located
in Maryland are held in fee except that several properties (not including any
principal electric or gas generating plant or the principal headquarters
building owned by BGE in downtown Baltimore) in BGE's service area are held
under lease arrangements. The leased spaces are used for various offices and
service. Electric transmission and electric and gas distribution lines are
constructed principally (a) in public streets and highways pursuant to
franchises or (b) on permanent fee simple or easement rights-of-way secured for
the most part by grants from record owners and to a relatively small part by
condemnation.
BGE's undivided interests as a tenant-in-common in the properties acquired for
the Keystone and Conemaugh Plants located in Pennsylvania are held in fee by
BGE, subject to minor defects and encumbrances which do not materially interfere
with the use of the properties by BGE.
All of BGE's property referred to above is subject to the lien of the Mortgage
securing BGE's First Refunding Mortgage Bonds.
20
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
ASBESTOS
Since 1993, BGE has been served in several actions concerning asbestos. The
actions are collectively titled IN RE BALTIMORE CITY PERSONAL INJURIES ASBESTOS
CASES in the Circuit Court for Baltimore City, Maryland. The actions are based
upon the theory of "premises liability," alleging that BGE knew of and exposed
individuals to an asbestos hazard. The actions relate to two types of claims.
The first type, direct claims by individuals exposed to asbestos, were
described in a Report on Form 8-K filed August 20, 1993. BGE and approximately
70 other defendants are involved. Approximately 520 non-employee plaintiffs each
claim $6 million in damages ($2 million compensatory and $4 million punitive).
BGE does not know the specific facts necessary for BGE to assess its potential
liability for these type claims, such as the identity of the BGE facilities at
which the plaintiffs allegedly worked as contractors, the names of the
plaintiffs' employers, and the date on which the exposure allegedly occurred.
The second type are claims made by one manufacturer -- Pittsburgh Corning
Corp. -- against BGE and approximately eight others, as third-party defendants.
These claims relate to approximately 1,500 individual plaintiffs. BGE does not
know the specific facts necessary for BGE to assess its potential liability for
these type claims, such as the identity of BGE facilities containing asbestos
manufactured by the manufacturer, the relationship (if any) of each of the
individual plaintiffs to BGE, the settlement amounts for any individual
plaintiffs who are shown to have had a relationship to BGE, and the dates on
which/places at which the exposure allegedly occurred.
Until the relevant facts for both type claims are determined, BGE is unable
to estimate what its liability, if any, might be. Although insurance and hold
harmless agreements from contractors who employed the plaintiffs may cover a
portion of any ultimate awards in the actions, BGE's potential liability could
be material.
See ITEM 1. BUSINESS -- ELECTRIC RATE MATTERS, NUCLEAR OPERATIONS,
ENVIRONMENTAL MATTERS, and NOTE 12 TO CONSOLIDATED FINANCIAL STATEMENTS for
other information about legal or regulatory proceedings involving BGE.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable.
21
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
STOCK TRADING
BGE's 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 28, 1997, there were 76,929 common shareholders of record.
DIVIDEND POLICY
We pay dividends on our Common Stock when our Board of Directors declares
them. There is no limitation on our paying Common Stock dividends, other than we
must first pay all dividends (and any redemption payments) due on our preference
stock.
Dividends have been paid on the Common Stock continuously since 1910.
Future dividends depend upon future earnings, the financial condition of the
Company and other factors. Quarterly dividends were declared on the Common Stock
during 1996 and 1995 in the amounts set forth below.
COMMON STOCK DIVIDENDS AND PRICE RANGES
<TABLE>
<CAPTION>
1996 1995
----------------------------- ----------------------------
PRICE* PRICE*
DIVIDEND ------------- DIVIDEND ----------------
DECLARED HIGH LOW DECLARED HIGH LOW
-------- ---- --- -------- ---- ---
<S><C>
First Quarter......................................... $ .39 $ 29-1/2 $ 26-1/8 $ .38 $ 25 $ 22
Second Quarter........................................ .40 28-5/8 25-1/2 .39 26-1/2 23-1/8
Third Quarter......................................... .40 28-5/8 25 .39 26-5/8 24-3/8
Fourth Quarter........................................ .40 28-3/4 25-3/4 .39 29 25-1/2
------ -----
Total............................................... $ 1.59 $1.55
====== =====
</TABLE>
*Based on New York Stock Exchange Composite Transactions as reported in the
eastern edition of THE WALL STREET JOURNAL.
22
Item 6. Selected Financial Data
<TABLE>
<CAPTION>
Compound
1996 1995 1994 1993 1992 Growth
- -----------------------------------------------------------------------------------------------------------------------------
(Dollar amounts in thousands, except per share amounts) 5-Year 10-Year
<S> <C>
Summary of Operations
Total Revenues $3,153,247 $2,934,799 $2,782,985 $2,741,385 $2,559,536 4.63% 4.63%
Expenses Other Than Interest and Income
Taxes 2,483,782 2,239,107 2,147,726 2,124,993 2,024,227 4.15 5.21
-------------------------------------------------------------
Income From Operations 669,465 695,692 635,259 616,392 535,309 6.54 2.73
Other Income 6,130 8,819 32,365 20,310 22,132 (26.25) (9.83)
-------------------------------------------------------------
Income Before Interest and Income Taxes 675,595 704,511 667,624 636,702 557,441 5.55 2.49
Net Interest Expense 198,438 196,977 190,154 188,764 189,747 0.19 5.82
-------------------------------------------------------------
Income Before Income Taxes 477,157 507,534 477,470 447,938 367,694 8.37 1.39
Income Taxes 166,333 169,527 153,853 138,072 103,347 14.22 1.65
-------------------------------------------------------------
Net Income 310,824 338,007 323,617 309,866 264,347 4.17 1.25
Preferred and Preference Stock Dividends 38,536 40,578 39,922 41,839 42,247 (2.05) 3.67
-------------------------------------------------------------
Earnings Applicable to Common Stock $ 272,288 $ 297,429 $ 283,695 $ 268,027 $ 222,100 5.26 0.95
=============================================================
Earnings Per Share of Common Stock $1.85 $2.02 $1.93 $1.85 $1.63 2.07 (1.26)
Dividends Declared Per Share of Common
Stock $1.59 $1.55 $1.51 $1.47 $1.43 2.58 3.03
Ratio of Earnings to Fixed Charges 3.10 3.21 3.14 3.00 2.65 6.43 (2.97)
Ratio of Earnings to Fixed Charges and
Preferred and Preference Stock Dividends
Combined 2.44 2.52 2.47 2.34 2.08 6.04 (2.68)
Financial Statistics at Year End
Total Assets $8,550,970 $8,316,663 $8,037,502 $7,829,613 $7,208,660 3.68 6.44
=============================================================
Capitalization
Long-term debt $2,758,769 $2,598,254 $2,584,932 $2,823,144 $2,376,950 2.91 5.62
Preferred stock -- 59,185 59,185 59,185 59,185 -- --
Redeemable preference stock 134,500 242,000 279,500 342,500 395,500 (19.53) 10.40
Preference stock not subject to mandatory
redemption 210,000 210,000 150,000 150,000 110,000 13.81 6.68
Common shareholders' equity 2,857,113 2,812,682 2,717,866 2,620,511 2,534,639 5.82 5.77
-------------------------------------------------------------
Total Capitalization $5,960,382 $5,922,121 $5,791,483 $5,995,340 $5,476,274 3.12 5.63
=============================================================
Book Value Per Share of Common Stock $19.35 $19.07 $18.42 $17.94 $17.63 2.62 3.43
Number of Common Shareholders 77,550 79,811 81,505 82,287 80,371 1.74 0.07
</TABLE>
Baltimore Gas and Electric Company and Subsidiaries
23
<PAGE>
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 and its diversified business
subsidiaries including:
(bullet) what factors affect our business,
(bullet) what our earnings and costs were in 1996 and 1995,
(bullet) why those earnings and costs were different from the year before,
(bullet) where our earnings came from,
(bullet) how all of this affects our overall financial condition,
(bullet) what our expenditures for capital projects were in 1994 through 1996
and what we expect them to be in 1997 through 1999, and
(bullet) where cash will come from to pay for future capital expenditures.
As you read Management's Discussion and Analysis, it may be helpful to refer to
our Consolidated Statements of Income on page 35, which present the results of
our operations for 1996, 1995, and 1994. In Management's Discussion and
Analysis, we analyze and explain the annual changes in the specific line items
in the Consolidated Statements of Income. Our analysis may be important to you
in making decisions about your investments in BGE.
You may notice some changes in this year's discussion, compared to past years.
This is because we volunteered to participate in a pilot program with the
Securities and Exchange Commission to write financial documents in plain
English. As a result, we have re-written our entire Management's Discussion and
Analysis section. Our goal is to discuss our financial condition in language
that is more easily understood.
BGE and Potomac Electric Power Company have agreed to merge into a new company
named Constellation Energy Corporation. We plan to complete the merger as soon
as we obtain all regulatory approvals. These matters are discussed in more
detail in Note 12 beginning on page 52 and in a Registration Statement on
Form S-4 (Registration No. 33-64799). The merger may impact many of the matters
discussed in Management's Discussion and Analysis including earnings, results of
electric operations, expenses, liquidity, and capital resources.
The electric utility industry is undergoing rapid and substantial change.
Competition is increasing. The regulatory environment (federal and state) is
shifting. These matters are discussed briefly in the "Competition and Response
to Regulatory Change" section on page 26 in Management's Discussion and
Analysis. They are discussed in detail in this Annual Report on Form 10-K. BGE
continuously evaluates these changes. Based on the evaluations, BGE refines
short and long term business plans with the primary goal of protecting our
security holders' investments and providing them with superior returns on their
investment in BGE. In order to support this primary goal, we also focus on other
groups who impact our primary goal. For example, we stress providing low cost,
reliable power to our electric customers. As you read Management's Discussion
and Analysis, many BGE initiatives to support our primary goal are mentioned.
These include the proposed merger with Potomac Electric Power Company, designed
to position us to remain competitive as the industry changes, and our
diversification effort. We enter new businesses which we believe will support
our primary goal. For example, new businesses may be opportunities to:
(bullet) provide customers of our core energy business additional services, or
(bullet) attract new customers for our core energy business, or
(bullet) expand our diversified stream of revenues.
We believe our newest subsidiary, Constellation Power Source, Inc., will satisfy
all three criteria. Its proposed power marketing business is described in detail
in the front of this report.
- --------------------------------------------------------------------------------
Results of Operations
In this section, we discuss our 1996 and 1995 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
1996 1995 1994
- --------------------------------------------------------------------------------
Earnings per share from
current-year operations:
Utility business $1.96 $1.84 $1.81
Diversified businesses (subsidiaries) .31 .18 .12
----------------------
Total earnings per share from
current-year operations 2.27 2.02 1.93
Disallowed replacement
energy costs (see Note 12) (.42) -- --
----------------------
Total earnings per share $1.85 $2.02 $1.93
======================
1996
Our 1996 total earnings decreased $25.1 million, or $.17 per share, from 1995.
Our total earnings decreased because we reserved for disallowed replacement
energy costs. We discuss this in detail in the "Disallowed Replacement Energy
Costs" section on page 27.
In 1996, we had higher utility earnings from current-year operations due to
three factors: we sold more electricity and gas due to colder winter weather
(people use more gas and electricity to heat their homes in colder weather),
there was an increase in the number of customers, and we had lower operations
and maintenance expenses. We would have had even higher utility earnings from
current-year operations except we sold less electricity in the third quarter due
to milder summer weather. We discuss our utility earnings in more detail
beginning on page 26.
Baltimore Gas and Electric Company and Subsidiaries
24
<PAGE>
In 1996, we had higher earnings from our diversified business subsidiaries
mostly because the Constellation Companies had higher earnings from power
generation projects and financial investments. We discuss our diversified
business earnings in more detail beginning on page 30.
1995
Our 1995 total earnings increased $13.7 million, or $.09 per share, from 1994.
In 1995, we had higher utility earnings mostly due to greater sales of
electricity during an extremely hot summer and higher electricity and gas sales
resulting from colder fall weather. We would have had even higher utility
earnings except for the mild weather in the first half of the year, lower net
other income and deductions (miscellaneous non-operating income and expenses),
and lower allowance for funds used during construction (an accounting procedure
used to exclude the cost of capital from expense and include it as part of the
cost of utility plant construction).
In 1995, we had higher earnings from our diversified businesses mostly because
the Constellation Companies had higher earnings from power generation projects
and financial investments.
Utility Business
Before we go into the details of our electric and gas operations, we believe it
is important to discuss four 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
The Maryland Public Service Commission (Maryland Commission) 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 Commission 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 Commission allows us to include in base rates a component to
recover money spent on conservation programs. This component is called an
"energy conservation surcharge." However, under this surcharge the Maryland
Commission limits what our profit can be. If, at the end of the year, we have
exceeded our allowed profit, 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 (nuclear
fuel, coal, gas, or oil) we use to generate electricity. The actual cost of the
fuel is passed on to the customer with no profit. We also charge our gas
customers separately for the natural gas they consume. The price we charge for
the natural gas is based on a Market Based Rates incentive mechanism approved by
the Maryland Commission. We discuss Market Based Rates in more detail in the
"Gas Cost Adjustments" section on page 28 and in Note 1 on page 43.
From time to time, when necessary to cover increased costs, we ask the Maryland
Commission for base rate increases. Not every request for base rate increases is
granted in full. However, the Maryland Commission has historically allowed BGE
to increase base rates to recover costs for replacing utility plant assets, 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.
Weather
Weather affects the demand for electricity and gas, especially among our
residential customers. Very hot summers and very cold winters increase demand.
Mild weather reduces demand.
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 daily actual
temperature exceeds the 65 degree baseline. Heating degree days result when the
daily actual temperature is less than the baseline.
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.
The following chart shows the number of cooling and heating degree days in 1996
and 1995, shows the percentage changes in the number of degree days from prior
years, and shows the number of degree days in a "normal" year as represented by
the 30-year average.
30-Year
1996 1995 Average
- --------------------------------------------------------------------------------
Cooling degree days 786 1,056 804
Percentage change
compared to prior year (25.6)% 11.3%
Heating degree days 5,138 4,601 4,901
Percentage change
compared to prior year 11.7% (1.5)%
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.
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 separately measured. 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.
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 1996 and 1995.
Baltimore Gas and Electric Company and Subsidiaries
25
<PAGE>
Competition and Response to Regulatory Change
Our business is also affected by competition. Electric utilities are facing
competition on three fronts:
(bullet) in the construction of generating units to meet increased demand for
electricity,
(bullet) in the sale of their electricity in the bulk power markets, and
(bullet) in the future, for electric sales to retail customers which utilities
now serve exclusively.
We regularly reevaluate our strategies with two goals in mind: to improve our
competitive position, and to anticipate and adapt to regulatory changes. In
September 1995, we decided that a merger with Potomac Electric Power Company
would help us compete by maintaining low-cost production and increasing our
size. The pending merger is more thoroughly discussed in Note 12 on page 52.
Although we believe the merger will improve our competitive position in the
future, no one can predict the ultimate effect competition or regulatory change
will have on our earnings or on the earnings of the merged company.
We will continue to develop strategies to keep us competitive. These strategies
might include one or more of the following:
(bullet) the complete or partial separation of our generation, transmission, and
distribution functions
(bullet) other internal restructuring
(bullet) mergers or acquisitions of utility or non-utility businesses
(bullet) addition or disposition of portions of our service territories
(bullet) spin-off or distribution of one or more businesses
We cannot predict whether any transactions of the types described above may
actually occur, nor can we predict what their effect on our financial condition
or competitive position might be.
We discuss competition in our electric and gas businesses in more detail in this
Annual Report on Form 10-K under the headings "Electric Regulatory Matters and
Competition" and "Gas Regulatory Matters and Competition."
Utility Business Earnings per Share of Common Stock
1996 1995 1994
- --------------------------------------------------------------------------------
Utility earnings per share from
current-year operations:
Electric business $1.75 $1.70 $1.71
Gas business .21 .14 .10
-------------------------
Total utility earnings per share
from current-year operations 1.96 1.84 1.81
Disallowed replacement
energy costs (see Note 12) (.42) -- --
-------------------------
Total utility earnings per share $1.54 $1.84 $1.81
=========================
Our 1996 total utility earnings decreased $44.5 million, or $.30 per share, from
1995. Our 1995 utility earnings increased $5.6 million, or $.03 per share, from
1994.
We discuss the factors affecting utility earnings below.
Electric Operations
Electric Revenues
The changes in electric revenues in 1996 and 1995 compared to the respective
prior year were caused by:
1996 1995
- --------------------------------------------------------------------------------
(In millions)
Electric system sales volumes $ 0.4 $ 43.4
Base rates (2.5) 23.2
Fuel rates (12.3) (13.8)
----------------------
Total change in electric revenues
from electric system sales (14.4) 52.8
Interchange and other sales (11.1) 49.0
Other 4.5 1.4
----------------------
Total change in electric revenues $(21.0) $103.2
======================
Electric System Sales Volumes
"Electric system sales" are sales to customers in our service territory at rates
set by the Maryland Commission. These sales do not include interchange sales and
sales to others.
The percentage changes in our electric system sales volumes, by type of
customer, in 1996 and 1995 compared to the respective prior year were:
1996 1995
- --------------------------------------------------------------------------------
Residential 2.5% 2.8%
Commercial (0.3) 2.3
Industrial 0.1 3.6
In 1996, we sold more electricity to residential customers for three reasons:
colder weather in the first quarter, greater electricity usage per customer, and
an increase in the number of customers. We would have sold even more electricity
to residential customers except for milder summer weather. We sold about the
same amount of electricity to commercial and industrial customers as we did in
1995. As mentioned above, weather impacts residential, more than commercial and
industrial, sales. In 1996 other items offset the impact of weather on
commercial and industrial sales. Other items include the demand for power to
fuel manufacturing equipment and office machinery, which vary with changes in
the customers' businesses. For example, if a manufacturing plant has a slow
year, it will make less product and use less power to run its assembly lines.
In 1995, we sold more electricity to residential and commercial customers mostly
because we had an increase in the number of customers and we had extremely hot
summer weather and cold fall weather. We would have sold even more electricity
to those customers except we had milder weather in the first half of 1995
compared to 1994. We sold more electricity to industrial customers mostly
because we had an increase in the number of customers and more demand for
electricity from Bethlehem Steel (our largest customer).
Base Rates
In 1996, base rate revenues were about the same as they were in 1995. Although
we sold more electricity this year, our revenues did not increase because the
higher sales occurred during the winter when our base rates are lower.
Baltimore Gas and Electric Company and Subsidiaries
26
<PAGE>
In 1995, base rate revenues were higher than in 1994 because of a higher energy
conservation surcharge and also because we did not have to reduce conservation
revenues as we did in 1994, when we exceeded our allowed profit.
From July 1, 1993, through June 30, 1994, we exceeded our profit limit under the
energy conservation surcharge. To correct the overage, we lowered the surcharge
on our customers' bills from December 1993 to November 1994. As a result, we
billed $20.1 million less than we would have otherwise. We also exceeded the
limit on our profit during 1996. Therefore, we excluded $28.5 million of our
1996 surcharge billings from revenue, and we will lower the surcharge on our
customers' bills beginning in July 1997 to correct the overage.
Fuel Rates
The fuel rate is the rate the Maryland Commission allows us to charge our
customers for our actual cost of fuel with no profit to us. If the cost of fuel
goes up, the Maryland Commission permits us to increase the fuel rate. If the
cost of fuel goes down, our customers benefit from a reduction in the fuel rate.
The fuel rate is impacted most by the amount of electricity generated at the
Calvert Cliffs Nuclear Power Plant because the cost of nuclear fuel is cheaper
than coal, gas, or oil. (See Note 1 on page 43 for a further discussion of how
the fuel rate increases and decreases.)
Changes in the fuel rate normally do not affect earnings. However, if the
Maryland Commission disallows recovery of any part of the fuel costs, our
earnings are reduced. (We discuss this more thoroughly in the "Electric Fuel and
Purchased Energy Expenses" section below and in Note 12 on page 54.)
In 1996 and 1995, fuel rate revenues decreased due to a lower fuel rate because
we were able to operate plants with the lowest fuel costs to generate
electricity during the previous 24 months. Fuel rate revenues would have been
even lower except we sold more electricity. In 1995, the fuel rate was also
lower compared to 1994 because of lower fuel costs.
Interchange and Other Sales
"Interchange and other sales" are sales of energy in the Pennsylvania-New
Jersey-Maryland Interconnection (PJM) and to others. The PJM is a regional power
pool of eight utility member companies, including BGE. We sell energy to PJM
members and to others after we have satisfied the demand for electricity in our
own system.
In 1996, we had lower interchange and other sales compared to 1995 because we
generated less electricity at our Calvert Cliffs Nuclear Power Plant. This meant
that we had less electricity to sell outside of our service territory. We
generated less electricity at that plant mostly because the 1996 outage for
regular refueling and maintenance took longer than in 1995.
In 1995, interchange and other sales increased because we were able to operate
plants with the lowest fuel costs to generate electricity, had available
capacity, and had lower costs than other utilities. Specifically, we had greater
generation from our coal-fired Brandon Shores Power Plant, and our Calvert
Cliffs Nuclear Power Plant generated a record level of electricity during 1995.
Electric Fuel and Purchased Energy Expenses
1996 1995 1994
- --------------------------------------------------------------------------------
(In millions)
Actual costs $539.2 $554.5 $541.2
Net recovery of costs
under electric fuel
rate clause (see Note 1) 8.2 24.3 1.1
Disallowed replacement
energy costs (including
carrying charges)
(see Note 12) 95.4 -- --
--------------------------
Total electric fuel and
purchased energy expenses $642.8 $578.8 $542.3
==========================
Actual Costs
In 1996, our actual cost of fuel to generate electricity (nuclear fuel, coal,
gas, or oil) and electricity we bought from other utilities was lower than in
1995 because the price of electricity and capacity we bought from other
utilities was lower and we sold less electricity. The price we pay for
electricity and capacity we buy from other utilities changes based on market
conditions, complex pricing formulas for PJM transactions, and contract terms.
In 1995, our actual cost of fuel to generate electricity and electricity we
bought from other utilities was higher than in 1994 mostly because we generated
more electricity and the price of electricity and capacity we bought from other
utilities was higher. Our actual costs would have been even higher except we
were able to use a less-costly mix of generating plants, mostly because of
shorter refueling and maintenance downtime at our Calvert Cliffs Nuclear Power
Plant.
Electric Fuel Rate Clause
The "electric fuel rate clause" (determined by the Maryland Commission) requires
that we defer (to include as an asset or liability on the balance sheet and
exclude from income and expense) the difference between our actual costs of fuel
and our fuel rate revenues collected from customers through the fuel rate. We
bill or refund that difference to customers in the future.
In 1996 and 1995, our actual fuel costs were lower than the fuel rate revenues
we collected from our customers. As a result, we recovered fuel costs which we
had deferred in prior years.
Disallowed Replacement Energy Costs
During 1989 through 1991 we experienced extended outages at our Calvert Cliffs
Nuclear Power Plant. These outages have been the subject of ongoing fuel rate
proceedings before the Maryland Commission for several years (see Note 12 on
page 54).
In December 1996, we entered into a settlement agreement with the Maryland
People's Counsel and the Maryland Commission Staff. We agreed not to bill our
customers for $118 million of electric replacement energy costs associated with
these extended outages. We set up a reserve for $35 million of these costs in
1990. In 1996, we increased that reserve by $83 million and we wrote off $5.6
million of related carrying charges. In addition, we wrote off $6.8 million of
fuel costs that were disallowed by the Maryland Commission in May 1996 (we
discuss these costs further in Note 12 on page 54). These write-offs and the
increase in the reserve significantly increased our total purchased fuel and
energy expenses in 1996. The remainder of the replacement energy costs
associated with the extended outage has already been recovered from customers
through the fuel rate.
Baltimore Gas and Electric Company and Subsidiaries
27
<PAGE>
Gas Operations
Gas Revenues
The changes in gas revenues in 1996 and 1995 compared to the respective prior
year were caused by:
1996 1995
- --------------------------------------------------------------------------------
(In millions)
Gas system sales volumes $ 8.2 $ 0.2
Base rates 18.9 6.4
Gas cost adjustments 62.1 (27.4)
---------------------
Total change in gas revenues
from gas system sales 89.2 (20.8)
Off-system sales 26.6 --
Other 1.0 0.1
---------------------
Total change in gas revenues $116.8 $(20.7)
=====================
Gas System Sales Volumes
The percentage changes in our gas system sales volumes, by type of customer, in
1996 and 1995 compared to the respective prior year were:
1996 1995
- --------------------------------------------------------------------------------
Residential 8.9% (0.2)%
Commercial 2.8 1.3
Industrial (2.3) 47
In 1996, we sold more gas to residential and commercial customers due to colder
winter and early spring weather and an increase in the number of customers. We
would have sold even more gas to those customers except that gas usage per
customer decreased. We sold less gas to industrial customers because Bethlehem
Steel used less gas. We would have sold even less gas to industrial customers
except for increased gas usage by other industrial customers, an increase in the
number of customers, and colder winter weather.
In 1995, we sold about the same amount of gas to residential customers as we did
in 1994. We sold more gas to commercial customers for three reasons: an increase
in the number of customers, increased gas usage per customer, and colder weather
in the fall of 1995. We would have sold even more gas to commercial customers
except for milder weather in the first half of 1995. We sold more gas to
industrial customers due to greater gas usage per customer.
Base Rates
In 1996, base rate revenues were higher than in 1995 because in November 1995,
the Maryland Commission allowed us to increase our gas base rates. This
increased our annual base rate revenues for 1996 by $19.3 million, or
approximately 3.7% of total 1996 gas revenues. That amount included $2.4 million
to recover higher depreciation expense (an accounting procedure which spreads
the cost of utility plant in service over the years in which it is used).
In 1995, our base rate revenues were higher than in 1994 because of the energy
conservation surcharge.
Gas Cost Adjustments
Prior to October 1996, the Maryland Commission allowed us to recover the actual
cost of the gas sold to our customers through "gas cost adjustment clauses."
These clauses require that we defer the difference between our actual cost of
gas and the gas revenues we collect from customers. We bill or refund that
difference to customers in the future.
Effective October 1996, the Maryland Commission approved a modification of the
gas cost adjustment clauses to provide a "Market Based Rates" incentive
mechanism. In general terms, 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), and half of the difference belongs to shareholders. We discuss this in
more detail in Note 1 on page 43.
Delivery service customers, including Bethlehem Steel, are not subject to the
gas cost adjustment clauses because we are not selling them gas (we are selling
them the service of delivering their gas).
In 1996, gas cost revenues increased because we had to pay more for gas and we
sold more gas. In 1995, gas cost revenues decreased because we paid less for gas
and we sold less gas.
Off-System Sales
Off-system gas sales, which are direct sales to suppliers and end users of
natural gas outside our service territory, also are not subject to gas cost
adjustments. We began sales of off-system gas during the first quarter of 1996.
The Maryland Commission approved an arrangement for part of the earnings from
off-system sales to benefit customers (through reduced costs) and the remainder
to be retained by BGE (which benefits shareholders).
Gas Purchased For Resale Expenses
1996 1995 1994
- --------------------------------------------------------------------------------
(In millions)
Actual costs $295.4 $205.9 $222.7
Net recovery (deferral) of
costs under gas adjustment
clauses (see Note 1) (11.0) (7.8) 1.9
---------------------------
Total gas purchased for
resale expenses $284.4 $198.1 $224.6
===========================
Actual Costs
Actual costs include the cost of gas purchased for resale to our customers and
for sale off-system. These costs do not include the cost of gas purchased by
delivery service customers, including Bethlehem Steel.
In 1996, actual gas costs increased from 1995 due to three factors: higher
market prices of gas, higher sales volumes, and the purchase of gas to resell
off-system (beginning in the first quarter of 1996).
In 1995, actual gas costs decreased compared to 1994 because of the considerably
lower market price of gas. This decrease would have been even greater except
that we received supplier refunds in 1994 which reduced actual gas costs that
year.
Gas Adjustment Clauses
We charge customers for the cost of gas sold through gas adjustment clauses
(determined by the Maryland Commission), as discussed under "Gas Cost
Adjustments" earlier in this section.
In 1996 and 1995, the portion of our actual gas costs subject to these clauses
was higher than the revenues we collected from our customers. As a result, we
deferred the difference and will collect the costs from our customers in the
future. These deferrals decreased our total gas purchased for resale expenses in
1996 and 1995.
Baltimore Gas and Electric Company and Subsidiaries
28
<PAGE>
Other Operating Expenses
Operations and Maintenance Expenses
In 1996, our operations and maintenance expenses decreased $18.5 million due to
our continued efforts to control costs. This decrease would have been even
greater except we had higher costs to maintain our nuclear plant. In 1995, our
operations and maintenance expenses were about the same as they were in 1994.
Depreciation and Amortization Expenses
We describe depreciation and amortization expenses in Note 1 on page 44.
In 1996, our depreciation and amortization expense increased $12.8 million from
1995 for two reasons:
(bullet) we had more utility plant in service to be depreciated (as our level of
utility plant that is in service changes, the amount of our
depreciation expense changes), and
(bullet) we had more energy conservation program costs to be amortized.
The increase in these expenses would have been even greater except that in 1995
depreciation and amortization expense included $14.2 million for the write-off
of certain costs of our Perryman site, which is covered in more detail below. In
1996, depreciation and amortization expense did not include any such write-off.
In 1995, our depreciation and amortization expense increased $21.5 million over
1994 because we had more utility plant in service to be depreciated (mostly
because of some capital additions to our Calvert Cliffs Nuclear Power Plant),
and we had a higher level of energy conservation program costs to be amortized.
In addition, we completed a study of the cost to decommission Calvert Cliffs.
(Decommission is a term used in the nuclear industry for the permanent shut-down
of a nuclear power plant which usually occurs when the plant's license expires.)
The study resulted in a higher estimated cost of decommissioning, which
increased decommissioning expense (included in depreciation and amortization
expense) by $9 million annually.
Our 1995 and 1994 depreciation and amortization expense reflected the write-off
of expenditures associated with future generation facilities at our Perryman
site which will not be built. We discuss the write-off of expenditures at our
Perryman site further in Note 1 on page 44. The write-off of these costs
increased our 1995 depreciation and amortization expense by $14.2 million and
increased our 1994 expense by $15.7 million.
Taxes Other Than Income Taxes
In 1996, taxes (other than income taxes) were $9.6 million higher than in 1995
mostly due to three factors: plant additions made in 1995 increased our property
taxes about $7 million, higher 1996 revenues increased our gross receipts taxes
about $2 million, and higher labor costs increased our payroll taxes about $1
million.
In 1995, taxes (other than income taxes) were $5.4 million higher than in 1994
mostly due to higher property taxes resulting from more utility plant in
service.
Other Income and Expenses
Allowance for Funds Used During Construction (AFC)
AFC is an accounting procedure used to exclude the cost of capital from expense
and include it as part of the cost of utility plant construction. AFC is
calculated at a rate authorized by the Maryland Commission. We describe AFC
further in Note 1 on page 44.
In 1996 and 1995, we had lower AFC compared to prior years because we completed
several projects and started less new construction. In 1996, we also had lower
AFC because the Maryland Commission decreased the gas AFC rate in November 1995
from 9.40% to 9.04%. This meant we were not authorized to record as much gas AFC
in 1996 as we were in 1995 and 1994.
Net Other Income and Deductions
Net other income and deductions represent miscellaneous income and expenses
which are not directly related to operations.
In 1996, net other income and deductions increased $4.9 million compared to 1995
mostly because the Constellation Companies had lower deductions not directly
related to operations and BGE had about $2 million more of other interest and
finance charge income.
In 1995, net other income and deductions decreased $16.2 million compared to
1994 because we had about $12 million less of other interest and finance charge
income, and we had about $4 million lower income from the sale of receivables
(money customers owe to us) and property. We sell receivables to a financial
institution under agreements which are discussed in Note 12 on page 52.
Interest Charges
Interest charges represent the interest we paid on outstanding debt.
In 1996, we had $2.1 million lower interest charges compared to 1995 largely
because of lower interest rates. We would have had even lower interest charges
except we had more debt outstanding.
In 1995, we had $5.3 million higher interest charges compared to 1994 because we
had more debt outstanding and short-term interest rates were higher.
Income Taxes
In 1996 our income taxes decreased because we had lower taxable income from
utility operations. Our income taxes would have been even lower except that we
had higher taxable income from our diversified businesses.
In 1995, our income taxes increased because we had higher taxable income from
both our utility operations and our diversified businesses.
Environmental Matters
We are subject to increasingly stringent federal, state, and local laws and
regulations that work to improve or maintain the quality of the environment. If
certain substances were disposed of or released at any of our properties,
whether currently operating or not, these laws and regulations require us to
remove or remedy the effect on the environment. This includes Environmental
Protection Agency Superfund sites. You will find details of our environmental
matters in Note 12 on page 53 and in this Annual Report on Form 10-K under Item
1. Business - Environmental Matters. These details include financial
information. Some of the information is about costs that may be material.
Baltimore Gas and Electric Company and Subsidiaries
29
<PAGE>
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. Some of our diversified
businesses are related to our core utility business and others are not. Our
diversified businesses include:
(bullet) Constellation Holdings, Inc. and Subsidiaries, together known as the
Constellation Companies
(bullet) BGE Home Products & Services, Inc. and Subsidiary
(bullet) BGE Energy Projects & Services, Inc. and Subsidiaries
(bullet) Constellation Energy Source, Inc. (formerly named BNG, Inc.)
Diversified Business Earnings Per Share of Common Stock
1996 1995 1994
- --------------------------------------------------------------------------------
Constellation Companies $ .29 $ .18 $ .09
BGE Home Products & Services .02 .00 .03
BGE Energy Projects & Services .00 .00 -
Constellation Energy Source .00 .00 .00
-------------------------
Total diversified business
earnings per share $ .31 $ .18 $ .12
=========================
Our 1996 diversified business earnings increased $19.3 million, or $.13 per
share, from 1995. Our 1995 diversified business earnings increased $8.2 million,
or $.06 per share, from 1994. These increases mostly reflect higher earnings
from the Constellation Companies.
We discuss factors affecting the earnings of each diversified business
subsidiary below.
Constellation Companies' Operations
The Constellation Companies engage in the following:
(bullet) development, ownership, and operation of power generation projects,
(bullet) financial investments, and
(bullet) development, ownership, and management of real estate and
senior-living facilities.
Earnings per share from the Constellation Companies were:
1996 1995 1994
- --------------------------------------------------------------------------------
Power generation $ .18 $ .13 $ .10
Financial investments .14 .08 .03
Real estate development and
senior-living facilities (.02) (.02) (.03)
Other (.01) (.01) (.01)
-------------------------
Total Constellation Companies'
earnings per share $ .29 $ .18 $ .09
=========================
Power Generation
The Constellation Companies' power generation business develops, owns, and
operates power generation facilities.
In 1996, earnings increased from 1995 mostly due to our share of higher earnings
from energy projects and a $14.6 million after-tax gain on the sale by a
Constellation partnership of a power purchase agreement with Jersey Central
Power & Light Company back to that utility. Energy projects had higher earnings
for a variety of reasons--some ongoing (like improved efficiency due to
equipment or procedure changes) and some onetime (for example, losses incurred
in 1995--to shut-down certain operations at a plant--did not occur again in
1996).
These increases were offset by:
(bullet) a $7.0 million after-tax write-off of Constellation's investment in
two geothermal wholesale power generating projects,
(bullet) a $3.0 million after-tax write-off of development costs for a proposed
coal-fired power project that will not be built, and
(bullet) a $6.2 million after-tax write-off of a portion of an investment in a
solar power project, in which Constellation has a minority ownership
interest, expected to be restructured with the lender.
In 1995, earnings increased from 1994 mostly due to our share of higher earnings
from energy projects and a profit made on the sale of some operating and
maintenance contracts.
California Power Purchase Agreements
The Constellation Companies have $227 million invested in 16 projects that sell
electricity in California under power purchase agreements called "Interim
Standard Offer No. 4" agreements.
Under these agreements, the projects supply electricity to utility companies at:
(bullet) a fixed rate for capacity and energy the first 10 years of the
agreements, and
(bullet) 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.
From 1996 through 2000, the 10-year periods for fixed energy rates expire for
these 16 power generation projects and they begin supplying electricity at
variable rates. When this happens, the revenues at these projects are expected
to be lower than they are now. It is difficult to estimate how much lower the
revenues may be, but the Constellation Companies' earnings could be affected
significantly.
Eight projects begin supplying electricity at variable rates in 1997 and 1998.
This means the Constellation Companies could experience lower earnings from
those projects. However, the remaining projects, which will continue to supply
electricity at fixed rates, are expected to have higher revenues in 1997 and
1998. These higher revenues may offset the lower revenues from the variable-rate
projects during those years.
The California projects that make the highest revenues will begin supplying
electricity at variable rates in 1999 and 2000. As a result, we do not expect
the Constellation Companies to have significantly lower earnings due to the
switch from fixed to variable rates before 2000.
Baltimore Gas and Electric Company and Subsidiaries
30
<PAGE>
In the second quarter of 1996, Constellation determined that its investments in
two of these plants are not expected to be fully recoverable. Accordingly, as
mentioned earlier in this section, the Constellation Companies recorded a $7.0
million after-tax write-off of the investment in these plants.
Constellation is pursuing alternatives for some of these power generation
projects including:
(bullet) repowering the projects to reduce operating costs,
(bullet) changing fuels to reduce operating costs,
(bullet) renegotiating the power purchase agreements to improve the terms,
(bullet) restructuring financings to improve the financing terms, and
(bullet) selling its ownership interests in the projects.
We cannot predict the financial effects of the switch from fixed to variable
rates on the Constellation Companies or on BGE, but the effects could be
material.
International
Historically, Constellation's power generation projects have been in the United
States. Over the last two years, however, Constellation has sought projects in
Latin America. As of December 31, 1996, Constellation had invested about $17.1
million and committed another $6.5 million in power projects in Latin America.
In the future, Constellation's power generation business may be expanding
further in both domestic and international projects.
Financial Investments
Earnings from Constellation's portfolio of financial investments include:
(bullet) income from marketable securities,
(bullet) income from financial limited partnerships, and
(bullet) income from financial guaranty insurance companies.
In 1996, earnings were higher than in 1995 because of better earnings from
marketable securities and increased gains from financial limited partnerships.
In 1995, earnings were higher compared to 1994 due to: increased earnings from
marketable securities, increased gains from financial limited partnerships, and
higher earnings from financial guaranty insurance companies.
Real Estate Development and Senior-Living Facilities
Constellation's real estate development business includes:
(bullet) land under development,
(bullet) office buildings,
(bullet) retail projects,
(bullet) distribution facility projects,
(bullet) an entertainment, dining, and retail complex in Orlando, Florida,
(bullet) a mixed-use planned-unit development, and
(bullet) senior-living facilities.
Most of these projects are in the Baltimore-Washington corridor. The area has
had a surplus of available land and office space in recent years, during a time
of low economic growth and corporate downsizings. Our projects have been
economically hurt by these conditions. Earnings from real estate development and
senior-living facilities in 1996 and 1995 were essentially unchanged from prior
years.
Constellation's real estate portfolio has continued to incur carrying costs and
depreciation over the years. Additionally, the Constellation Companies have 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 from Constellation Holdings. Constellation Holdings obtained those funds
from the cash flow from other Constellation Companies and through additional
borrowing.
We will consider market demand, interest rates, the availability of financing,
and the strength of the economy in general when making decisions about our real
estate investments. We believe that until the economy shows sustained growth and
there is more demand for new development, our real estate values will not
improve much. If we were to sell our real estate projects in the current market,
we would have losses, 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. Management evaluates strategies
for all its businesses, including real estate, on an ongoing basis.* We
anticipate that competing demands for our financial resources, changes in the
utility industry, and the proposed merger with Potomac Electric Power Company,
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. Depending on market conditions in the future, we could also have
losses on any future sales.
It may be helpful for you to understand when we are required, by accounting
rules, to writedown the value of a real estate investment to market value. A
writedown 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
cash flow from the project is less than the investment in the project.
BGE Home Products & Services' Operations
BGE Home Products & Services engages in:
(bullet) sales and service of electric and gas appliances,
(bullet) home improvements, and
(bullet) sales and service of heating and air conditioning systems.
In 1996, earnings increased due to improved performance in the service and
installation business. In 1995, earnings decreased compared to 1994 largely due
to lower income from the sale of receivables during 1995. We sell receivables to
a financial institution under agreements which are discussed in Note 12 on page
52.
* In the first quarter of 1997, we wrote down the investment in one of our
projects to market value because we changed our intent about that project.
The write-down is described in detail in the front of this report under The
Constellation Companies--Power Generation, Real Estate, and Financial
Investments on page 15.
Baltimore Gas and Electric Company and Subsidiaries
31
<PAGE>
BGE Energy Projects & Services' Operations
BGE Energy Projects & Services provides a broad range of customized energy
services, including:
(bullet) power quality services,
(bullet) customer electrical system improvements,
(bullet) lighting and mechanical engineering and installation services,
(bullet) campus and multi-building energy systems,
(bullet) energy consulting and financial contracts,
(bullet) district energy systems through Comfort Link (a partnership with the
Poole and Kent Company), and
(bullet) private electric and gas distribution systems.
This subsidiary was formed in November 1995. It had no significant earnings in
1996 or 1995.
Constellation Energy Source's Operations
Constellation Energy Source (formerly named BNG, Inc.) engages in natural gas
brokering. This subsidiary had no significant earnings in 1996 or 1995.
- --------------------------------------------------------------------------------
Liquidity and Capital Resources
Overview
Our business requires a great deal of capital. Our actual capital requirements
for the years 1994 through 1996, along with estimated amounts for the years 1997
through 1999, are shown below.
<TABLE>
<CAPTION>
1994 1995 1996 1997 1998 1999
- ---------------------------------------------------------------------------------------------------------------------------
(In millions)
<S> <C>
Utility Business Capital Requirements:
Construction expenditures (excluding AFC)
Electric $345 $223 $219 $230 $216 $ 215
Gas 68 70 84 72 70 73
Common 42 51 46 33 39 37
-----------------------------------------------------
Total construction expenditures 455 344 349 335 325 325
AFC 34 22 10 7 7 7
Nuclear fuel (uranium purchases and processing charges) 42 46 47 49 50 50
Deferred energy conservation expenditures 41 46 31 24 19 18
Deferred nuclear expenditures 8 -- -- -- -- --
Retirement of long-term debt and redemption of preference stock 203 279 184 173 117 270
-----------------------------------------------------
Total utility business capital requirements 783 737 621 588 518 670
-----------------------------------------------------
Diversified Business Capital Requirements:
Investment requirements 51 118 118 214 180 205
Retirement of long-term debt 37 55 52 108 165 186
-----------------------------------------------------
Total diversified business capital requirements 88 173 170 322 345 391
-----------------------------------------------------
Total capital requirements $871 $910 $791 $910 $863 $1,061
=====================================================
</TABLE>
Capital Requirements of Our Utility Business
Capital requirements for our utility business do not include costs to complete
the pending merger with Potomac Electric Power Company. These costs, currently
estimated to be $150 million, are discussed in more detail in Note 12 on page
52.
We continuously review and change our construction program, so actual
expenditures may vary from the estimates for the years 1997 through 1999 in the
capital requirements chart. Additionally, actual capital requirements may be
different than the estimates for 1997 through 1999 because adjustments which may
result from the pending merger with Potomac Electric Power Company have not been
considered in those estimates.
Electric construction expenditures include:
(bullet) installation of a 5,000 kilowatt diesel generator which was placed in
service in 1996 at our Calvert Cliffs Nuclear Power Plant, and
(bullet) improvements to other generating plants and to our transmission and
distribution facilities.
Our projections of future electric construction expenditures do not include
costs to build more generating units.
Our utility operations provided about 96% in 1996, 100% in 1995, and 72% in
1994, of the cash needed to meet our capital requirements, excluding cash needed
to retire debt and redeem preferred and preference stock. In addition, in 1994,
the sale of some receivables provided $70 million in cash. This is discussed in
more detail in Note 12 on page 52.
Baltimore Gas and Electric Company and Subsidiaries
32
<PAGE>
During the three years from 1997 through 1999, we expect utility operations to
provide 115% of the cash needed to meet our capital requirements, excluding cash
needed to retire debt and redeem preference stock. This estimate does not
consider the pending merger with Potomac Electric Power Company.
When we cannot meet utility capital requirements internally, we sell debt and
equity securities. The amount of cash we need and market conditions determine
when and how much we sell. During the three years ended December 31, 1996, we
sold:
(bullet) $540 million of long-term debt,
(bullet) $60 million of preference stock, and
(bullet) $39 million of common stock.
Security Ratings
Independent credit-rating agencies rate our fixed-income securities. The ratings
indicate the agencies' assessment of our ability to pay interest, dividends, and
principal on these securities. These ratings affect how much it will cost us to
sell these securities. The better the rating, the cheaper it is for us to sell.
At the date of this report, our securities ratings were as follows:
Standard Moody's
& Poor's Investors Duff & Phelps
Rating Group Service Credit Rating Co.
- --------------------------------------------------------------------------------
Mortgage Bonds A+ A1 AA-
Unsecured Debt A A2 A+
Preference Stock A "a2" A
Capital Requirements of Our Diversified Businesses
In the past, capital requirements of our diversified businesses only included
the Constellation Companies because they had the only significant capital
requirements. From time to time, however, our other diversified businesses may
develop significant capital requirements. As that occurs, we will include the
capital requirements of those businesses in the capital requirements table on
page 32. As discussed below under "Investment Requirements," capital
requirements for Comfort Link are also included this year.
Our Constellation Companies and other diversified businesses expect to expand
their businesses. This will include our new power marketing business. It also
may include expansion in the energy, financial investments, real estate, and
senior-living facility businesses. Such expansion could mean more investments in
and acquisition of new projects. Our Constellation Companies and other
diversified businesses have met their capital requirements in the past through
borrowing, cash from their operations, and from time to time, loans or equity
contributions from BGE. Our Constellation Companies and other diversified
businesses plan to raise the cash needed to meet capital requirements in the
future through these same methods.
Investment Requirements
The investment requirements of our diversified businesses include:
(bullet) for the Constellation Companies, investments in financial limited
partnerships and funding for the development and acquisition of
projects, as well as loans made to project partnerships, and
(bullet) for BGE Energy Projects & Services, funding for construction of
district energy projects of Comfort Link.
Investment requirements for 1997 through 1999 include estimates of funding for
existing and new projects and for our new power marketing business. We
continuously review and modify those estimates. Actual investment
requirements could vary a great deal from the estimates on page 32 because
they would be subject to several variables, including:
(bullet) the type and number of projects selected for development,
(bullet) the effect of market conditions on those projects,
(bullet) opportunities for growth in the power marketing business,
(bullet) the ability to obtain financing, and
(bullet) the availability of cash from operations.
Debt and Liquidity
Our diversified businesses plan to meet capital requirements by refinancing debt
as it comes due, by additional borrowing, and with cash generated by the
businesses. This includes cash from operations, sale of assets, and earned tax
benefits. BGE Home Products & Services may also meet capital requirements
through sales of receivables as discussed in Note 12 on page 52.
If Constellation can get a reasonable value for its real estate, it could obtain
additional cash by selling real estate projects. For more information, see the
discussion of the real estate business and market on page 31. Constellation's
ability to sell or liquidate assets will depend on market conditions, and we
cannot give assurances that these sales or liquidations could be made.
In addition, Constellation has a $75 million revolving credit agreement and
Comfort Link has a $50 million revolving credit agreement to provide additional
cash for short-term financial needs.
Baltimore Gas and Electric Company and Subsidiaries
33
<PAGE>
Item 8. Financial Statements and Supplementary Data
Report of Independent Accountants
To the Shareholders of
Baltimore Gas and Electric Company
We have audited the accompanying consolidated balance sheets and statements of
capitalization of Baltimore Gas and Electric Company and Subsidiaries as of
December 31, 1996 and 1995, and the related consolidated statements of income,
cash flows, common shareholders' equity, and income taxes for each of the three
years in the period ended December 31, 1996, and the consolidated financial
statement schedule listed in Item 14(a)(1) and (2) 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, 1996 and 1995, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1996 in conformity with generally
accepted accounting principles. In addition, the consolidated financial
statement schedule referred to above, when considered in relation to the basic
consolidated 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
standards, the consolidated balance sheets and statements of capitalization at
December 31, 1994, 1993, and 1992, 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, 1993 (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 included in the Selected Financial Data for each of the five years in
the period ended December 31, 1996, appearing on page 23 is fairly stated in all
material respects in relation to the financial statements from which it has been
derived.
/s/ Coopers & Lybrand L.L.P.
_____________________________
COOPERS & LYBRAND L.L.P.
Baltimore, Maryland
January 17, 1997
34
<PAGE>
Consolidated Statements of Income
<TABLE>
<CAPTION>
Year Ended December 31, 1996 1995 1994
- ---------------------------------------------------------------------------------------------------------------------------
(In thousands, except per share amounts)
<S> <C>
Revenues
Electric $2,208,744 $2,229,774 $2,126,581
Gas 517,292 400,504 421,249
Diversified businesses 427,211 304,521 235,155
-------------------------------------------------
Total revenues 3,153,247 2,934,799 2,782,985
-------------------------------------------------
Expenses Other Than Interest and Income Taxes
Electric fuel and purchased energy 547,414 578,801 542,314
Disallowed replacement energy costs (see Note 12) 95,369 -- --
Gas purchased for resale 284,443 198,069 224,590
Operations 526,424 550,811 552,817
Maintenance 174,141 168,269 164,892
Diversified businesses - selling, general, and administrative 311,053 220,573 167,430
Depreciation and amortization 330,191 317,417 295,950
Taxes other than income taxes 214,747 205,167 199,733
-------------------------------------------------
Total expenses other than interest and income taxes 2,483,782 2,239,107 2,147,726
-------------------------------------------------
Income from Operations 669,465 695,692 635,259
-------------------------------------------------
Other Income
Allowance for equity funds used during construction 6,508 14,162 21,746
Equity in earnings of Safe Harbor Water Power Corporation 4,596 4,559 4,349
Net other income and (deductions) (4,974) (9,902) 6,270
-------------------------------------------------
Total other income 6,130 8,819 32,365
-------------------------------------------------
Income Before Interest and Income Taxes 675,595 704,511 667,624
-------------------------------------------------
Interest Expense
Interest charges 217,622 219,689 214,347
Capitalized interest (15,664) (15,050) (12,427)
Allowance for borrowed funds used during construction (3,520) (7,662) (11,766)
-------------------------------------------------
Net interest expense 198,438 196,977 190,154
-------------------------------------------------
Income Before Income Taxes 477,157 507,534 477,470
Income Taxes 166,333 169,527 153,853
-------------------------------------------------
Net Income 310,824 338,007 323,617
Preferred and Preference Stock Dividends 38,536 40,578 39,922
-------------------------------------------------
Earnings Applicable to Common Stock $ 272,288 $ 297,429 $ 283,695
=================================================
Average Shares of Common Stock Outstanding 147,560 147,527 147,100
Earnings Per Share of Common Stock $1.85 $2.02 $1.93
=================================================
</TABLE>
See Notes to Consolidated Financial Statements.
Baltimore Gas and Electric Company and Subsidiaries
35
<PAGE>
Consolidated Balance Sheets
<TABLE>
<CAPTION>
At December 31, 1996 1995
- ----------------------------------------------------------------------------------------------------------------
(In thousands)
<S> <C>
Assets
Current Assets
Cash and cash equivalents $ 66,708 $ 23,443
Accounts receivable (net of allowance for uncollectibles
of $18,028 and $16,390, respectively) 419,479 400,005
Trading securities 68,794 47,990
Fuel stocks 87,073 59,614
Materials and supplies 147,729 145,900
Prepaid taxes other than income taxes 64,763 60,508
Deferred income taxes 2,943 36,831
Other 44,709 31,487
--------------------------------
Total current assets 902,198 805,778
--------------------------------
Investments and Other Assets
Real estate projects 525,765 479,344
Power generation projects 379,130 358,629
Financial investments 204,443 205,841
Nuclear decommissioning trust fund 116,368 85,811
Net pension asset 84,510 60,077
Safe Harbor Water Power Corporation 34,363 34,327
Senior living facilities 36,415 16,045
Other 92,171 71,894
--------------------------------
Total investments and other assets 1,473,165 1,311,968
--------------------------------
Utility Plant
Plant in service
Electric 6,514,950 6,360,624
Gas 776,973 692,693
Common 523,485 522,450
--------------------------------
Total plant in service 7,815,408 7,575,767
Accumulated depreciation (2,613,355) (2,481,801)
--------------------------------
Net plant in service 5,202,053 5,093,966
Construction work in progress 221,857 247,296
Nuclear fuel (net of amortization) 132,937 130,782
Plant held for future use 25,503 25,552
--------------------------------
Net utility plant 5,582,350 5,497,596
--------------------------------
Deferred Charges
Regulatory assets (net) 512,279 637,915
Other 80,978 63,406
--------------------------------
Total deferred charges 593,257 701,321
--------------------------------
Total Assets $8,550,970 $8,316,663
================================
</TABLE>
See Notes to Consolidated Financial Statements.
Baltimore Gas and Electric Company and Subsidiaries
36
<PAGE>
Consolidated Balance Sheets
<TABLE>
<CAPTION>
At December 31, 1996 1995
- --------------------------------------------------------------------------------------------------------------------
(In thousands)
<S> <C>
Liabilities and Capitalization
Current Liabilities
Short-term borrowings $ 333,185 $ 279,305
Current portions of long-term debt and preference stock 280,772 146,969
Accounts payable 172,889 177,092
Customer deposits 27,993 26,857
Accrued taxes 6,473 8,244
Accrued interest 57,440 56,670
Dividends declared 66,950 67,198
Accrued vacation costs 34,351 33,403
Other 37,046 39,417
-----------------------------------
Total current liabilities 1,017,099 835,155
-----------------------------------
Deferred Credits and Other Liabilities
Deferred income taxes 1,300,174 1,311,530
Postretirement and postemployment benefits 169,253 148,594
Decommissioning of federal uranium enrichment facilities 38,599 43,695
Other 65,463 55,568
-----------------------------------
Total deferred credits and other liabilities 1,573,489 1,559,387
-----------------------------------
Capitalization
Long-term debt 2,758,769 2,598,254
Preferred stock -- 59,185
Redeemable preference stock 134,500 242,000
Preference stock not subject to mandatory redemption 210,000 210,000
Common shareholders' equity 2,857,113 2,812,682
-----------------------------------
Total capitalization 5,960,382 5,922,121
-----------------------------------
Commitments, Guarantees, and Contingencies - See Note 12
Total Liabilities and Capitalization $8,550,970 $8,316,663
===================================
</TABLE>
See Notes to Consolidated Financial Statements.
Baltimore Gas and Electric Company and Subsidiaries
37
<PAGE>
Consolidated Statements of Cash Flows
<TABLE>
<CAPTION>
Year Ended December 31, 1996 1995 1994
- ---------------------------------------------------------------------------------------------------------------------------
(In thousands)
<S> <C>
Cash Flows From Operating Activities
Net income $310,824 $338,007 $323,617
Adjustments to reconcile to net cash provided by operating activities
Depreciation and amortization 383,155 378,977 351,064
Deferred income taxes 26,009 103,494 79,278
Investment tax credit adjustments (7,655) (8,088) (8,192)
Deferred fuel costs 528 5,565 11,461
Deferred energy conservation revenues 28,500 1,283 18,769
Disallowed replacement energy costs 95,369 -- --
Accrued pension and postemployment benefits (13,792) (7,641) (41,113)
Allowance for equity funds used during construction (6,508) (14,162) (21,746)
Equity in earnings of affiliates and joint ventures (net) (48,305) (21,259) (20,225)
Changes in current assets other than sale of accounts receivable (88,035) (107,392) (10,536)
Changes in current liabilities, other than short-term borrowings (4,905) (7,293) (24,447)
Other 26,762 6,661 (5,699)
----------------------------------------------
Net cash provided by operating activities 701,947 668,152 652,231
----------------------------------------------
Cash Flows From Financing Activities
Proceeds from issuance of
Short-term borrowings (net) 53,880 215,605 63,700
Long-term debt 383,182 184,422 207,169
Preference stock -- 59,329 --
Common stock 3,729 318 33,869
Proceeds from sale of receivables 10,000 2,000 70,000
Reacquisition of long-term debt (158,551) (315,105) (240,853)
Reacquisition of preferred and preference stock (112,559) (73,000) (4,406)
Common stock dividends paid (233,109) (227,192) (220,152)
Preferred and preference stock dividends paid (37,050) (40,087) (39,950)
Other (1,172) 13 (437)
----------------------------------------------
Net cash used in financing activities (91,650) (193,697) (131,060)
----------------------------------------------
Cash Flows From Investing Activities
Utility construction expenditures (including AFC) (360,485) (366,037) (488,976)
Allowance for equity funds used during construction 6,508 14,162 21,746
Nuclear fuel expenditures (46,761) (46,330) (42,089)
Deferred nuclear expenditures -- -- (8,393)
Deferred energy conservation expenditures (31,383) (45,503) (40,440)
Contributions to nuclear decommissioning trust fund (25,483) (9,780) (9,780)
Purchases of marketable equity securities (32,664) (18,447) (52,099)
Sales of marketable equity securities 39,657 49,788 40,585
Other financial investments 7,068 9,423 2,469
Real estate projects (55,344) (15,599) 14,926
Power generation systems (5,332) (34,408) (1,116)
Other (62,813) (26,871) (3,650)
----------------------------------------------
Net cash used in investing activities (567,032) (489,602) (566,817)
----------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 43,265 (15,147) (45,646)
Cash and Cash Equivalents at Beginning of Year 23,443 38,590 84,236
----------------------------------------------
Cash and Cash Equivalents at End of Year $ 66,708 $ 23,443 $ 38,590
==============================================
Other Cash Flow Information
Cash paid during the year for:
Interest (net of amounts capitalized) $182,431 $195,308 $184,441
Income taxes $160,132 $ 99,623 $ 83,143
</TABLE>
See Notes to Consolidated Financial Statements.
Certain prior-year amounts have been reclassified to conform with the current
year's presentation.
Baltimore Gas and Electric Company and Subsidiaries
38
<PAGE>
Consolidated Statements
of Common Shareholders' Equity
<TABLE>
<CAPTION>
Unrealized
Gain (Loss)
on Available Pension
Common Stock Retained For Sale Liability Total
Years Ended December 31, 1996, 1995, and 1994 Shares Amount Earnings Securities Adjustment Amount
- ---------------------------------------------------------------------------------------------------------------------------------
(In thousands)
<S> <C>
Balance at December 31, 1993 146,034 $1,391,464 $1,251,140 $ -- $(22,093) $2,620,511
Net income 323,617 323,617
Dividends declared
Preferred and preference stock (39,922) (39,922)
Common stock ($1.51 per share) (222,180) (222,180)
Common stock issued 1,493 33,869 33,869
Other 45 45
Net unrealized loss on securities (5,609) (5,609)
Deferred taxes on net unrealized loss on securities 1,963 1,963
Pension liability adjustment 8,573 8,573
Deferred taxes on pension liability adjustment (3,001) (3,001)
------------------------------------------------------------------------
Balance at December 31, 1994 147,527 1,425,378 1,312,655 (3,646) (16,521) 2,717,866
Net income 338,007 338,007
Dividends declared
Preferred and preference stock (40,578) (40,578)
Common stock ($1.55 per share) (228,667) (228,667)
Common stock issued 318 318
Other 109 109
Net unrealized gain on securities 14,010 14,010
Deferred taxes on net unrealized gain on securities (4,904) (4,904)
Pension liability adjustment 25,417 25,417
Deferred taxes on pension liability adjustment (8,896) (8,896)
------------------------------------------------------------------------
Balance at December 31, 1995 147,527 1,425,805 1,381,417 5,460 -- 2,812,682
Net income 310,824 310,824
Dividends declared
Preferred and preference stock (38,536) (38,536)
Common stock ($1.59 per share) (234,640) (234,640)
Common stock issued 140 3,729 3,729
Other 408 408
Net unrealized gain on securities 4,071 4,071
Deferred taxes on net unrealized gain on securities (1,425) (1,425)
------------------------------------------------------------------------
Balance at December 31, 1996 147,667 $1,429,942 $1,419,065 $8,106 $ -- $2,857,113
========================================================================
</TABLE>
See Notes to Consolidated Financial Statements.
Baltimore Gas and Electric Company and Subsidiaries
39
<PAGE>
Consolidated Statements of Capitalization
<TABLE>
<CAPTION>
At December 31, 1996 1995
- ---------------------------------------------------------------------------------------------------------------------------
(In thousands)
<S> <C>
Long-Term Debt
First Refunding Mortgage Bonds of BGE
5-1/8% Series, due April 15, 1996 $ -- $ 26,187
6-1/8% Series, due August 1, 1997 24,935 24,935
Floating rate series, due April 15, 1999 125,000 125,000
8.40% Series, due October 15, 1999 91,137 91,200
5-1/2% Series, due July 15, 2000 124,990 125,000
8-3/8% Series, due August 15, 2001 122,377 122,427
7-1/8% Series, due January 1, 2002 22,737 39,698
7-1/4% Series, due July 1, 2002 124,484 124,609
5-1/2% Installment Series, due July 15, 2002 10,440 11,045
6-1/2% Series, due February 15, 2003 124,822 124,882
6-1/8% Series, due July 1, 2003 124,855 124,925
5-1/2% Series, due April 15, 2004 124,995 124,995
Remarketed floating rate series, due September 1, 2006 125,000 --
7-1/2% Series, due January 15, 2007 123,652 123,667
6-5/8% Series, due March 15, 2008 124,960 124,985
7-1/2% Series, due March 1, 2023 124,973 124,973
7-1/2% Series, due April 15, 2023 100,000 100,000
----------------------------------
Total First Refunding Mortgage Bonds of BGE 1,619,357 1,538,528
----------------------------------
Other long-term debt of BGE
Term bank loan due March 29, 2001 50,000 50,000
Medium-term notes, Series A -- 10,500
Medium-term notes, Series B 100,000 100,000
Medium-term notes, Series C 183,000 200,000
Medium-term notes, Series D 138,000 28,000
Pollution control loan, due July 1, 2011 36,000 36,000
Port facilities loan, due June 1, 2013 48,000 48,000
Adjustable rate pollution control loan, due July 1, 2014 20,000 20,000
5.55% Pollution control revenue refunding loan, due July 15, 2014 47,000 47,000
Economic development loan, due December 1, 2018 35,000 35,000
6.00% Pollution control revenue refunding loan, due April 1, 2024 75,000 75,000
----------------------------------
Total other long-term debt of BGE 732,000 649,500
----------------------------------
Long-term debt of Constellation Companies
Revolving credit agreement
Variable rates based on LIBOR, due December 9, 1999 65,000 1,000
Mortgage and construction loans and other collateralized notes
8.00%, due July 31, 2001 141 --
8.00%, due October 30, 2003 1,500 --
Variable rates, due through 2009 128,571 110,018
7.50%, due October 9, 2005 9,846 9,989
7.357%, due March 15, 2009 5,763 5,896
9.65%, due February 1, 2028 9,746 --
Unsecured notes 387,160 420,000
----------------------------------
Total long-term debt of Constellation Companies 607,727 546,903
----------------------------------
Long-term debt of other diversified businesses
Loans under revolving credit agreements 12,000 --
----------------------------------
Unamortized discount and premium (14,543) (15,708)
Current portion of long-term debt (197,772) (120,969)
----------------------------------
Total long-term debt $2,758,769 $2,598,254
----------------------------------
</TABLE>
continued on page 41
See Notes to Consolidated Financial Statements.
Baltimore Gas and Electric Company and Subsidiaries
40
<PAGE>
Consolidated Statements of Capitalization
<TABLE>
<CAPTION>
At December 31, 1996 1995
- ---------------------------------------------------------------------------------------------------------------------------
(In thousands)
<S> <C>
Preferred Stock
Cumulative, $100 par value, 1,000,000 shares authorized
Series B, 4 1/2%, 222,921 shares redeemed at $110 per share on May 28, 1996 $ -- $ 22,292
Series C, 4%, 68,928 shares redeemed at $105 per share on May 28, 1996 -- 6,893
Series D, 5.40%, 300,000 shares redeemed at $101 per share on May 28, 1996 -- 30,000
----------------------------------
Total preferred stock -- 59,185
----------------------------------
Preference Stock
Cumulative, $100 par value, 6,500,000 shares authorized
Redeemable preference stock
7.50%, 1986 Series, 395,000 and 425,000 shares outstanding. Callable
at $102.50 per share prior to October 1, 2001 and at lesser amounts thereafter 39,500 42,500
6.75%, 1987 Series, 440,000 and 455,000 shares outstanding. Callable at
$104.50 per share prior to April 1, 1997 and at lesser amounts thereafter 44,000 45,500
7.80%, 1989 Series, 500,000 shares outstanding 50,000 50,000
8.25%, 1989 Series, 100,000 and 300,000 shares outstanding 10,000 30,000
8.625%, 1990 Series, 390,000 and 650,000 shares outstanding 39,000 65,000
7.85%, 1991 Series, 350,000 shares outstanding 35,000 35,000
Current portion of redeemable preference stock (83,000) (26,000)
----------------------------------
Total redeemable preference stock 134,500 242,000
----------------------------------
Preference stock not subject to mandatory redemption
7.78%, 1973 Series, 200,000 shares outstanding, callable at $101 per share 20,000 20,000
7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003 40,000 40,000
6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003 50,000 50,000
6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004 40,000 40,000
6.99%, 1995 Series, 600,000 shares outstanding, not callable prior to October 1, 2005 60,000 60,000
----------------------------------
Total preference stock not subject to mandatory redemption 210,000 210,000
----------------------------------
Common Shareholders' Equity
Common stock without par value, 175,000,000 shares authorized; 147,667,114 and
147,527,114 shares issued and outstanding at December 31, 1996 and 1995,
respectively. (At December 31, 1996, 166,893 shares were reserved for the
Employee Savings Plan and 3,277,656 shares were reserved for the Dividend
Reinvestment and Stock Purchase Plan.) 1,429,942 1,425,805
Retained earnings 1,419,065 1,381,417
Unrealized gain (loss) on available-for-sale securities 8,106 5,460
----------------------------------
Total common shareholders' equity 2,857,113 2,812,682
----------------------------------
Total Capitalization $5,960,382 $5,922,121
==================================
</TABLE>
See Notes to Consolidated Financial Statements.
Baltimore Gas and Electric Company and Subsidiaries
41
<PAGE>
Consolidated Statements of Income Taxes
<TABLE>
<CAPTION>
Year Ended December 31, 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------------------------
(Dollar amounts in thousands)
<S> <C>
Income Taxes
Current $147,979 $ 74,121 $ 82,767
-------------------------------------------------
Deferred
Change in tax effect of temporary differences 22,516 118,300 88,896
Change in income taxes recoverable through future rates 4,918 (1,006) (8,580)
Deferred taxes credited (charged) to shareholders' equity (1,425) (13,800) (1,038)
-------------------------------------------------
Deferred taxes charged to expense 26,009 103,494 79,278
Investment tax credit adjustments (7,655) (8,088) (8,192)
-------------------------------------------------
Income taxes per Consolidated Statements of Income $166,333 $169,527 $153,853
=================================================
Reconciliation of Income Taxes Computed at Statutory
Federal Rate to Total Income Taxes
Income before income taxes $477,157 $507,534 $477,470
Statutory federal income tax rate 35% 35% 35%
-------------------------------------------------
Income taxes computed at statutory federal rate 167,005 177,637 167,115
Increases (decreases) in income taxes due to
Depreciation differences not normalized on regulated activities 12,669 10,953 9,791
Allowance for equity funds used during construction (2,278) (4,957) (7,611)
Amortization of deferred investment tax credits (7,655) (8,088) (8,164)
Tax credits flowed through to income (520) (521) (1,754)
Amortization of deferred tax rate differential on regulated activities (1,958) (2,013) (1,885)
Other (930) (3,484) (3,639)
-------------------------------------------------
Total income taxes $166,333 $169,527 $153,853
=================================================
Effective federal income tax rate 34.9% 33.4% 32.2%
</TABLE>
<TABLE>
<CAPTION>
At December 31, 1996 1995
- -------------------------------------------------------------------------------------------------------------------
(Dollar amounts in thousands)
<S> <C>
Deferred Income Taxes
Deferred tax liabilities
Accelerated depreciation $ 920,631 $ 878,470
Allowance for funds used during construction 209,183 210,928
Income taxes recoverable through future rates 92,584 94,305
Deferred termination and postemployment costs 45,624 49,591
Deferred fuel costs 7,957 39,559
Leveraged leases 27,581 29,842
Percentage repair allowance 38,354 38,295
Energy conservation expenditures 26,622 28,121
Other 175,587 151,231
----------------------------------
Total deferred tax liabilities 1,544,123 1,520,342
----------------------------------
Deferred tax assets
Alternative minimum tax -- 32,626
Accrued pension and postemployment benefit costs 40,570 31,707
Deferred investment tax credits 46,889 49,512
Capitalized interest and overhead 42,509 39,439
Contributions in aid of construction 35,710 34,404
Nuclear decommissioning liability 18,750 16,708
Other 62,464 41,247
----------------------------------
Total deferred tax assets 246,892 245,643
----------------------------------
Deferred tax liability, net $1,297,231 $1,274,699
==================================
</TABLE>
See Notes to Consolidated Financial Statements.
Baltimore Gas and Electric Company and Subsidiaries
42
<PAGE>
Notes to Consolidated Financial Statements
Note 1. Significant Accounting Policies
Nature of the Business
Baltimore Gas and Electric Company (BGE) and Subsidiaries (collectively, the
Company) is primarily an electric and gas utility serving a territory which
encompasses Baltimore City and all or part of ten Central Maryland counties. The
Company is also engaged in diversified businesses as described further in Note
3.
Principles of Consolidation
The consolidated financial statements include the accounts of BGE and all
subsidiaries in which BGE owns directly or indirectly a majority of the voting
stock. Intercompany balances and transactions are eliminated in consolidation.
Under this policy, the accounts of Constellation Holdings, Inc. (CHI) and
Subsidiaries (collectively, the Constellation Companies), BGE Home Products &
Services, Inc. and Subsidiary (collectively, HP&S), BGE Energy Projects &
Services, Inc. and Subsidiaries (collectively, EP&S), and Constellation Energy
Source, Inc. (formerly named BNG, Inc.) are consolidated in the financial
statements, and Safe Harbor Water Power Corporation is reported under the equity
method. Corporate joint ventures, partnerships, and affiliated companies (which
include power generation projects) in which a 20% to 50% voting interest is held
are accounted for under the equity method, unless control is evident, in which
case the entity is consolidated. Investments in which less than a 20% voting
interest is held are accounted for under the cost method, unless significant
influence is exercised over the entity, in which case the investment is
accounted for under the equity method.
Regulation of Utility Operations
BGE's utility operations are subject to regulation by the Mary-land Public
Service Commission (Maryland Commission). The accounting policies and practices
used in the determination of service rates are also generally used for financial
reporting purposes in accordance with generally accepted accounting principles
for regulated industries. See Note 5.
Utility Revenues
BGE recognizes utility revenues as service is rendered to customers.
Fuel and Purchased Energy Costs
The cost of fuel used in generating electricity, net of revenues from
interchange sales, is recovered through a zero-based electric fuel rate subject
to approval by the Maryland Commission. The difference between actual fuel costs
and fuel revenues is deferred on the Consolidated Balance Sheets to be recovered
from or refunded to customers in future periods. The electric fuel rate formula
is based upon the latest twenty-four-month generation mix and the latest
three-month average fuel cost for each generating unit. The fuel rate does not
change unless the calculated rate is more than 5% above or below the rate then
in effect.
During 1989 through 1991 BGE experienced extended outages at its Calvert Cliffs
Nuclear Power Plant. The replacement energy costs associated with these outages
are estimated to be $458 million. The extended outages have been the subject of
ongoing fuel rate proceedings before the Maryland Commission for several years
(see Note 12).
In December 1996, BGE entered into a settlement agreement with the Maryland
People's Counsel and the Maryland Commission Staff proposing that customers will
not fund a total of $118 million of electric replacement energy costs associated
with these extended outages. BGE recorded a reserve for $35 million of these
costs in 1990. In 1996, BGE increased the reserve by $83 million and wrote off
$5.6 million of accrued carrying charges related to the deferred fuel balances.
These increases in the reserve reduced 1996 after-tax earnings by $57.6
million, or 39 cents per share. In addition, the Maryland Commission issued
a rate order in May 1996 disallowing certain fuel costs which were previously
deferred by BGE. Accordingly, BGE wrote-off the deferred fuel costs in 1996.
The write-off of these costs reduced after-tax earnings by $4.5 million,
or 3 cents per share.
Prior to October 1996, the cost of gas sold was recovered through gas adjustment
clauses subject to approval by the Maryland Commission. Under these clauses, the
difference between actual fuel costs and fuel revenues is deferred on the
balance sheet and recovered from or refunded to customers in future periods.
Effective October 1996, the Maryland Commission approved a modification of these
clauses to provide a Market Based Rates (MBR) incentive mechanism. Under the MBR
mechanism, differences between a market index and BGE's actual cost of gas are
shared equally between BGE's customers and shareholders.
Risk Management
Beginning in 1996, BGE engages in commodity hedging activities to minimize the
risk of market fluctuations associated with the price of gas under the MBR
mechanism. The objective of hedging is to manage BGE's price risk under the MBR
mechanism. Under internal guidelines, speculative positions are prohibited.
BGE enters into basis swap agreements which help minimize commodity price risk
by fixing the basis or differential that exists between a delivery location
index and the commodity futures prices. Net amounts receivable or payable under
the swaps are deferred and recognized as a component of gas costs when realized.
At December 31, 1996, there were unsettled swap agreements representing a
notional quantity of 12.3 million decatherms of natural gas purchases through
March 1997.
Income Taxes
The deferred tax liability represents the tax effect of temporary differences
between the financial-statement and tax bases of assets and liabilities. It is
measured using presently enacted tax rates. The portion of BGE's deferred tax
liability applicable to utility operations which has not been reflected in
current service rates represents income taxes recoverable through future rates.
That portion has been recorded as a regulatory asset on the Consolidated Balance
Sheets. Deferred income tax expense represents the net change in the deferred
tax liability and regulatory asset during the year, exclusive of amounts charged
or credited to common shareholders' equity.
Current tax expense consists solely of regular tax less applicable tax credits.
In certain prior years, tax expense included an alternative minimum tax (AMT)
that can be carried forward indefinitely as tax credits to future years in which
the regular tax liability exceeds the AMT liability. Current income tax for the
years ended December 31, 1996 and 1995 reflect full utilization of AMT credits
carried forward of $30 million and $40 million, respectively. The deferred
income taxes provided in earlier years on the AMT liability were reversed as the
credits were utilized.
The investment tax credit (ITC) associated with BGE's regulated utility
operations has been deferred on the Consolidated Balance Sheets (see Note 5) and
is amortized to income ratably over the lives of the subject property. ITC and
other tax credits associated with nonregulated diversified businesses other than
leveraged leases are flowed through to income.
BGE's utility revenue from system sales is subject to the Maryland public
service company franchise tax in lieu of a state income tax. The franchise tax
is included in taxes other than income taxes in the Consolidated Statements of
Income.
Baltimore Gas and Electric Company and Subsidiaries
43
<PAGE>
Inventory Valuation
Fuel stocks and materials and supplies are generally stated at average cost.
Impairment of Long-Lived Assets
Long-lived assets subject to the requirements of Statement of Financial
Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to Be Disposed Of, are evaluated for impairment
through a review of undiscounted expected future cash flows. If the sum of the
undiscounted expected future cash flows is less than the carrying amount of the
asset, an impairment loss is recognized.
Real Estate Projects
Real estate projects consist of the Constellation Companies' investments in
rental and operating properties and properties under development. Rental and
operating properties are held for investment. Properties under development are
held for future development and subsequent sale. Costs incurred in the
acquisition and active development of such properties are capitalized. Rental
and operating properties and properties under development are stated at cost
unless the amount invested exceeds the amounts expected to be recovered through
operations and sales. In these cases, the projects are written down to the
amount estimated to be recoverable.
Investments and Other Assets
Investments in debt and equity securities subject to the requirements of
Statement of Financial Accounting Standards No. 115, Accounting for Certain
Investments in Debt and Equity Securities, are reported at fair value. Certain
of Constellation Companies' marketable equity securities and financial
partnerships are classified as trading securities. Unrealized gains and losses
on these securities are included in diversified businesses revenues. The
investments comprising the nuclear decommissioning trust fund and certain
marketable equity securities of CHI are classified as available-for-sale.
Unrealized gains and losses on these securities, as well as CHI's portion of
unrealized gains and losses on securities of equity-method investees, are
recorded in shareholders' equity. The Company utilizes specific identification
to determine the cost of these securities in computing realized gains or losses.
Utility Plant, Depreciation and Amortization, and Decommissioning
Utility plant is stated at original cost, which includes material, labor, and,
where applicable, construction overhead costs and an allowance for funds used
during construction. Additions to utility plant and replacements of units of
property are capitalized to utility plant accounts. Utility plant retired or
otherwise disposed of is charged to accumulated depreciation. Maintenance and
repairs of property and replacements of items of property determined to be less
than a unit of property are charged to maintenance expense.
Depreciation is generally computed using composite straight-line rates applied
to the average investment in classes of depreciable property. Vehicles are
depreciated based on their estimated useful lives. As a result of the Maryland
Commission's November 1995 gas rate Order, BGE revised its gas utility plant
depreciation rates to reflect the results of a detailed depreciation
study. The revised rates resulted in an increase in depreciation accruals of
approximately $2.4 million annually.
Depreciation expense for 1995 and 1994 includes the write-off of certain costs
at BGE's Perryman site. Initially, BGE had planned to build two combined cycle
generating units at its Perryman site with each unit consisting of two
combustion turbines. However, due to significant changes in the environment in
which utilities operate, BGE decided in 1994 not to construct the second
combined cycle generating unit and wrote off the construction work in progress
costs associated with that unit. This write-off reduced after-tax earnings
during 1994 by $11.0 million or 7 cents per share. As a result of the Maryland
Commission's August 1995 Order requiring all new generation capacity needs to
be competitively bid and BGE's September 1995 announcement that it will merge
with Potomac Electric Power Company, BGE determined that it will not build
the second combustion turbine for the first combined cycle unit. Therefore,
during the third quarter of 1995, BGE wrote off the remaining construction work
in progress costs associated with the first combined cycle unit. This write-off
reduced after-tax earnings during 1995 by $9.7 million, or 7 cents per share.
The construction of the first 140-megawatt combustion turbine at Perryman
was completed, and the unit was placed in service, during June 1995.
BGE owns an undivided interest in the Keystone and Conemaugh electric generating
plants located in western Pennsylvania, as well as in the transmission line
which transports the plants' output to the joint owners' service territories.
BGE's ownership interest in these plants is 20.99% and 10.56%, respectively, and
represents a net investment of $153 million and $150 million as of December 31,
1996 and 1995, respectively. Financing and accounting for these properties are
the same as for wholly owned utility plant.
Nuclear fuel expenditures are amortized as a component of actual fuel costs
based on the energy produced over the life of the fuel. Fees for the future
disposal of spent nuclear fuel are paid quarterly to the Department of Energy
and are accrued based on the kilowatt-hours of electricity sold. Nuclear fuel
expenses are subject to recovery through the electric fuel rate.
Nuclear decommissioning costs are accrued by and recovered through a sinking
fund methodology. In a 1995 order, the Maryland Commission authorized BGE to
record decommissioning expense based on a facility-specific cost estimate in
order to accumulate a decommissioning reserve of $521 million in 1993 dollars by
the end of Calvert Cliffs' service life in 2016, adjusted to reflect expected
inflation, to decommission the radioactive portion of the plant. The total
decommissioning reserve of $163.8 million and $136.7 million at December 31,
1996 and 1995, respectively, is included in accumulated depreciation in the
Consolidated Balance Sheets.
In accordance with Nuclear Regulatory Commission (NRC) regulations, BGE has
established an external decommissioning trust to which a portion of accrued
decommissioning costs have been contributed. 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. BGE is using the
facility-specific cost estimate for funding these costs and providing the
requisite financial assurance.
Allowance for Funds Used During Construction and Capitalized Interest
The allowance for funds used during construction (AFC) is an accounting
procedure which capitalizes the cost of funds used to finance utility
construction projects as part of utility plant on the Consolidated Balance
Sheets, crediting the cost as a noncash item on the Consolidated Statements of
Income. The cost of borrowed and equity funds is segregated between interest
expense and other income, respectively. BGE recovers the capitalized AFC and a
return thereon after the related utility plant is placed in service and included
in depreciable assets and rate base.
Prior to November 20, 1995, the Company accrued AFC at a pre-tax rate of 9.40%.
Effective November 20, 1995, a rate order of the Maryland Commission reduced the
pre-tax gas-plant and common-plant AFC rates to 9.04% and 9.36%, respectively.
AFC is compounded annually.
The Constellation Companies capitalize interest on qualifying real estate and
power generation development projects.
Baltimore Gas and Electric Company and Subsidiaries
44
<PAGE>
Long-Term Debt
The discount or premium and expense of issuance associated with long-term debt
are deferred and amortized over the original lives of the respective debt
issues. Gains and losses on the reacquisition of debt are amortized over the
remaining original lives of the issuances.
Cash Flows
For the purpose of reporting cash flows, highly liquid investments purchased
with a maturity of three months or less are considered to be cash equivalents.
Use of Accounting Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period. These
estimates involve judgments with respect to, among other things, various future
economic factors which are difficult to predict and are beyond the control of
the Company. Therefore, actual amounts could differ from these estimates.
Accounting Standards Issued
The Financial Accounting Standards Board has issued Statement of Financial
Accounting Standards No. 125, regarding accounting for transfers and servicing
of financial assets and extinguishments of liabilities, effective January 1,
1997. The American Institute of Certified Public Accountants has issued
Statement of Position No. 96-1, regarding accounting for environmental
remediation liabilities, effective January 1, 1997. Adoption of these statements
is not expected to have a material impact on the Company's financial statements.
- --------------------------------------------------------------------------------
Note 2. Segment Information
<TABLE>
<CAPTION>
Construction Identifiable
Nonaffiliated Affiliated Total Income from Depreciation/ Expenditures Assets at
Revenues Revenues Revenues Operations Amortization (Including AFC) December 31
- ---------------------------------------------------------------------------------------------------------------------------------
(In thousands)
<S> <C>
1996
Electric $2,208,744 $ 283 $2,209,027 $497,986 $279,345 $262,542 $6,226,291
Gas 517,292 -- 517,292 68,848 37,790 97,943 810,084
Diversified businesses 427,211 6,782 433,993 102,631 13,056 -- 1,400,553
Other identifiable assets -- -- -- -- -- -- 114,042
Intercompany eliminations -- (7,065) (7,065) -- -- -- --
------------------------------------ -------- -------- -------- ----------
Total $3,153,247 $ -- $3,153,247 $669,465 $330,191 $360,485 $8,550,970
==================================== ======== ======== ======== ==========
1995
Electric $2,229,774 $ 1,337 $2,231,111 $574,299 $276,285 $288,509 $6,195,722
Gas 400,504 -- 400,504 48,104 29,637 77,528 748,462
Diversified businesses 304,521 6,609 311,130 73,289 11,495 -- 1,266,049
Other identifiable assets -- -- -- -- -- -- 106,430
Intercompany eliminations -- (7,946) (7,946) -- -- -- --
------------------------------------ -------- -------- -------- ----------
Total $2,934,799 $ -- $2,934,799 $695,692 $317,417 $366,037 $8,316,663
==================================== ======== ======== ======== ==========
1994
Electric $2,126,581 $ 840 $2,127,421 $539,739 $252,273 $412,885 $5,981,634
Gas 421,249 -- 421,249 27,801 32,478 76,091 726,759
Diversified businesses 235,155 8,245 243,400 67,719 11,199 -- 1,200,551
Other identifiable assets -- -- -- -- -- -- 128,558
Intercompany eliminations -- (9,085) (9,085) -- -- -- --
------------------------------------ -------- -------- -------- ----------
Total $2,782,985 $ -- $2,782,985 $635,259 $295,950 $488,976 $8,037,502
==================================== ======== ======== ======== ==========
</TABLE>
- --------------------------------------------------------------------------------
Note 3. Subsidiary Information
Diversified businesses consist of the operations of the Constellation Companies,
HP&S, EP&S, and Constellation Energy Source, Inc. (formerly named BNG, Inc.).
The Constellation Companies include Constellation Holdings, Inc., a wholly owned
subsidiary which holds all of the stock of three other subsidiaries,
Constellation Power, Inc. (formerly named Constellation Energy, Inc.),
Constellation Investments, Inc., and Constellation Real Estate Group, Inc. These
companies are engaged in development, ownership, and operation of power
generation projects; financial investments; and development, ownership, and
management of real estate and senior-living facilities, respectively.
HP&S is a wholly owned subsidiary which engages predominantly in the sales and
service of electric and gas appliances, home improvements, and sales and service
of heating and air conditioning systems, primarily in Central Maryland.
EP&S is a wholly owned subsidiary which provides a broad range of customized
energy services. These energy services include: power quality services, customer
electrical system improvements, lighting and mechanical engineering and
installation services, campus and multi-building energy systems, energy
consulting and financial contracts, district energy systems through Comfort
Link (a partnership with the Poole and Kent Company), and, beginning in late
1996, private electric and gas distribution systems.
Constellation Energy Source, Inc. (formerly named BNG, Inc.) is a wholly owned
subsidiary which engages in natural gas brokering.
BGE's investment in Safe Harbor Water Power Corporation, a producer of
hydroelectric power, represents 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 following is condensed financial information for the Constellation
Companies. The condensed financial information does not reflect the elimination
of intercompany balances or transactions which are eliminated in the Company's
consolidated financial statements.
Baltimore Gas and Electric Company and Subsidiaries
45
<PAGE>
The 1996 operating results reflect a $14.6 million after-tax gain on the sale by
a Constellation partnership of a power purchase agreement with Jersey Central
Power & Light Company back to that utility. This gain was offset by a $7.0
million after-tax write-off of the investment in two geothermal wholesale power
generating projects, a $3.0 million after-tax write-off of development costs of
a proposed coal-fired power project that will not be built, and a $6.2 million
after-tax write-off of a portion of an investment in a solar power project in
which the Constellation Companies have a minority ownership interest and which
is expected to be restructured with the lender.
<TABLE>
<CAPTION>
1996 1995 1994
- --------------------------------------------------------------------------------------------------------------------------
(In thousands, except per share amounts)
<S> <C>
Income Statements
Revenues
Real estate projects $ 80,793 $ 108,414 $ 106,915
Power generation systems 93,134 57,734 41,301
Financial investments 38,916 25,201 12,126
---------------------------------------------------
Total revenues 212,843 191,349 160,342
Expenses other than interest and income taxes 113,247 114,479 107,267
---------------------------------------------------
Income from operations 99,596 76,870 53,075
Minority interest (355) (2,348) --
Interest expense (44,991) (46,673) (45,782)
Capitalized interest 14,645 13,582 10,776
Income tax benefit (expense) (26,578) (14,355) (4,305)
---------------------------------------------------
Net income $ 42,317 $ 27,076 $ 13,764
===================================================
Contribution to the Company's earnings per share of common stock $ .29 $ .18 $ .09
===================================================
Balance Sheets
Current assets $ 115,689 $ 98,526 $ 92,814
Noncurrent assets 1,189,726 1,102,528 1,055,056
---------------------------------------------------
Total assets $1,305,415 $1,201,054 $1,147,870
---------------------------------------------------
Current liabilities $ 134,025 $ 70,393 $ 70,670
Noncurrent liabilities 775,237 778,505 758,626
Shareholder's equity 396,153 352,156 318,574
---------------------------------------------------
Total liabilities and shareholder's equity $1,305,415 $1,201,054 $1,147,870
===================================================
</TABLE>
- --------------------------------------------------------------------------------
Note 4. Real Estate Projects and Financial Investments
Real Estate Projects
Real estate projects consist of the following investments held by the
Constellation Companies:
At December 31, 1996 1995
- -----------------------------------------------------------
(In thousands)
Properties under development $286,200 $270,678
Rental and operating properties
(net of accumulated
depreciation) 237,725 207,666
Other real estate ventures 1,840 1,000
-----------------------
Total real estate projects $525,765 $479,344
=======================
Financial Investments
Financial investments consist of the following investments held by the
Constellation Companies:
At December 31, 1996 1995
- ---------------------------------------------------------
(In thousands)
Insurance companies $ 76,822 $ 77,792
Marketable equity securities 46,231 41,475
Financial limited partnerships 48,115 51,023
Leveraged leases 33,275 35,551
-----------------------
Total financial investments $204,443 $205,841
=======================
Available-For-Sale Investments
The Constellation Companies' marketable equity securities shown above and BGE's
investments comprising the nuclear decommissioning trust fund are classified as
available-for-sale. The fair values, gross unrealized gains and losses, and
amortized cost bases for available-for-sale securities, exclusive of $1.9
million of unrealized net gains on securities of equity-method investees, are as
follows:
Amortized Unrealized Unrealized Fair
At December 31, 1996 Cost Basis Gains Losses Value
- -------------------------------------------------------------------
(In thousands)
Marketable equity $ 39,363 $6,918 $ (50) $ 46,231
securities
U.S. government
agency 18,167 263 -- 18,430
State municipal
bonds 73,571 2,202 (125) 75,648
-----------------------------------------
Total $131,101 $9,383 $(175) $140,309
=========================================
Amortized Unrealized Unrealized Fair
At December 31, 1995 Cost Basis Gains Losses Value
- -------------------------------------------------------------------
(In thousands)
Marketable equity
securities $ 38,520 $2,998 $ (43) $ 41,475
U.S. government
agency 14,177 141 -- 14,318
State municipal
bonds 50,411 2,056 (74) 52,393
------------------------------------------
Total $103,108 $5,195 $(117) $108,186
==========================================
Baltimore Gas and Electric Company and Subsidiaries
46
<PAGE>
Gross and net realized gains and losses on the Constellation Companies'
available-for-sale securities were as follows:
1996 1995 1994
- -------------------------------------------------------------
(In thousands)
Gross realized gains $4,280 $5,470 $ 1,108
Gross realized losses (210) (2,446) (3,150)
-------------------------------
Net realized gains (losses) $4,070 $3,024 $(2,042)
===============================
Contractual Maturities
The contractual maturities of debt securities are as follows:
Amount
- ----------------------------------------------------------
(In thousands)
Less than 1 year $ 1,000
1-5 years 10,065
5-10 years 71,405
More than 10 years 6,000
-------
Total contractual maturities of debt securities $88,470
=======
- --------------------------------------------------------------------------------
Note 5. Regulatory Assets (net)
As discussed in Note 1, BGE's utility operations are subject to regulation by
the Maryland Commission. Except for differences in the timing of the recognition
of certain utility expenses and credits, the ratemaking process utilized by the
Maryland Commission generally is based upon the same accounting principles
applied by nonregulated entities. Under the Maryland Commission's ratemaking
process, these utility expenses and credits are deferred on the Consolidated
Balance Sheets as regulatory assets and liabilities and are recognized in income
as the related amounts are included in service rates and recovered from or
refunded to customers in utility revenues. The following table sets forth
BGE's regulatory assets and liabilities:
At December 31, 1996 1995
- ------------------------------------------------------------------
(In thousands)
Income taxes recoverable through
future rates $264,525 $269,442
Deferred postemployment benefit costs 89,217 81,616
Deferred nuclear expenditures 82,101 86,519
Deferred environmental costs 47,657 38,371
Deferred energy conservation
expenditures 46,696 73,297
Deferred cost of decommissioning
federal uranium enrichment facilities 46,015 51,104
Deferred termination benefit costs 41,137 60,073
Deferred fuel costs 22,734 113,026
Deferred investment tax credits (133,970) (141,463)
Other 6,167 5,930
--------------------
Total regulatory assets (net) $512,279 $637,915
====================
Income taxes recoverable through future rates represent principally the tax
effect of depreciation differences not normalized and the allowance for equity
funds used during construction, offset by unamortized deferred tax rate
differentials and deferred taxes on deferred ITC. These amounts are amortized as
the related temporary differences reverse. See Note 1 for a further discussion
of income taxes.
Deferred postemployment benefit costs represent the excess of such costs
recognized in accordance with Statements of Financial Accounting Standards No.
106 and No. 112 over the amounts reflected in utility rates. These costs will be
amortized over a 15-year period beginning in 1998 (see Note 6).
Deferred nuclear expenditures represent the net unamortized balance of certain
operations and maintenance costs which are being amortized over the remaining
life of the Calvert Cliffs Nuclear Power Plant in accordance with orders of the
Maryland Commission. These expenditures consist of costs incurred from 1979
through 1982 for inspecting and repairing seismic pipe supports, expenditures
incurred from 1989 through 1994 associated with nonrecurring phases of certain
nuclear operations projects, and expenditures incurred during 1990 for
investigating leaks in the pressurizer heater sleeves.
Deferred environmental costs represent the estimated costs of investigating
contamination and performing certain remediation activities at contaminated
Company-owned sites (see Note 12). In November 1995, the Maryland Commission
issued a rate order in the Company's gas base rate proceeding which authorized
the Company to amortize over a 10-year period $21.6 million of these costs, the
amount which had been incurred through October 1995.
Deferred energy conservation expenditures represent the net unamortized balance
of certain operations costs which are being amortized over five years in
accordance with orders of the Maryland Commission. These expenditures consist of
labor, materials, and indirect costs associated with the conservation programs
approved by the Maryland Commission.
Deferred cost of decommissioning federal uranium enrichment facilities
represents the unamortized portion of BGE's required contributions to a fund for
decommissioning and decontaminating the Department of Energy's (DOE) uranium
enrichment facilities. The Energy Policy Act of 1992 requires domestic utilities
to make such contributions, which are generally payable over a 15-year period
with escalation for inflation and are based upon the amount of uranium enriched
by DOE for each utility. These costs are being amortized over the contribution
period as a cost of fuel.
Deferred termination benefit costs represent the net unamortized balance of the
cost of certain termination benefits (see Note 7) applicable to BGE's regulated
operations. These costs are being amortized over a five-year period in
accordance with rate actions of the Maryland Commission.
Deferred fuel costs represent the difference between actual fuel costs and the
fuel rate revenues under BGE's fuel clauses (see Note 1). Deferred fuel costs
are reduced as they are collected from customers.
The underrecovered costs deferred under the fuel clauses were as follows:
At December 31, 1996 1995
- --------------------------------------------------------------------
(In thousands)
Electric deferred fuel costs
Costs deferred $113,172 $130,399
Reserve for disallowed replacement
energy costs (see Note 12) (118,000) (35,000)
--------------------
Net electric deferred fuel costs (4,828) 95,399
Gas deferred fuel costs 27,562 17,627
--------------------
Total deferred fuel costs $ 22,734 $113,026
====================
Deferred investment tax credits (ITC) represents ITC associated with BGE's
regulated utility operations as discussed in Note 1. Deferred ITC are not
deducted from rate base in accordance with federal income tax normalization
requirements.
The foregoing regulatory assets and liabilities are recorded on BGE's
Consolidated Balance Sheets in accordance with Statement of Financial Accounting
Standards (SFAS) No. 71. If BGE were required to terminate application of SFAS
No. 71 for all of its regulated operations, all such amounts deferred would be
recognized in the Consolidated Statements of Income at that time, resulting in a
charge to earnings, net of applicable income taxes.
Baltimore Gas and Electric Company and Subsidiaries
47
<PAGE>
Note 6. Pension and Postemployment Benefits
Pension Benefits
The Company sponsors several noncontributory defined benefit pension plans, the
largest of which (the Pension Plan) covers substantially all BGE employees and
certain employees of BGE's subsidiaries. The other plans, which are not material
in amount, provide supplemental benefits to certain non-employee directors and
key employees. Benefits under the plans are generally based on age, years of
service, and compensation levels.
Prior service cost associated with retroactive plan amendments is amortized on a
straight-line basis over the average remaining service period of active
employees. The Company's funding policy is to contribute at least the
minimum amount required under Internal Revenue Service regulations using the
projected unit credit cost method. Plan assets at December 31, 1996 consisted
primarily of marketable equity and fixed income securities, and group annuity
contracts.
The following tables set forth the combined funded status of the plans and the
composition of total net pension cost. Net pension cost shown below does not
include the cost of termination benefits described in Note 7.
<TABLE>
<CAPTION>
At December 31, 1996 1995
- ------------------------------------------------------------------------------------------------------------------------
(In thousands)
<S> <C>
Vested benefit obligation $695,634 $688,084
Nonvested benefit obligation 17,974 15,668
----------------------------------
Accumulated benefit obligation 713,608 703,752
Projected benefits related to increase in future compensation levels 132,673 122,539
----------------------------------
Projected benefit obligation 846,281 826,291
Plan assets at fair value (792,541) (744,645)
----------------------------------
Projected benefit obligation less plan assets 53,740 81,646
Unrecognized prior service cost (21,890) (24,357)
Unrecognized net loss (117,157) (118,361)
Unamortized net asset from adoption of FASB Statement No. 87 797 995
----------------------------------
Accrued pension (asset) liability $ (84,510) $ (60,077)
==================================
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31, 1996 1995 1994
- ---------------------------------------------------------------------------------------------------------------------------
(In thousands)
<S> <C>
Components of net pension cost
Service cost-benefits earned during the period $16,089 $11,407 $15,015
Interest cost on projected benefit obligation 59,948 58,433 58,723
Actual return on plan assets (57,671) (150,510) 7,932
Net amortization and deferral 2,115 94,674 (60,071)
------------------------------------------------
Total net pension cost 20,481 14,004 21,599
Amount capitalized as construction cost (2,442) (1,422) (2,578)
------------------------------------------------
Amount charged to expense $18,039 $12,582 $19,021
================================================
</TABLE>
The Company also sponsors a defined contribution savings plan covering all
eligible BGE employees and certain employees of BGE's subsidiaries. Under this
plan, the Company makes contributions on behalf of participants. Company
contributions to this plan totaled $9.4 million, $8.5 million, and $8.7 million
in 1996, 1995, and 1994, respectively.
Postretirement Benefits
The Company sponsors defined benefit postretirement health
care and life insurance plans which cover substantially all BGE employees and
certain employees of its subsidiaries. Benefits under the plans are generally
based on age, years of service, and pension benefit levels. The postretirement
benefit (PRB) plans are unfunded. Substantially all of the health care plans are
contributory, and participant contributions for employees who retire after June
30, 1992 are based on age and years of service. Retiree contributions increase
commensurate with the expected increase in medical costs. The postretirement
life insurance plan is noncontributory. The transition obligation resulting from
the adoption of Statement of Financial Accounting Standards No. 106 effective
January 1, 1993 is being amortized over a 20-year period.
In April 1993, the Maryland Commission issued a rate order authorizing BGE to
recognize in operating expense one-half of the annual increase in PRB costs
applicable to regulated operations as a result of the adoption of Statement No.
106 and to defer the remainder of the annual increase in these costs for
inclusion in BGE's next base rate proceeding. In accordance with the April 1993
Order, all amounts to be deferred prior to completion of BGE's next base rate
proceeding will be amortized over a 15-year period beginning in 1998.
In November 1995, the Maryland Commission issued a rate order in BGE's gas base
rate proceeding providing for full recognition in operating expense of PRB and
other postemployment benefits (discussed below) costs attributable to gas
operations, and affirming its previous decision on amortization of deferred PRB
costs. This phase-in approach meets the guidelines established by the Emerging
Issues Task Force of the Financial Accounting Standards Board for deferring PRB
costs as a regulatory asset. Accrual-basis PRB costs applicable to nonregulated
operations are charged to expense.
Baltimore Gas and Electric Company and Subsidiaries
48
<PAGE>
The following table sets forth the components of the accumulated PRB obligation
and a reconciliation of these amounts to the accrued PRB liability.
<TABLE>
<CAPTION>
At December 31, 1996 1995
- ---------------------------------------------------------------------------------------------------------------------------
Life Life
Health Care Insurance Health Care Insurance
(In thousands)
<S> <C>
Accumulated postretirement benefit obligation:
Retirees $163,904 $45,485 $157,804 $44,769
Active employees 82,373 19,269 84,724 18,599
-------------------------------------------------------------
Total accumulated postretirement benefit obligation 246,277 64,754 242,528 63,368
Unrecognized transition obligation (141,089) (40,960) (149,907) (43,521)
Unrecognized net loss (7,368) (5,690) (12,767) (5,764)
-------------------------------------------------------------
Accrued postretirement benefit liability $ 97,820 $18,104 $ 79,854 $14,083
=============================================================
</TABLE>
The following table sets forth the composition of net PRB cost. Such cost does
not include the cost of termination benefits described in Note 7.
Year ended December 31, 1996 1995
- --------------------------------------------------------------------------------
(In thousands)
Net postretirement benefit cost:
Service cost--benefits earned during
the period $ 5,559 $ 3,918
Interest cost on accumulated post
retirement benefit obligation 21,918 21,203
Amortization of transition obligation 11,378 11,378
Net amortization and deferral 174 (86)
-------------------
Total net postretirement benefit cost 39,029 36,413
Amount capitalized as construction cost (6,224) (5,299)
Amount deferred (7,455) (8,025)
-------------------
Amount charged to expense $25,350 $23,089
===================
Other Postemployment Benefits
The Company provides health and life insurance benefits to employees of BGE and
certain employees of its subsidiaries who are determined to be disabled under
BGE's Disability Insurance Plan. The Company also provides pay continuation
payments for employees determined to be disabled before November 1995. Such
payments for employees determined to be disabled after that date are paid by an
insurance company, and the cost of such insurance is paid by employees. The
liability for these benefits totaled $51 million and $52 million as of December
31, 1996 and 1995, respectively. The portion of the liability attributable to
regulated activities as of December 31, 1993 was deferred.
Consistent with the Maryland Commission's November 1995 order, the amounts
deferred will be amortized over a 15-year period beginning in 1998.
Assumptions
The pension, postretirement, and other postemployment benefit liabilities were
determined using the following assumptions.
At December 31, 1996 1995
- --------------------------------------------------------------------------------
Assumptions:
Discount rate
Pension and postretirement benefits 7.5% 7.5%
Other postemployment benefits 6.0 6.0
Average increase in
future compensation levels 4.0 4.0
Expected long-term rate of
return on assets 9.0 9.0
The health care inflation rates for 1996 are assumed to be 9.5% for
Medicare-eligible retirees and 8.9% for retirees not covered by Medicare. The
health care inflation rates for 1997 are assumed to be 7.5% for
Medicare-eligible retirees and 10.0% for retirees not covered by Medicare. After
1997, both rates are assumed to decrease by 0.5% annually to an ultimate rate of
5.5% in the years 2001 and 2006, respectively. A one percentage point increase
in the health care inflation rate from the assumed rates would increase the
accumulated postretirement benefit obligation by approximately $41 million as of
December 31, 1996 and would increase the aggregate of the service cost and
interest cost components of postretirement benefit cost by approximately $4
million annually.
- --------------------------------------------------------------------------------
Note 7. Termination Benefits
BGE offered a Voluntary Special Early Retirement Program (the 1992 VSERP) to
eligible employees who retired during the period February 1, 1992 through April
1, 1992. In April 1993, the Maryland Commission authorized BGE to amortize
the $6.6 million cost of termination benefits associated with the 1992 VSERP,
which consisted principally of an enhanced pension benefit, over a five-year
period for ratemaking purposes.
BGE offered a second Voluntary Special Early Retirement Program (the 1993 VSERP)
to eligible employees who retired as of February 1, 1994. The one-time cost of
the 1993 VSERP consisted of enhanced pension and postretirement benefits. In
addition to the 1993 VSERP, further employee reductions have been accomplished
through the elimination of certain positions, and various programs have been
offered to employees impacted by the eliminations. The $88.3 million portion of
1993 VSERP attributable to regulated activities was deferred and is being
amortized over a five-year period for ratemaking purposes, beginning in February
1994, consistent with previous rate actions of the Maryland Commission.
Baltimore Gas and Electric Company and Subsidiaries
49
<PAGE>
Note 8. Short-Term Borrowings
Short-term borrowings include bank loans, commercial paper notes, and bank lines
of credit. The Company pays commitment fees in support of lines of credit.
Borrowings under the lines are at the banks' prime rates, base interest rates,
or at various money market rates.
Short-term borrowings were as follows:
At December 31, 1996 1995
- -------------------------------------------------------------------
(In thousands)
BGE's bank loans $ 8,785 $ 3,845
BGE's commercial paper notes 324,400 275,300
Constellation Companies' lines of credit -- 160
--------------------
Total short-term borrowings $333,185 $279,305
====================
The weighted average interest rates for short-term borrowings were as follows:
Year ended December 31, 1996 1995
- -------------------------------------------------------------------
BGE
Bank loans 4.93% 4.74%
Commercial Paper Notes 5.53 5.92
Constellation Companies
Lines of Credit -- --
Unused lines of credit supporting commercial paper notes at December 31, 1996
and 1995 were $203 million and $238 million, respectively. These amounts are
exclusive of $150 million of revolving credit agreements undrawn at year-end
(see Note 9).
- --------------------------------------------------------------------------------
Note 9. Long-Term Debt
First Refunding Mortgage Bonds of BGE
Substantially all of the principal properties and franchises owned by BGE, as
well as the capital stock of Constellation Holdings, Inc., Safe Harbor Water
Power Corporation, HP&S, EP&S, and Constellation Energy Source, Inc. (formerly
named BNG, Inc.), are subject to the lien of the mortgage under which BGE's
outstanding First Refunding Mortgage Bonds have been issued.
On August 1 of each year, BGE is required to pay to the mortgage trustee an
annual sinking fund payment equal to 1% of the largest principal amount of
Mortgage Bonds outstanding under the mortgage during the preceding twelve
months. Such funds are to be used, as provided in the mortgage, for the purchase
and retirement by the trustee of Mortgage Bonds of any series other than the
5 1/2% Installment Series of 2002, the 8.40% Series of 1999, the 5 1/2% Series
of 2000, the 8 3/8% Series of 2001, the 7 1/4% Series of 2002, the 6 1/2%
Series of 2003, the 6 1/8% Series of 2003, the 5 1/2% Series of 2004, the
7 1/2% Series of 2007, and the 6 5/8% Series of 2008.
The principal amounts of the 5 1/2% Installment Series Mortgage Bonds payable
each year are as follows:
Year
- --------------------------------------------------------------------------------
(In thousands)
1997 $ 605
1998 and 1999 690
2000 and 2001 865
2002 6,725
The Remarketed Floating Rate Series Due September 1, 2006 First Refunding
Mortgage Bonds include a provision that allows the bondholders the option to
tender their bonds back to BGE on an annual basis. BGE is required to repurchase
and retire at par any bonds tendered that are not remarketed or purchased by the
remarketing agent. In addition, BGE has the option to call the bonds annually at
par on each remarketing date.
Other Long-Term Debt of BGE
BGE maintains revolving credit agreements that expire at various times from 1997
through 1999. Under the terms of the agreements, BGE may, at its option, obtain
loans at various interest rates. A commitment fee is paid on the daily average
of the unborrowed portion of the commitment. At December 31, 1996, BGE had no
borrowings under these revolving credit agreements and had available $150
million of unused capacity under these agreements.
Under the terms of the bank loan which matures on March 29, 2001, the bank has a
one-time option to cancel the loan on December 29, 1997. Until that date, the
interest rate on the loan is 5.22%. If the bank does not cancel the loan on
December 29, 1997, the interest rate for the remaining term will reset to 6.11%.
Following is information regarding BGE's Medium-term Notes outstanding at
December 31, 1996:
Weighted-Average
Series Interest Rate Maturity Dates
- --------------------------------------------------------------------------------
B 8.43% 1998-2006
C 7.09% 1997-2003
D 6.60% 1998-2006
Long-Term Debt of Constellation Companies
The Constellation Companies have a $75 million unsecured revolving credit
agreement which matures December 9, 1999 and is used to provide liquidity for
general corporate purposes. A commitment fee is paid on the daily average of the
unborrowed portion of the commitment. At December 31, 1996, the Constellation
Companies had $65 million outstanding under this agreement.
The Constellation Companies' mortgage and construction loans and other
collateralized notes have varying terms. The 8.00% mortgage note requires
monthly principal and interest payments through July 31, 2001. The 8.00%
construction loan requires no monthly principal and interest payments during
construction and is due October 30, 2003. The variable rate mortgage notes
require periodic payment of principal and interest with various maturities from
June 1997 through July 2009. The 7.50% mortgage note requires monthly principal
and interest payments through October 9, 2005. The 7.357% mortgage note requires
quarterly principal and interest payments through March 15, 2009. The 9.65%
mortgage note requires monthly principal and interest payments through February
1, 2028.
The unsecured notes outstanding as of December 31, 1996 mature in accordance
with the following schedule:
Amount
- --------------------------------------------------------------------------------
(In thousands)
8.93%, due August 28, 1997 $ 52,000
6.65%, due September 9, 1997 15,000
8.23%, due October 15, 1997 30,000
7.05%, due April 22, 1998 25,000
7.06%, due September 9, 1998 20,000
8.48%, due October 15, 1998 75,000
7.30%, due April 22, 1999 90,000
8.73%, due October 15, 1999 15,000
7.55%, due April 22, 2000 35,000
7.43%, due September 9, 2000 30,000
8.00%, due December 31, 2000 160
--------
Total unsecured notes $387,160
========
Baltimore Gas and Electric Company and Subsidiaries
50
<PAGE>
Long-Term Debt of Other Diversified Businesses
Long-term debt of other diversified businesses includes a
$50 million unsecured revolving credit agreement of Comfort Link which matures
September 26, 2001. Loans may be obtained at various rates for terms up to nine
months. A facility fee is paid on the total amount of the commitment. At
December 31, 1996, $12 million was outstanding under this agreement.
Weighted Average Interest Rates for Variable Rate Debt
The weighted average interest rates for variable rate debt were as follows:
Year ended December 31, 1996 1995
- --------------------------------------------------------------------------------
BGE
Floating rate series mortgage bonds 5.87% 6.30%
Remarketed floating rate series
mortgage bonds 5.63 --
Pollution control loan 3.49 3.79
Port facilities loan 3.59 4.06
Adjustable rate pollution control loan 3.90 3.75
Economic development loan 3.57 4.01
Constellation Companies
Loans under credit agreements 6.08 6.74
Mortgage and construction loans
and other collateralized notes 8.33 8.99
Other Diversified Businesses
Loans under credit agreements 6.13 --
Aggregate Maturities
The combined aggregate maturities and sinking fund requirements for all of the
Company's long-term borrowings for each of the next five years are as follows:
Diversified
Year BGE Businesses
- --------------------------------------------------------------------------------
(In thousands)
1997 $ 89,848 $107,924
1998 93,578 165,370
1999 247,347 186,339
2000 253,658 97,803
2001 247,183 31,897
As of December 31, 1996, BGE had $195 million of debt with provisions that allow
lenders the option to request BGE to repay the debt at certain times prior to
maturity. In the event such options are exercised, BGE intends to refinance such
debt on a long-term basis through the issuance of medium term notes or using
revolving credit agreements.
- --------------------------------------------------------------------------------
Note 10. Redeemable Preference Stock
The 7.80%, 1989 Series is subject to mandatory redemption in full at par on July
1, 1997. The following series are subject to an annual mandatory redemption of
the number of shares shown below at par beginning in the year shown below. At
BGE's option, an additional number of shares, not to exceed the same number as
are mandatory, may be redeemed at par in any year, commencing in the same year
in which the mandatory redemption begins. The 8.25%, 1989 Series, the 8.625%,
1990 Series, and the 7.85%, 1991 Series listed below are not redeemable except
through operation of a sinking fund.
Beginning
Series Shares Year
- --------------------------------------------------------------------------------
7.50%, 1986 Series 15,000 1992
6.75%, 1987 Series 15,000 1993
8.25%, 1989 Series 100,000 1995
8.625%, 1990 Series 130,000 1996
7.85%, 1991 Series 70,000 1997
The combined aggregate redemption requirements at December 31, 1996 for all
series of redeemable preference stock are as follows:
Year
- --------------------------------------------------------------------------------
(In thousands)
1997 $ 83,000
1998 23,000
1999 23,000
2000 10,000
2001 10,000
Thereafter 68,500
--------
Total aggregate redemption requirements $217,500
========
With regard to payment of dividends or assets available in the event of
liquidation, all issues of preference stock, whether subject to mandatory
redemption or not, rank equally; and all preference stock ranks prior to common
stock.
Baltimore Gas and Electric Company and Subsidiaries
51
<PAGE>
Note 11. Leases
The Company, as lessee, contracts for certain facilities and equipment under
lease agreements with various expiration dates and renewal options. Consistent
with the regulatory treatment, lease payments for utility operations are charged
to expense. Lease expense, which is comprised primarily of operating leases,
totaled $11.6 million, $12.2 million, and $12.7 million for the years ended
1996, 1995, and 1994, respectively.
The future minimum lease payments at December 31, 1996 for long-term
noncancelable operating leases are as follows:
Year
- --------------------------------------------------------------------------------
(In thousands)
1997 $ 4,899
1998 4,095
1999 2,072
2000 1,893
2001 1,450
Thereafter 2,725
-------
Total minimum lease payments $17,134
=======
Certain of the Constellation Companies, as lessor, have entered into operating
leases for office and retail space. These leases expire over periods ranging
from 1 to 19 years, with options to renew. The net book value of property under
operating leases was $177.3 million at December 31, 1996. The future minimum
rentals to be received under operating leases in effect at December 31, 1996 are
as follows:
Year
- --------------------------------------------------------------------------------
(In thousands)
1997 $ 15,433
1998 14,073
1999 13,146
2000 12,671
2001 11,704
Thereafter 61,735
--------
Total minimum rentals $128,762
========
- --------------------------------------------------------------------------------
Note 12. Commitments, Guarantees, and Contingencies
Commitments
BGE has made substantial commitments in connection with its construction program
for 1997 and subsequent years. In addition, BGE has entered into three long-term
contracts for the purchase of electric generating capacity and energy. The
contracts expire in 2001, 2013, and 2023. Total payments under these contracts
were $64.1, $68.4, and $69.4 million during 1996, 1995, and 1994, respectively.
At December 31, 1996, the estimated future payments for capacity and energy that
BGE is obligated to buy under these contracts are as follows:
Year
- --------------------------------------------------------------------------------
(In thousands)
1997 $ 61,669
1998 78,075
1999 91,938
2000 92,039
2001 62,978
Thereafter 805,110
----------
Total estimated future payments for
capacity and energy under long-term contracts $1,191,809
==========
Certain of the Constellation Companies have committed to contribute additional
capital and to make additional loans to certain affiliates, joint ventures, and
partnerships in which they have an interest. As of December 31, 1996, the total
amount of investment requirements committed to by the Constellation Companies is
$56 million.
In December, 1994, BGE and HP&S entered into agreements with a financial
institution whereby BGE and HP&S can sell on an ongoing basis up to an aggregate
of $40 million and $50 million, respectively, of an undivided interest in a
designated pool of customer receivables. Under the terms of the agreements, BGE
and HP&S have limited recourse on the receivables and have recorded a reserve
for credit losses. At December 31, 1996, BGE and HP&S had sold $35 million and
$47 million of receivables, respectively, under these agreements.
Guarantees
BGE has agreed to guarantee two-thirds of certain indebtedness of Safe Harbor
Water Power Corporation. The total amount of indebtedness that can be guaranteed
is $50 million, of which $33 million represents BGE's potential share of the
guarantee. As of December 31, 1996, outstanding indebtedness of Safe Harbor
Water Power Corporation was $32 million, of which $21 million is guaranteed by
BGE. BGE has also agreed to guarantee up to $20 million of obligations and
indebtedness of Constellation Energy Source, Inc. (formerly named BNG, Inc.) As
of December 31, 1996, there were no outstanding obligations under this
guarantee. BGE assesses that the risk of material loss on the loans guaranteed
is minimal.
As of December 31, 1996, the total outstanding loans and letters of credit of
certain power generation and real estate projects guaranteed by the
Constellation Companies were $54 million. Also, the Constellation Companies have
agreed to guarantee certain other borrowings of various power generation and
real estate projects. The Company has assessed that the risk of material loss on
the loans guaranteed and performance guarantees is minimal.
Pending Merger With Potomac Electric Power Company
BGE, Potomac Electric Power Company (PEPCO), and Constellation Energy
Corporation (formerly named "RH Acquisition Corp.") (CEC), have entered into an
Agreement and Plan of Merger, dated as of September 22, 1995 (the Merger
Agreement). CEC was formed to accomplish the merger and its outstanding capital
stock is owned 50% by BGE and 50% by PEPCO. The Merger Agreement provides for a
strategic business combination that will be accomplished by merging both BGE and
PEPCO into CEC (the Merger). The Merger, which was unanimously approved by the
Boards of Directors of BGE and PEPCO and approved by the shareholders of both
companies, is expected to close during 1997 after all other conditions to the
consummation of the Merger, including obtaining applicable regulatory approvals
(described below), are met or waived. In connection with the Merger, BGE common
shareholders will receive one share of CEC common stock for each BGE share and
PEPCO common shareholders will receive 0.997 of a share of CEC common stock for
each PEPCO share.
Baltimore Gas and Electric Company and Subsidiaries
52
<PAGE>
Preliminary estimates by the managements of PEPCO and BGE indicate that the
synergies resulting from the combination of their utility operations could
generate net cost savings of up to $1.3 billion over a period of 10 years
following the Merger. These estimates indicate that about two-thirds of the
savings will come from reduced labor costs, with the remaining savings split
between nonfuel purchasing and corporate and administrative programs. These
savings are net of costs to achieve, presently estimated to be approximately
$150 million, and are expected to be allocated among shareholders and customers.
This allocation will depend upon the results of regulatory proceedings in the
various jurisdictions in which BGE and PEPCO operate their utility businesses
(see discussion of the issues raised in regulatory proceedings regarding the
allocation and other matters). The analyses employed in order to develop
estimates of the potential savings as a result of the Merger were necessarily
based upon various assumptions which involve judgments with respect to, among
other things, future national and regional economic and competitive conditions,
inflation rates, regulatory treatment, weather conditions, financial market
conditions, interest rates, future business decisions and other uncertainties,
all of which are difficult to predict and many of which are beyond the control
of BGE and PEPCO. Accordingly, while BGE believes that such assumptions are
reasonable for purposes of the development of estimates of potential savings,
there can be no assurance that such assumption will approximate actual
experience or that all such savings will be realized.
Major regulatory proceedings, together with an indication of the current status
of the proceeding, which must be concluded in order to proceed with the merger,
are listed below. The Merger Agreement provides that a condition to closing is
that no such approvals shall impose terms and conditions that would have, or
would be reasonably likely to have, a material adverse effect on the business,
operations, properties, assets, condition (financial or otherwise), prospects,
or results of operations of the new company.
(bullet) Federal Energy Regulatory Commission (FERC) - Hearings have been
completed and we are waiting for a decision. The hearings explored the
merged company's generation market power, including the appropriate geographic
markets, and to consider appropriate remedies if the merged company is found
to possess generation market power. Testimony of FERC staff included the
suggestion that a significant portion of generation (approximately 2400-3600
megawatts) be divested or transmission capability be upgraded or both due to
the perceived market power of the merged company in both the wholesale and
retail markets.
(bullet) Maryland Public Service Commission (Maryland Commission) - Hearings
have been completed and we are waiting for a decision. Since the Report on Form
10-Q for the third quarter 1996 was filed, rebuttal and surrebuttal testimony
has been filed. Office of People's Counsel (the advocates for residential
customers) recommended that the Maryland Commission not approve the Merger
until the Applicants demonstrate that Maryland customers will not be harmed by
potential restrictions on competition due to the market power of the new
company. If, however, the Maryland Commission decides to approve the Merger,
People's Counsel continues to recommend rate decreases. Due to the use of a
different test period, the amounts are somewhat different than reported in
the second quarter Report on Form 10-Q. Based on a test period proposed by
People's Counsel in recent testimony, they recommend a pre-merger rate
reduction of approximately $108.3 million ($84.7 million to BGE customers
and $23.6 million to PEPCO customers) with Merger savings being reflected
in further reduced rates of approximately $65 million ($45 million to BGE
customers and $20 million to PEPCO customers) contemporaneously with the date
of the Merger. A number of other recommendations are also included in
People's Counsel testimony. The Maryland Energy Administration (MEA)
continues to recommend that the Maryland Commission adopt an alternative
regulatory plan and also asks that rates be examined. Maryland Commission
Staff testimony also utilizes the new test period. Based on the new test period
Maryland Commission Staff recommends an immediate decrease of $63.6 million
(BGE's rates reduced by $54.3 million and PEPCO's by $9.3 million) at the
time of the Merger. Maryland Commission Staff's surrebuttal testimony also
recommends that CEC be required to make a rate filing 15 months after the
Merger becomes effective.
(bullet) District of Columbia Public Service Commission - Hearings began
February 18, 1997. Testimony was filed by the parties in September 1996. The
D.C. Office of People's Counsel (the advocates for residential customers)
opposes the Merger based on its contention that BGE and PEPCO have not proved
that the Merger is in the public interest. Testimony of the D.C. People's
Counsel also provides that should the Merger be approved, an immediate rate
reduction of $44.2 million be imposed at the time of the Merger, followed by
a 5-year moratorium on rate increases. Further, testimony of D.C. People's
Counsel advocates divestiture of all nonutility affiliate companies, exclusion
of BGE's Calvert Cliffs Nuclear Plant from production plant assigned to D.C.,
and a 5-year $23.37 million per year economic development program. GSA, a major
D.C. customer, requests that any approval should be coupled with an imposition
of retail competition access for ratepayers such as GSA, a 25-year
amortization of costs to achieve the Merger, and elimination of Calvert Cliffs
from the generating mix. In addition to these matters, D.C. People's Counsel, an
intervenor, Washington Gas Light Company, and the D.C. Corporation Counsel have
questioned the interpretation by BGE and PEPCO that a D.C. statute known as
the Antimerger Law is inapplicable to this transaction. Should such statute
be deemed to be applicable, authorization of the Merger by Congress would be
required. Allegations also were made that BGE and PEPCO should have received
Congressional approval for their owning 50% of the shell company, CEC, prior to
consummation of the Merger.
The reasons for the Merger, the terms and conditions contained in the Merger
Agreement, the regulatory approvals required prior to closing the Merger, and
other matters concerning the Merger, PEPCO, and CEC are discussed in more detail
in the Registration Statement on Form S-4 (Registration No. 33-64799).
Environmental Matters
The Clean Air Act of 1990 (the Act) contains two titles designed to reduce
emissions of sulfur dioxide and nitrogen oxide (NOx) from electric generating
stations. Title IV contains provisions for compliance in two separate phases.
Phase I of Title IV became effective January 1, 1995, and Phase II of Title IV
must be implemented by 2000. BGE met the requirements of Phase I by installing
flue gas desulfurization systems and fuel switching and through unit
retirements. BGE is currently examining what actions will be required in order
to comply with Phase II of the Act. However, BGE anticipates that compliance
will be attained by some combination of fuel switching, flue gas
desulfurization, unit retirements, or allowance trading.
At this time, plans for complying with NOx control requirements under Title I of
the Act are less certain because all implementation regulations have not yet
been finalized by the government. It is expected that by the year 1999 these
regulations will require additional NOx controls for ozone attainment at BGE's
generating plants and at other BGE facilities. The controls will result in
additional expenditures that are difficult to predict prior to the issuance of
such regulations. Based on existing and proposed ozone nonattainment
regulations, BGE currently estimates that the NOx controls at BGE's generating
plants will cost approximately $90 million. BGE is currently unable to predict
the cost of compliance with the additional requirements at other BGE facilities.
Baltimore Gas and Electric Company and Subsidiaries
53
<PAGE>
BGE has been notified by the Environmental Protection Agency and several state
agencies that it is being considered a potentially responsible party (PRP) with
respect to the cleanup of certain environmentally contaminated sites owned and
operated by third parties. Cleanup costs for these sites cannot be estimated,
except that BGE's 15.79% share of the possible cleanup costs at one of these
sites, Metal Bank of America, a metal reclaimer in Philadelphia, could exceed
amounts recognized by up to approximately $7 million based on the highest
estimate of costs in the range of reasonably possible alternatives. Although the
cleanup costs for certain of the remaining sites could be significant, BGE
believes that the resolution of these matters will not have a material effect on
its financial position or results of operations.
Also, BGE is coordinating investigation of several former gas manufacturing
plant sites, including exploration of corrective action options to remove coal
tar. In late December 1996, the Maryland Department of the Environment and BGE
signed a consent order that requires BGE to implement remedial action plans
addressing contamination at and related to the Spring Gardens site. The specific
remedial actions for this site will be developed in the future. BGE has
recognized estimated environmental costs at all former gas manufacturing plant
sites (based on remedial action options) which are considered probable totaling
$50 million in nominal dollars. These costs, net of accumulated amortization,
have been deferred as a regulatory asset (see Note 5). Accounting rules also
require BGE to disclose additional costs deemed by BGE to be less likely than
probable costs, but still "reasonably possible" of being incurred at these
sites. Because of the results of recent studies at these sites, it is reasonably
possible that these additional costs could exceed the amount recognized by
approximately $48 million in nominal dollars ($11 million in current dollars,
plus the impact of inflation at 3.1% over a period of up to 60 years).
Nuclear Insurance
An accident or an extended outage at either unit of the Calvert Cliffs Nuclear
Power Plant could have a substantial adverse effect on BGE. The primary
contingencies resulting from an incident at the Calvert Cliffs plant would
involve the physical damage to the plant, the recoverability of replacement
power costs, and BGE's liability to third parties for property damage and bodily
injury. BGE maintains various insurance policies for these contingencies. The
costs that could result from a major accident or an extended outage at either of
the Calvert Cliffs units could exceed the coverage limits.
In addition, in the event of an incident at any commercial nuclear power plant
in the country, BGE could be assessed for a portion of any third party claims
associated with the incident. Under the provisions of the Price Anderson Act,
the limit for third party claims from a nuclear incident is $8.92 billion. If
third party claims relating to such an incident exceed $200 million (the amount
of primary insurance), BGE's share of the total liability for third party claims
could be up to $159 million per incident, that would be payable at a rate of $20
million per year.
BGE and other operators of commercial nuclear power plants in the United States
are required to purchase insurance to cover claims of certain nuclear workers.
Other non-governmental commercial nuclear facilities may also purchase such
insurance. Coverage of up to $400 million is provided for claims against BGE or
others insured by these policies for radiation injuries. If certain claims were
made under these policies, BGE and all policyholders could be assessed, with
BGE's share being up to $6.02 million in any one year.
For physical damage to Calvert Cliffs, BGE has $2.75 billion of property
insurance from industry mutual insurance companies. If an outage at Calvert
Cliffs is caused by an insured physical damage loss and lasts more than 21
weeks, BGE has up to $473.2 million per unit of insurance, provided by an
industry mutual insurance company, for replacement power costs. This amount can
be reduced by up to $94.6 million per unit if an outage to both units at Calvert
Cliffs is caused by a singular insured physical damage loss. If accidents at any
insured plants cause a shortfall of funds at the industry mutuals, BGE and all
policyholders could be assessed, with BGE's share being up to $35.1 million.
Recoverability of Electric Fuel Costs
By statute, actual electric fuel costs are recoverable so long as the Maryland
Commission finds that BGE demonstrates that, among other things, it has
maintained the productive capacity of its generating plants at a reasonable
level. The Maryland Commission and Maryland's highest appellate court have
interpreted this as permitting a subjective evaluation of each unplanned outage
at BGE's generating plants to determine whether or not BGE had implemented all
reasonable and cost-effective maintenance and operating control procedures
appropriate for preventing the outage. Effective January 1, 1987, the Maryland
Commission authorized the establishment of a Generating Unit Performance Program
(GUPP) to measure, annually, utility compliance with maintaining the productive
capacity of generating plants at reasonable levels by establishing a system-wide
generating performance target and individual performance targets for each base
load generating unit. In fuel rate hearings, actual generating performance after
adjustment for planned outages will be compared to the system-wide target and,
if met, should signify that BGE has complied with the requirements of Maryland
law. Failure to meet the system-wide target will result in review of each unit's
adjusted actual generating performance versus its performance target in
determining compliance with the law and the basis for possibly imposing a
penalty on BGE. Parties to fuel rate hearings may still question the prudence of
BGE's actions or inactions with respect to any given generating plant outage,
which could result in the disallowance of replacement energy costs by the
Maryland Commission.
Since the two units at BGE's Calvert Cliffs Nuclear Power Plant utilize BGE's
lowest cost fuel, replacement energy costs associated with outages at these
units can be significant. BGE 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.
In October 1988, BGE filed its first fuel rate application for a change in its
electric fuel rate under GUPP. The resultant case before the Maryland Commission
covers BGE's operating performance in calendar year 1987, and BGE's filing
demonstrated that it met the system-wide and individual nuclear plant
performance targets for 1987. In November 1989, testimony was filed on behalf of
the Maryland People's Counsel (People's Counsel) alleging that seven outages at
the Calvert Cliffs plant in 1987 were due to management imprudence and that the
replacement energy costs associated with those outages should be disallowed by
the Commission. Total replacement energy costs associated with the 1987 outages
were approximately $33 million. On January 23, 1995, the Hearing Examiner issued
his decision in the 1987 fuel rate proceeding and found that the Company had met
the GUPP standard which establishes a presumption that BGE had operated the
plant at a reasonably productive capacity level. However, the Order found that
the presumption of reasonableness would be overcome by a showing of
mismanagement and that such a showing was made with respect to the environmental
qualifications outage time. The Hearing Examiner had mitigated the disallowance
of replacement energy costs due to the fact the GUPP standard was met. The
Hearing Examiner's Order was appealed to the Maryland Commission by both BGE and
People's Counsel. The Maryland Commission upheld the Hearing Examiner's findings
with respect to the environmental
Baltimore Gas and Electric Company and Subsidiaries
54
<PAGE>
qualification related outage time, but disagreed with certain methodologies
applied by the Hearing Examiner. The impact of the Maryland Commission's
decision on the Company's 1996 earnings was approximately $4.5 million,
the amount previously estimated by the Company. People's Counsel has filed a
motion for rehearing.
In May 1989, BGE filed its fuel rate case in which 1988 performance was
examined. BGE met the system-wide and nuclear plant performance targets in 1988.
People's Counsel alleged that BGE imprudently managed several outages at Calvert
Cliffs, and BGE estimates that the total replacement energy costs associated
with these 1988 outages were approximately $2 million. On November 14, 1991, a
Hearing Examiner at the Maryland Commission issued a proposed Order, which
became final on December 17, 1991 and concluded that no disallowance was
warranted. The Hearing Examiner found that BGE maintained the productive
capacity of the Plant at a reasonable level, noting that it produced a near
record amount of power and exceeded the GUPP standard. Based on this record, the
Order concluded there was sufficient cause to excuse any avoidable failures to
maintain productive capacity at higher levels.
During 1989, 1990, and 1991, BGE experienced extended outages at its Calvert
Cliffs Nuclear Power Plant. In the Spring of 1989, a leak was discovered around
the Unit 2 pressurizer heater sleeves during a refueling outage. BGE shut down
Unit 1 as a precautionary measure on May 6, 1989, to inspect for similar leaks
and none were found. However, Unit 1 was out of service for the remainder of
1989 and 285 days of 1990 to undergo maintenance and modification work to
enhance the reliability of various safety systems, to repair equipment, and to
perform required periodic surveillance tests. Unit 2, which returned to service
May 4, 1991, remained out of service for the remainder of 1989, 1990, and the
first part of 1991 to repair the pressurizer, perform maintenance and
modification work, and complete the refueling. The replacement energy costs
associated with these extended outages for both units at Calvert Cliffs,
concluding with the return to service of Unit 2, are estimated to be $458
million.
In a December 1990 Order issued by the Maryland Commission in a BGE base rate
proceeding, the Maryland Commission found that certain operations and
maintenance expenses incurred at Calvert Cliffs during the test year should not
be recovered from ratepayers. The Maryland Commission found that this work,
which was performed during the 1989-1990 Unit 1 outage and fell within the test
year, was avoidable and caused by BGE actions which were deficient. The Maryland
Commission noted in the Order that its review and findings on these issues
pertain to the reasonableness of BGE's test year operations and maintenance
expenses for purposes of setting base rates and not to the responsibility for
replacement energy costs associated with the outages at Calvert Cliffs. The
Maryland Commission stated that its decision in the base rate case will have no
res judicata (binding) effect in the fuel rate proceeding examining the
1989-1991 outages. The work characterized as avoidable significantly increased
the duration of the Unit 1 outage. Despite the Maryland Commission's statement
regarding no binding effect, BGE recognizes that the views expressed by the
Maryland Commission made the full recovery of all of the replacement energy
costs associated with the Unit 1 outage doubtful. Therefore, in December 1990,
BGE recorded a provision of $35 million against the possible disallowance of
such costs.
In December 1996, BGE entered into a settlement agreement with People's Counsel
and the Maryland Commission Staff proposing a resolution to these fuel rate
proceedings. BGE agreed that ratepayers will not fund a total of $118 million of
electric replacement energy costs associated with the extended outages. This
represents $83 million in addition to the $35 million reserve for possible
disallowance of replacement energy costs recorded in 1990. Therefore, in
December 1996, BGE increased the provision for the disallowance of such costs by
$83 million. Additionally, in 1996, BGE wrote off $5.6 million of accrued
carrying charges related to the deferred fuel balances. The remainder of the
replacement energy costs associated with the extended outage has already been
recovered from customers through the fuel rate.
California Power Purchase Agreements
The Constellation Companies have ownership interests in 16 projects that sell
electricity in California under "Interim Standard Offer No. 4" power purchase
agreements. Under these agreements, the projects supply electricity to utilities
at a fixed rate for capacity and energy the first 10 years of the agreements,
and a fixed rate for capacity plus a variable rate for energy based on the
utilities' avoided cost for the remaining term of the agreements. Avoided
cost generally is the cost of a utility's lowest-cost next-available source
of generation to service the demands on its system.
From 1996 through 2000, the 10-year periods for fixed energy rates expire for
these projects and they will begin supplying electricity at variable rates. At
current avoided cost levels, the Constellation Companies would experience
reduced earnings or incur losses associated with these projects when they
begin supplying electricity at variable rates. Eight projects begin supplying
electricity at variable rates in 1997 and 1998. The projects that make the
highest revenues will begin supplying electricity at variable rates in 1999 and
2000. As a result, we do not expect the Constellation Companies to experience
significantly lower earnings or losses on these projects before 2000.
Constellation is pursuing alternatives for these power generation projects
including repowering the projects to reduce operating costs, changing fuels to
reduce operating costs, renegotiating the power purchase agreements to improve
the terms, restructuring financings to improve the financing terms, and selling
its ownership interests in the projects. The Company cannot estimate the
financial impact of the switch from fixed to variable rates on the Constellation
Companies or on BGE, but the impact could be material.
Constellation Real Estate
Management will consider market demand, interest rates, the availability of
financing, and the strength of the economy in general when making decisions
about real estate investments. We believe until the economy shows sustained
growth and there is more demand for new development, real estate values will not
improve much. If we were to sell our real estate projects in the current market,
we would have losses, 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. Management evaluates strategies
for all its businesses, including real estate, on an ongoing basis.* Competing
demands for our financial resources, changes in the utility industry, and the
proposed merger with Potomac Electric Power Company, are factors we will
consider when we evaluate all diversified business strategies so we use capital
and other resources effectively. Depending on market conditions in the future,
we could also have losses on any future sales.
Applicable accounting rules would require a writedown of a real estate
investment to market value in either of two cases. The first is if we change our
intent about a project from an intent to hold to an intent to sell and the
market value of that project is below book value. The second is if the expected
cash flow from the project is less than the investment in the project.
* In the first quarter of 1997, we wrote down the investment in one of our
projects to market value because we changed our intent about that project. The
write-down is described in detail in the front of this report under The
Constellation Companies -- Power Generation, Real Estate, and Financial
Investments on page 15.
Baltimore Gas and Electric Company and Subsidiaries
55
<PAGE>
Note 13. Fair Value of Financial Instruments
The following table presents the carrying amounts and fair values of financial
instruments included in the Consolidated Balance Sheets.
<TABLE>
<CAPTION>
At December 31, 1996 1995
- -----------------------------------------------------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
(In thousands)
<S> <C>
Cash and cash equivalents $ 66,708 $ 66,708 $ 23,443 $ 23,443
Net accounts receivable 419,479 419,479 400,005 400,005
Other current assets 74,964 74,964 54,070 54,070
Investments and other assets for which it is:
Practicable to estimate fair value 184,487 185,679 149,645 150,170
Not practicable to estimate fair value 62,162 -- 73,042 --
Short-term borrowings 333,185 333,185 279,305 279,305
Current portions of long-term debt and preference stock 280,772 280,772 146,969 146,969
Accounts payable 172,889 172,889 177,092 177,092
Other current liabilities 194,065 194,065 193,992 193,992
Long-term debt 2,758,769 2,767,721 2,598,254 2,694,858
Redeemable preference stock 134,500 141,621 242,000 254,809
</TABLE>
Financial instruments included in other current assets include trading
securities and miscellaneous loans receivable of the Constellation Companies.
Financial instruments included in other current liabilities represent total
current liabilities from the Consolidated Balance Sheets excluding short-term
borrowings, current portions of long-term debt and preference stock, accounts
payable, and accrued vacation costs. The carrying amount of current assets and
current liabilities approximates fair value because of the short maturity of
these instruments.
Investments and other assets include investments in common and preferred
securities, which are classified as financial investments in the Consolidated
Balance Sheets, and the nuclear decommissioning trust fund. The fair value of
investments and other assets is based on quoted market prices where available.
It was not practicable to estimate the fair value of the Constellation
Companies' investments in several financial partnerships which invest in
nonpublic debt and equity securities, investments in several partnerships which
own solar powered energy production facilities, and in an investment in a
company involved in the development of international power projects because the
timing and magnitude of cash flows from these investments are difficult to
predict. These investments are carried at their original cost in the
Consolidated Balance Sheets.
The investments in financial partnerships totaled $48 million and $50 million at
December 31, 1996 and 1995, respectively, representing ownership interests up to
10%. The aggregate assets of these partnerships totaled $6.1 billion at December
31, 1995. The investments in solar powered energy production facility
partnerships totaled $11 million and $22 million at December 31, 1996 and 1995,
respectively, representing ownership interests up to 12%. The aggregate assets
of these partnerships totaled $35 million at December 31, 1995.
The fair value of fixed-rate long-term debt and redeemable preference stock is
estimated using quoted market prices where available or by discounting remaining
cash flows at the current market rate. The carrying amount of variable-rate
long-term debt approximates fair value.
BGE and the Constellation Companies have loan guarantees on outstanding
indebtedness totaling $21 million and $47 million, respectively, at December 31,
1996 and $22 million and $35 million, respectively, at December 31, 1995 for
which it is not practicable to determine fair value. It is not anticipated that
these loan guarantees will need to be funded.
Baltimore Gas and Electric Company and Subsidiaries
56
<PAGE>
Note 14. Quarterly Financial Data (Unaudited)
The following data are unaudited but, in the opinion of Management, include all
adjustments necessary for a fair presentation. BGE's 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 be indicative of overall trends and changes in operations.
<TABLE>
<CAPTION>
Quarter Ended
------------------------------------------------------------- Year Ended
March 31 June 30 September 30 December 31 December 31
- -------------------------------------------------------------------------------------------------------------------------
(In thousands, except per-share amounts)
<S> <C>
1996
Revenues $861,330 $731,707 $825,960 $734,250 $3,153,247
Income from operations 201,315 148,637 275,667 43,846 669,465
Net income 100,781 64,553 146,482 (992) 310,824
Earnings applicable to common stock 91,118 52,448 137,862 (9,140) 272,288
Earnings per share of common stock 0.62 0.36 .93 (.06) 1.85
=============================================================================
1995
Revenues $717,806 $642,500 $848,781 $725,712 $2,934,799
Income from operations 148,222 120,920 299,744 126,806 695,692
Net income 70,854 50,889 163,335 52,929 338,007
Earnings applicable to common stock 60,902 40,937 153,104 42,486 297,429
Earnings per share of common stock 0.41 0.28 1.04 0.29 2.02
=============================================================================
</TABLE>
1996
Results for the second quarter reflect:
(bullet) the $4.5 million after-tax write-off of disallowed replacement energy
costs (see Note 1).
(bullet) the $14.6 million after-tax gain on the sale by a Constellation
partnership of a power purchase agreement (see Note 3).
(bullet) the $7.0 million and $3.0 million after-tax write-offs by the
Constellation Companies of the investment in two geothermal wholesale
power generating plants and the development costs of a proposed
coal-fired power project, respectively (see Note 3).
Results for the third quarter reflect the $6.2 million after-tax write-off by
the Constellation Companies of a portion of a solar power project investment
(see Note 3).
Results for the fourth quarter reflect the $57.6 million after-tax write-off of
disallowed replacement energy costs (see Note 1).
1995
Results for the third quarter reflect the $9.7 million after-tax write-off of
certain Perryman costs (see Note 1).
Baltimore Gas and Electric Company and Subsidiaries
57
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Directors
---------
The following are the Directors of BGE on the date of this report. They
were each elected at BGE's 1996 Annual Meeting of Shareholders. We expect the
pending Merger with PEPCO to close prior to the expiration of their terms of
office. Should the Merger be delayed, these terms would expire at BGE's 1997
Annual Meeting of Shareholders which would be held during the period of August
18th through September 16th.
H. FURLONG BALDWIN, age 65, currently serves as Chairman of the Board and Chief
Executive Officer of Mercantile Bankshares Corporation (a bank holding
company), positions he has held since 1984 and 1976, respectively, and as
Chairman of the Board and Chief Executive Officer of Mercantile-Safe
Deposit and Trust Company, positions he attained in 1976. Mr. Baldwin also
serves as a director of GRC International, Inc., USF&G Corporation,
Conrail, Inc., Offitbank, Wills Group, and Constellation Holdings, Inc. Mr.
Baldwin has been a director of the Company since 1988 and is a member of
the Executive Committee and is the Chairman of the Long Range Strategy
Committee.
BEVERLY B. BYRON, age 64, served for seven successive terms as a Congresswoman
to the United States House of Representatives from 1978 to 1992. She is a
director of McDonnell Douglas Corp., Farmers & Mechanics Bank, and UNC
Incorporated. Mrs. Byron has been a director of the Company since 1993 and
is a member of the Audit Committee, the Committee on Nuclear Power and is
the Chairwoman of the Committee on Workplace Diversity.
J. OWEN COLE, age 67, currently serves as Chairman of the Board of Blue Cross
and Blue Shield of Maryland, a position he has held since January 1995. In
addition, Mr. Cole serves as Chairman of the Trust Committee of the Board
of Directors of both First Maryland Bancorp (a bank holding company) and
The First National Bank of Maryland, positions he has held since 1994. From
1988 to 1994, Mr. Cole served as Chairman of the Executive Committee of the
Board of Directors of both First Maryland Bancorp and The First National
Bank of Maryland. Mr. Cole has been a director of the Company since 1977
and is the Chairman of the Audit Committee and a member of the Committee on
Management.
DAN A. COLUSSY, age 65, currently serves as Chairman of the Board, President and
Chief Executive Officer of UNC Incorporated (aviation services). He was
elected Chief Executive Officer in 1984, Chairman of the Board in 1989,
served as President from 1984 to September 1994, and currently serves as
President since October 1995. Mr. Colussy also serves as Chairman-Elect and
director of Blue Cross and Blue Shield of Maryland. He has been a director
of the Company since 1992 and is a member of the Committee on Management
and the Chairman of the Committee on Nuclear Power.
EDWARD A. CROOKE, age 58, currently serves as President and Chief Operating
Officer of the Company. Mr. Crooke has been President of the Company since
1988 and Chief Operating Officer since 1992. He is also Chairman of the
Board of BGE Home Products & Services, Inc., and Chairman of the Board and
Chief Executive Officer of Constellation Energy Source, Inc. (formerly
named BNG, Inc.), positions he attained in 1994. In addition, Mr. Crooke is
Chairman of the Board of BGE Energy Projects & Services, Inc., a position
he attained in November 1995 and is Chairman of the Board of Constellation
Holdings, Inc., a position he attained in January 1996. Mr. Crooke serves
as a director of First Maryland Bancorp, The First National Bank of
Maryland, AEGIS Insurance Services, Associated Electric & Gas Insurance
Services, Limited, and Baltimore Equitable Society. Mr. Crooke has been a
director of the Company since 1988 and is a member of the Executive
Committee.
JAMES R. CURTISS, age 43, currently is a partner in the law firm of Winston &
Strawn, a position he attained in 1993. From 1988 to 1993, he served as a
Commissioner of the United States Nuclear Regulatory Commission. Mr.
Curtiss is also a director of Cameco Corporation. He has been a director of
the Company since 1994 and is a member of the Committee on Nuclear Power
and the Committee on Workplace Diversity.
58
<PAGE>
JEROME W. GECKLE, age 67, was Chairman of the Board of PHH Corporation (vehicle,
relocation, and management services) from 1979 to 1989. Now retired, Mr.
Geckle serves as a director of First Maryland Bancorp, The First National
Bank of Maryland, and Constellation Holdings, Inc. Mr. Geckle has been a
director of the Company since 1980 and is the Chairman of the Committee on
Management and a member of the Long Range Strategy Committee.
DR. FREEMAN A. HRABOWSKI, III, age 46, currently serves as the President of the
University of Maryland Baltimore County, a position he attained in 1993.
Previously, he served as Interim President from 1992 to 1993 and Executive
Vice President from 1990 to 1992. Dr. Hrabowski is also a director of the
Baltimore Equitable Society, Mercantile Bankshares Corporation, and UNC
Incorporated. He has served as a director of the Company since 1994 and is
a member of the Audit and Executive Committees and the Committee on
Workplace Diversity.
NANCY LAMPTON, age 54, currently serves as Chairman and Chief Executive Officer
of American Life and Accident Insurance Company of Kentucky, a position she
attained in 1971. Ms. Lampton is also a director of Bank One Kentucky,
Brinly-Hardy, and Duff & Phelps Utility Income Fund, Inc. She has served as
a director of the Company since 1994 and is a member of the Long Range
Strategy Committee and the Committee on Workplace Diversity.
GEORGE V. MCGOWAN, age 69, served as Chairman of the Board and Chief Executive
Officer of the Company and Chairman of the Board of Constellation Holdings,
Inc., from 1988 to 1992. Mr. McGowan is a director of The Baltimore Life
Insurance Company, Life of Maryland, Inc., McCormick & Company, Inc.,
NationsBank, N.A., Organization Resources Counselors, Inc., and UNC
Incorporated. Mr. McGowan has been a director of the Company since 1980 and
is the Chairman of the Executive Committee and a member of the Committee on
Nuclear Power.
CHRISTIAN H. POINDEXTER, age 58, currently serves as Chairman of the Board and
Chief Executive Officer of the Company, positions he attained in 1993,
after serving as Vice Chairman of the Board, a position he held since 1989.
Mr. Poindexter is also a director of BGE Home Products & Services, Inc., a
position he attained in 1994, and is a director of BGE Energy Projects &
Services, Inc., a position he attained in November 1995. Currently, Mr.
Poindexter serves as a director of Constellation Holdings, Inc., after
serving as Chairman of the Board from 1993 to January 1996. In addition,
Mr. Poindexter serves as a director of Dome Corporation, Johns Hopkins
Medicine Board, Mercantile Bankshares Corporation, Mercantile Mortgage
Corporation, and Mercantile-Safe Deposit and Trust Company, Nuclear
Electric Insurance Limited, and Nuclear Mutual Limited Insurance Company.
Mr. Poindexter has been a director of the Company since 1988 and is a
member of the Executive Committee.
GEORGE L. RUSSELL, JR., age 67, currently is a partner in the law firm of Piper
& Marbury L.L.P., a position he attained in 1986. Mr. Russell is also a
director of the Federal Reserve Bank of Richmond. He has been a director of
the Company since 1988 and is a member of the Audit and the Executive
Committees.
MICHAEL D. SULLIVAN, age 57, currently is Chairman of the Board of Golf America
Stores, Inc. (golf apparel retailing), a position he attained in October
1996. He is also Chairman of the Board and Chief Executive Officer of
Lombardi Research Group, LLC (hair care products), positions he attained in
1995. Mr. Sullivan was Chairman of the Board of Waye Laboratories, Inc.
(hair restoration) from January 1995 to June 1995. In addition, Mr.
Sullivan was Chief Executive Officer and President, from 1982 to 1994, of
Merry-Go-Round Enterprises, Inc. (specialty retailing). That company filed
a reorganization petition under Chapter XI of the Federal Bankruptcy law in
January 1994, and subsequently announced a bankruptcy liquidation. Mr.
Sullivan has been a director of the Company since 1992 and is a member of
the Committee on Management and the Long Range Strategy Committee.
BOARD OF DIRECTORS COMMITTEES, MEETINGS, AND FEES
The Executive Committee of the Board of Directors may exercise most of the
powers of the Board of Directors in the management of the business and affairs
of the Company in the intervals between meetings of the full Board. The
Committee, however, may not declare dividends, authorize the issuance of stock,
recommend to shareholders any action requiring shareholders' approval, amend the
by-laws, or approve mergers.
The Audit Committee of the Board of Directors, comprised of outside
directors, recommends an auditing firm to be engaged, discusses the scope of the
examination with that firm, and reviews the annual financial
59
<PAGE>
statements with the auditing firm and with Management of the Company.
Additionally, the Committee meets with the Manager of the Auditing Department of
the Company to ensure that an adequate program of internal auditing is being
carried out, and invites comments and recommendations from the auditing firm
concerning the system of internal controls and accounting procedures. The Audit
Committee reports on its activities periodically to the Board of Directors.
The Committee on Nuclear Power monitors the performance and safety of the
Company's Calvert Cliffs Nuclear Power Plant. The Committee meets periodically,
usually on-site at the Calvert Cliffs plant, to confer with Management, senior
plant management, and other nuclear oversight personnel. Following each meeting,
the Committee reports the results of its observations and findings to the Board
of Directors and makes such recommendations as it deems appropriate.
The Committee on Management's duties include recommending to the Board of
Directors nominees for election as directors and officers and making
recommendations concerning remuneration arrangements for directors and officers
of the Company. This Committee, which is comprised of outside directors,
considers nominees recommended by shareholders; such recommendations should be
submitted in writing to the attention of the Corporate Secretary, Baltimore Gas
and Electric Company, 39 West Lexington Street, Baltimore, Maryland 21201.
The Committee on Workplace Diversity provides an ongoing Board of
Directors' perspective of management's progress in achieving employee diversity
goals. The Committee provides input to management in setting goals and
developing strategies to increase goal attainment, provides oversight on
implementation of strategies, and evaluates results. The Committee on Workplace
Diversity reports on its activities periodically to the Board of Directors.
The Long Range Strategy Committee provides an oversight role in the
development of the Company's long range strategic goals. The Committee meets
periodically to review the continued appropriateness of these goals and to
approve presentations to the Board regarding the implementation of significant
strategic initiatives. This Committee also reviews major regulatory,
environmental and public policy issues as well as technology advances which may
impact Company operations. The Long Range Strategy Committee reports on its
activities periodically to the Board of Directors.
The Board of Directors met nine times during 1996 for regularly scheduled
meetings. The Committee on Management and the Audit Committee each met four
times, the Committee on Nuclear Power met three times, and the Committee on
Workplace Diversity and the Executive Committee each met two times. Each of the
directors attended 75% or more of the total number of meetings of the Board and
of any committees on which the director served.
Each director, who is not an officer or employee of the Company or its
subsidiaries, receives a fee of $1,000 for each regular, committee, or special
meeting of the Board attended and a retainer fee of $18,000 per year, payable
quarterly. Each committee chairman receives an additional annual retainer fee of
$3,000 per year, payable quarterly. Each director may be reimbursed for
reasonable travel expenses incidental to attendance at meetings. Each director
who is not an officer or employee may elect to defer receipt of any portion of
the fees earned. In addition, the Company maintains a director retirement plan.
Under this plan, non-employee directors with at least five years of service
receive an annual retirement benefit for life equal to the annual Board retainer
in effect at the time of the director's retirement from the Board. Benefit
payments begin at the director's date of retirement or at age 65, whichever is
later. The Company also provides an automobile to Mr. McGowan, a director who
retired on December 31, 1992 as Chairman of the Board and Chief Executive
Officer of the Company and who continues to participate in civic and community
activities on behalf of the Company. The approximate yearly cost to the Company
is $7,908.
Executive Officers
------------------
Executive Officers of BGE at the date of this report are:
<TABLE>
<CAPTION>
OTHER OFFICES OR POSITIONS
NAME AGE PRESENT OFFICE HELD DURING PAST FIVE YEARS
---- --- -------------- ---------------------------
<S><C>
Christian H. Poindexter 58 Chairman of the Board (A) Vice Chairman of the Board
(Since January 1, 1993)
</TABLE>
60
<PAGE>
<TABLE>
<CAPTION>
OTHER OFFICES OR POSITIONS
NAME AGE PRESENT OFFICE HELD DURING PAST FIVE YEARS
---- --- -------------- ---------------------------
<S><C>
Edward A. Crooke 58 Chairman of the Board - President, Utility Operations
Subsidiaries and President (B)
(Since January 1, 1996)
Bruce M. Ambler 57 President and Chief Executive
Officer
Constellation Holdings, Inc.
(Since August 1, 1989)
George C. Creel 63 Executive Vice President Senior Vice President, Generation
and Acting Chief Operating Vice President, Nuclear Energy
Officer
(Since January 1, 1996)
Charles W. Shivery 51 President Vice President
BGE Corp. and President Finance and Accounting,
and Chief Executive Chief Financial Officer and
Officer Constellation Power Secretary
Source, Inc. Vice President and Treasurer,
(Since February 25, 1997) Corporate Finance Group
Robert E. Denton 54 Senior Vice President Vice President, Nuclear Energy
Generation Plant General Manager, Calvert
(Since January 1, 1996) Cliffs Nuclear Power Plant
Thomas F. Brady 47 Vice President Vice President, Customer Service
Customer Service and and Accounting
Distribution Vice President, Accounting and
(Since July 1, 1993) Economics
David A. Brune 56 Vice President General Counsel
Finance and Accounting,
Chief Financial Officer and
Secretary
(Since February 25, 1997)
Charles H. Cruse 52 Vice President Plant General Manager, Calvert
Nuclear Energy Cliffs Nuclear Power Plant
(Since January 1, 1996) Manager, Nuclear Engineering
Carserlo Doyle 54 Vice President Manager, Telecommunications
Electric Interconnection Principal Engineer -- Electric
and Transmission Interconnection
(Since January 1, 1994)
Jon M. Files 61 Vice President
Management Services
(Since September 1, 1981)
Frank O. Heintz 52 Vice President Executive Director, LDC Caucus --
Gas American Gas Association
(Since January 1, 1997) Chairman, Maryland Public Service
Commission
Sharon S. Hostetter 52 Vice President Manager, Marketing
Marketing and Sales Division Manager, Resource
(Since November 1, 1995) Application and Customer
Development Group, Rochester
Gas and Electric Corporation
Ronald W. Lowman 52 Vice President Manager, Fossil Engineering
Fossil Energy Manager, Fossil Engineering
(Since January 1, 1993) Services
G. Dowell Schwartz, Jr. 60 Vice President
General Services
(Since April 1, 1990)
Joseph A. Tiernan 58 Vice President Vice President, Corporate
Corporate Affairs Administration
(Since February 1, 1993)
Stephen F. Wood 44 President and Vice President, Marketing and Sales
Chief Executive Officer Manager, Major Customer Projects
BGE Energy Projects & Manager, System Engineering
Services, Inc. and Construction
(Since November 1, 1995) Manager, Distribution Engineering
Vice President
(Since February 16, 1996)
</TABLE>
61
<PAGE>
- -----------
(A) Chief Executive Officer, Director, and member of the Executive Committee.
(B) Chief Operating Officer, Director, and member of the Executive Committee.
Officers of the Registrant 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.
ITEM 11. EXECUTIVE COMPENSATION
The summary compensation table below (together with important explanatory
notes on the next page) provides information about salary and other
compensation. Following the summary compensation table are tables about
long-term incentive plan awards and pension benefits, a performance graph that
compares BGE common stockholder return to both the S&P 500 Index and the Dow
Jones Electric Utilities Index, and a report by the Committee on Management
about executive compensation.
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
LONG-TERM
ANNUAL COMPENSATION COMPENSATION
------------------- ------------
ALL OTHER
COMPENSATION
(INCLUDES
ONE-
TIME PAYMENT
FOR YEARS
RESTRICTED LTIP 1988-1996;
STOCK AWARD PAYOUT SEE NOTE 3
NAME AND PRINCIPAL POSITION FISCAL (SEE NOTE 1 (SEE NOTE 2 ON NEXT
@ 12/31/96 YEAR SALARY BONUS ON NEXT PAGE) ON NEXT PAGE) PAGE)
--------------------------- ------ ------ ----- ------------- ------------- ------------
<S><C>
Christian H. Poindexter 1996 $ 567,300 $212,500 -0- $ 181,500 $324,799
Chairman of the Board & Chief 1995 $ 537,233 $247,400* -0- N/A $ 31,611
Executive Officer 1994 $ 498,533 $163,000 -0- N/A $ 26,436
Edward A. Crooke 1996 $ 403,400 $150,000 -0- $ 118,800 $252,504
President & Chief Operating 1995 $ 400,567 $184,200* -0- N/A $ 25,217
Officer, Chairman of the Board of 1994 $ 385,067 $125,000 -0- N/A $ 19,089
all non-utility subsidiaries
George C. Creel 1996 $ 316,600 $118,000 -0- $ 72,600 $138,842
Executive Vice President & Acting 1995 $ 265,600 $ 72,900 -0- N/A $ 17,292
Chief Operating Officer 1994 $ 248,867 $ 55,000 -0- N/A $ 11,754
Bruce M. Ambler 1996 $ 315,100 $120,000 -0- $ 180,000 $117,101
President & Chief Executive Officer 1995 $ 298,933 $108,600 -0- N/A $ 17,033
of Constellation Holdings, Inc. 1994 $ 280,133 $ 69,000 -0- N/A $ 11,443
Robert E. Denton 1996 $ 230,567 $ 75,100 -0- $ 38,500 $ 70,899
Senior Vice President -- Generation 1995 $ 196,933 $ 55,000 -0- N/A $ 10,785
1994 $ 172,467 $ 36,000 -0- N/A $ 7,090
</TABLE>
- -----------
* These amounts include a $ 100,000 bonus for Mr. Poindexter and a $ 75,000
bonus for Mr. Crooke for their work in connection with the Merger.
62
<PAGE>
NOTES TO SUMMARY COMPENSATION TABLE
(1) At December 31, 1996, Mr. Poindexter held 26,635 shares of performance-based
Restricted Stock with a value of $712,486, Mr. Crooke held 19,085 shares of
performance-based Restricted Stock with a value of $510,524, Mr. Creel held
17,224 shares of performance-based Restricted Stock with a value of
$460,742, Mr. Ambler held 16,401 shares of performance-based Restricted
Stock with a value of $438,727, and Mr. Denton held 12,952 shares of
performance-based Restricted Stock with a value of $346,466. Dividends on
performance-based Restricted Stock Awards are accumulated during the
performance period, reinvested in BGE shares, and reflected in the preceding
shares and values. Additional awards were granted effective February 12,
1997 as described below in the Long-Term Incentive Plan Table.
(2) The amounts in the LTIP PAYOUT column were paid for performance during the
1994-1996 period.
(3) The amounts in the ALL OTHER COMPENSATION COLUMN include the Company match
under the Company's savings plans; the interest on the cumulative corporate
funds used to pay annual premiums on policies providing split-dollar life
insurance benefits (calculated at the Internal Revenue Service's blended
rate); and a contribution to a trust securing the executives' supplemental
pension benefits. These amounts also include a one-time contribution by BGE
to fund a trust that was established in 1996 to secure executives'
nonqualified deferred compensation plan benefits. The nonqualified deferred
compensation plan was put in place in 1988 to permit executives to defer
compensation and establish phantom investment accounts equivalent to the
compensation being deferred. The amount of the funding is equal to the
interest, dividends and capital appreciation recorded in those accounts
since 1988. A breakdown of the 1996 amounts in the ALL OTHER COMPENSATION
column is shown on the chart below -- notes (a), (b), and (c) under the
chart include important background data. Both the chart and the background
data are needed to understand the numbers in the ALL OTHER COMPENSATION
column.
<TABLE>
<CAPTION>
SUPPLEMENTAL DEFERRED
COMPANY MATCH AND PENSION TRUST COMPENSATION TRUST
SPLIT DOLLAR AMOUNTS CONTRIBUTION CONTRIBUTION
(A) (B) (C) TOTAL
-------------------- ------------- ------------------ ---------
<S><C>
Christian H. Poindexter...................... $41,541 $53,999 $229,259 $324,799
Edward A. Crooke............................. 33,387 53,999 165,118 252,504
George C. Creel.............................. 24,477 53,999 60,366 138,842
Bruce M. Ambler.............................. 22,442 53,999 40,660 117,101
Robert E. Denton............................. 14,985 53,999 1,915 70,899
</TABLE>
- -----------
(a) The Company match and split-dollar amounts shown in column (a) above were
the only items included in the ALL OTHER COMPENSATION column for 1995 and
1994.
(b) An initial contribution to the trust securing supplemental pension
benefits -- shown in column (b) above -- was made during 1996. Therefore,
there were no trust contributions included in the ALL OTHER COMPENSATION
column for 1995 or 1994.
(c) A ONE-TIME contribution was made during 1996 to the trust securing deferred
compensation plan benefits equal to the interest, dividends and capital
appreciation on plan accounts SINCE 1988. Therefore, there were no trust
contributions included in the ALL OTHER COMPENSATION column for 1995 or
1994.
63
<PAGE>
LONG-TERM INCENTIVE PLAN TABLE
The Committee on Management, effective February 12, 1997, made grants of
performance-based restricted shares under the Long-Term Incentive Plan.
For each named executive, the grants are subject to both performance and
time (3 years) contingencies. For all but Mr. Ambler, performance will be
measured by comparing BGE's total shareholder return to the Dow Jones Electric
Utilities Index. Both are shown in the performance graph on page 66. A threshold
award will be earned if the BGE three-year cumulative total shareholder return
percentile rank is at the 50th percentile, progressing to a maximum award for a
return at or above the 75th percentile. At the Merger effective date, the shares
of restricted BGE stock outstanding will be converted to shares of restricted
Constellation Energy Corporation common stock, using the Merger conversion
ratio: one share of Constellation Energy Corporation common stock for each share
of BGE common stock. After the Merger effective date, the total shareholder
return measure will be based upon the return taking into account the growth in
common stock value of Constellation Energy Corporation and dividends. For Mr.
Ambler, the performance will be measured by comparing BGE's total shareholder
return to the Dow Jones Electric Utilities Index and on Constellation Holdings'
return on equity over the performance period.
Pursuant to the grants, restricted shares were issued equivalent to the
number of shares that will be earned if "target" performance (62.5th percentile)
is achieved. These restricted shares will be forfeited in whole or part, if
performance is below target. Dividends on the restricted shares will be
accumulated during the performance period and reinvested in BGE shares. Actual
dividends awarded at the end of the performance period will be based upon
performance and paid in stock (except that the recipients may elect to have a
portion of the shares withheld to satisfy tax withholding requirements).
Additional shares, up to the maximum number noted below, will be awarded if
performance is above target at the end of the 1997-1999 performance period.
Dividend equivalents from the date of the grant will be paid for any additional
shares that are awarded.
<TABLE>
<CAPTION>
PERFORMANCE
NAME MINIMUM(A) TARGET(A) MAXIMUM(A) PERIOD
---- ---------- --------- ---------- -----------
<S><C>
C.H. Poindexter............................................. 6,500 13,000 19,500 3 years
E.A. Crooke................................................. 4,500 9,000 13,500 3 years
G.C. Creel.................................................. 4,500 9,000 13,500 3 years
B.M. Ambler................................................. 3,500 7,000 10,500 3 years
R.E. Denton................................................. 2,500 5,000 7,500 3 years
</TABLE>
- -----------
(A) The target number of shares have been issued. If fewer shares are actually
earned during the performance period, all or some shares will be forfeited;
if additional shares are actually earned during the performance period,
additional shares, up to the maximum listed, will be issued.
PENSION BENEFITS
The following table shows annual pension benefits payable upon normal
retirement to executives, including the five individuals named in the Summary
Compensation Table. Normal retirement occurs at age 65 for Messrs. Poindexter,
Crooke, and Ambler, and at age 62 for all other executives. Pension benefits are
computed at 60% of total final average salary plus bonus for Messrs. Poindexter,
Crooke, and Ambler, without regard to years of service. Pension benefits are
computed at 55% of total final average salary plus bonus for Mr. Creel, who has
attained the maximum credited years of service. Pension benefits are computed at
50% of total final average salary plus bonus for Mr. Denton and, when he attains
30 years service in 2000, will be computed at 55%.
64
<PAGE>
<TABLE>
<CAPTION>
TOTAL FINAL PERCENTAGE OF FINAL AVERAGE SALARY AND BONUS
SALARY AND --------------------------------------------
BONUS 50% 55% 60%
- ----------- --- --- ---
<S><C>
$ 300,000 $ 150,000 $ 165,000 $ 180,000
325,000 162,500 178,750 195,000
350,000 175,000 192,500 210,000
400,000 200,000 220,000 240,000
425,000 212,500 233,750 255,000
450,000 225,000 247,500 270,000
500,000 250,000 275,000 300,000
550,000 275,000 302,500 330,000
575,000 287,500 316,250 345,000
600,000 300,000 330,000 360,000
650,000 325,000 357,500 390,000
700,000 350,000 385,000 420,000
750,000 375,000 412,500 450,000
775,000 387,500 426,250 465,000
800,000 400,000 440,000 480,000
850,000 425,000 467,500 510,000
900,000 450,000 495,000 540,000
950,000 475,000 522,500 570,000
</TABLE>
Salary and bonus are calculated in the same manner shown in the Summary
Compensation Table. There is no offset of pension benefits for social security
or other amounts.
SECURING EXECUTIVE BENEFITS
During 1994, the Company implemented a program to secure the supplemental
pension benefits for each of the executive officers, including those listed in
the Summary Compensation Table. During 1996, the Company implemented a program
to secure deferred compensation of executive officers including those listed in
the Summary Compensation Table. These programs do not increase the amount of
supplemental pension benefits or deferred compensation. In the past, both
supplemental pension benefits and deferred compensation were unfunded -- that
means no money was set aside on behalf of the executive as he earned the
benefit, and the benefits were paid from the Company's general funds when the
executive retired. To provide security, accrued supplemental pension benefits
and deferred compensation are now being funded through a trust at the time they
are earned. An executive officer's accrued benefits in the supplemental pension
trust become vested when any of these events occur: retirement eligibility;
termination, demotion or loss of benefit eligibility without cause; a change of
control of the Company followed within two years by the executive's demotion,
termination or loss of benefit eligibility; or reduction of previously accrued
benefits. As a result of becoming vested, the executive would be entitled to a
payout of the vested amount from the supplemental pension trust upon the later
of age 55 or employment termination. An executive's benefits under the deferred
compensation plan always are fully vested and are payable at employment
termination. Payments to these trusts are included in the Summary Compensation
Table in the "All Other Compensation" column.
AGREEMENTS RELATING TO THE MERGER
In connection with the Merger, Messrs. Poindexter and Crooke each signed an
employment agreement dated as of September 22, 1995 with Constellation Energy
Corporation. Mr. Poindexter's agreement provides that he will serve as Chief
Executive Officer from the time the Merger is completed and that he will become
Chairman one year after the Merger is completed. Mr. Crooke's agreement provides
that he will serve as Vice Chairman of Constellation Energy Corporation and also
as Chairman of all the non-utility subsidiaries. These agreements remain in
effect for five years after the Merger is completed.
In December 1995, BGE entered into severance agreements with 15 key
employees. The agreements become binding on Constellation Energy Corporation at
the time the Merger is completed and remain in effect for two years thereafter.
The severance agreements provide for the payment of severance benefits to the
executive under certain circumstances including, but not limited to, the
following (i) upon termination of
65
<PAGE>
employment (other than for cause, death, disability or the executive's voluntary
termination of employment without "good reason") within the two year period
following the time the Merger is completed or (ii) termination of the
executive's employment without cause or the executive's voluntary termination
following the occurrence of certain events that constitute "good reason" prior
to the time the Merger is completed.
Four of the 15 key employees who have severance agreements with BGE are
retiring when the Merger closes and are entitled to severance benefits. All
other key employees who have severance agreements have been offered, and
accepted, executive positions with Constellation Energy Corporation and will not
be eligible for severance benefits when the Merger closes. If the four retiring
employees had been terminated as of December 31, 1996, under circumstances
giving rise to an entitlement to benefits thereunder, the aggregate value of
such benefits would have been approximately: $750,000 for Mr. Creel, and an
aggregate of $2 million for the other executives, none of whom is named in the
Summary Compensation Table.
PERFORMANCE GRAPH
The following graph assumes $100 was invested on December 31, 1991 in
Baltimore Gas and Electric Company common stock, S&P 500 Index and Dow Jones
Electric Utilities Index. Total return is computed assuming reinvestment of
dividends.
[Graph appears here--plot points are listed below]
Dow Jones
Year BGE Electric Utility Index S&P 500
- ---- --- ---------------------- -------
1991 100 100 100
1992 109 107 108
1993 126 119 118
1994 117 105 120
1995 161 138 165
1996 160 139 203
REPORT OF COMMITTEE ON MANAGEMENT
REGARDING EXECUTIVE COMPENSATION
The Committee on Management, made up completely of outside Directors, is
responsible for executive compensation policies. In addition to establishing
policies, the Committee approves all compensation plans and recommends to the
Board of Directors specific salary amounts and other compensation awards for
individual executives.
The Committee designs compensation policies to encourage executives to
manage BGE in the best long-term interests of shareholders and to allow BGE to
attract and retain executives best suited to lead BGE in a changing industry.
66
<PAGE>
The Committee determined that the relevant labor market for executives is
the utility industry. Utilities used for comparison in 1996 were electric
utilities and combination electric/gas utilities that have annual revenues in
the $2-5 billion range, adjusted by using regression analysis to account for
BGE's size. These utilities are thought to best represent the portion of the
executive labor market in which BGE competes. All of these utilities are
included in the Dow Jones Electric Utilities Index shown on the Performance
Graph.
The Committee's philosophy is that base salary should approximate the
middle of that labor market for average performance, and that short-term and
long-term incentive awards for superior performance should bring total
compensation to approximately the 75th percentile of the labor market. Total
compensation is made up of three components: base salary, short-term incentive
awards, and long-term incentive awards. As described below, corporate
performance is one of the criteria used by the Committee in determining base
salary, and it is a key component in determining both short-term and long-term
incentive awards.
The Committee has retained an outside executive compensation consultant
since 1993. He provides information and advice on a regular basis. In addition,
internal compensation analysts (certified by the American Compensation
Association) use survey data, outside consultants, and other resources to make
recommendations to the Committee.
Base salary ranges did not change for the named executives in 1996 except
Mr. Creel. He was elected Executive Vice President and named acting Chief
Operating Officer during 1996 to allow Mr. Crooke time for leading the Merger
transition team. Both his salary range and his base salary were increased to
reflect these new responsibilities.
Salary increases during 1996 for Mr. Poindexter and the other named
executives were based upon 1995 corporate performance (consolidated corporate
earnings from ongoing operations increased 4.5%, or $.09 per share, in 1995
compared to 1994, and utility earnings from ongoing operations increased 1.6%,
or $0.03 per share, in 1995 compared to 1994), and the corporate response to
changes in the industry and the regulatory environment. Mr. Poindexter's base
salary increase of 5.6% moved him to the middle third of his salary range.
Bonus payments to Mr. Poindexter and other executives represent the
short-term incentive component of executive compensation. The Committee sets
short-term incentive amounts, as well as the mix among base salary, short-term
incentive compensation and long-term incentive compensation, to bring total
compensation in line with survey data for the relevant labor market. For 1996
short-term incentive awards, the Committee determined that the appropriate
measure for earnings was earnings from ongoing operations. This had the effect
of eliminating the $.42 per share reduction related to the write-off of $83
million for deferred fuel costs from the extended 1989-1991 outage at BGE's
Calvert Cliff's nuclear power plant. In making this decision, the Committee gave
weight to the following facts: (a) the $118 million settlement amount (the $83
million written off in 1996 plus the $35 million reserve taken in 1990) is
considerably lower than initial demands of People's Counsel ($458 million) and
PSC Staff ($200 million), (b) the total maintenance performed during the
extended outage resulted in the plant being in excellent operating condition, as
evidenced by its good operating history since the end of the extended outage,
(c) leadership provided by the executives to the team that handled the
litigation and negotiated the settlement. Mr. Poindexter's, Mr. Crooke's, and
Mr. Creel's short-term bonuses were based on two factors of equal importance:
corporate earnings (an increase of 8.6%, or $.18 per share, in 1996 compared to
1995); and corporate business plan performance in the following areas: customer
satisfaction, innovation, and internal business perspectives. Mr. Shivery's
short-term incentive bonus was based upon two factors of equal importance:
higher consolidated corporate earnings as described above, and achievement of
operational targets contained in the finance and accounting division's business
plan. Mr. Ambler's bonus was based upon net income from Constellation Holdings
($42.3 million in 1996, an increase of 56.1%, compared to $27.1 million in 1995)
weighted at 50%; higher consolidated corporate earnings as described above,
weighted at 20%; and operational targets contained in Constellation Holdings'
business plan weighted at 30%.
Early this year the named executives received cash long-term bonuses for
the 1994-1996 performance period. These awards were earned under a cash
Long-Term Performance Program for executive officers, including Mr. Poindexter,
adopted in 1993. The Program was designed to tie the awards directly to total
shareholder return. These awards were the only awards made under the Program.
Program objectives for Messrs. Poindexter, Crooke, Creel, and Shivery are based
upon BGE total shareholder return during the period 1994-1996 compared to total
shareholder return for the other companies included in the Dow Jones Electric
Utilities Index (one of the indices used in the Performance Graph). Performance
(61st percentile)
67
<PAGE>
exceeded the target of (60th percentile) and produced awards that were slightly
above target. For Mr. Ambler, the performance objectives measured improvement in
Constellation Holdings' net income over the same three year period. He received
a maximum award based upon an improvement in net income of 255%. Awards to the
named executives are disclosed in the column of the Summary Compensation Table
titled LONG-TERM COMPENSATION -- LTIP PAYOUT.
The current Long-Term Incentive Plan was approved by the shareholders at
the 1995 Annual Meeting of Shareholders and will be in effect until 2005. The
Committee specifically included numerous features in the Long-Term Incentive
Plan to allow various types of awards keyed to corporate performance, including
performance shares and restricted stock subject to performance-based
contingencies. Awards in 1995 and 1996 of performance-based restricted stock
were granted under the Plan to the named executives and are included in footnote
1 to the Summary Compensation Table on page 63. Awards of performance-based
restricted stock granted in 1997 to the named executives are shown on the
Long-Term Incentive Plan table on page 64. The awards are subject to forfeiture
if corporate performance criteria are not satisfied or if the executive's
employment terminates during the applicable three year performance periods. The
corporate performance criteria for all named executives except Mr. Ambler for
each period is measured by total shareholder return over the performance period
compared to total shareholder return for the other companies included in the Dow
Jones Electric Utilities Index (one of the indices used in the Performance
Graph) and are as follows: a threshold award at the 50th percentile, progressing
to a maximum payout if percentile rank for total shareholder return exceeds the
75th percentile. For Mr. Ambler, the performance objectives for all the awards
measure improvement in Constellation Holdings' net income over the same three
year period.
In making long-term incentive awards the Committee considers the desired
amount of total compensation and the appropriate mix among base salary,
short-term incentive compensation, and long-term incentive compensation. The
Committee sets long-term incentive target amounts to bring total compensation in
line with survey data for the relevant labor market. Measures for
performance-based long-term incentive awards are based upon total shareholder
return.
The Committee evaluated the total director compensation package and,
together with their counterparts from PEPCO, will recommend the compensation
package that makes the most sense for the new company. Matters under
consideration include whether compensation should be paid in stock, cash or a
mix, and what structure (a retainer, meeting fees, and other benefits, if any)
is optimal. The Committee has determined to terminate retirement benefits for
BGE directors in 1997. Any vested benefits will be replaced with annuities
purchased on the termination date; all non-vested benefits will terminate.
Section 162(m) of the Internal Revenue Code limits tax deductions for
executive compensation to $1 million. There are several exemptions to Section
162(m), including one for qualified performance-based compensation. To be
qualified, performance-based compensation must meet various requirements,
including shareholder approval. The Committee has considered annually whether it
should adopt a policy regarding 162(m) and concluded it was not appropriate to
do so. One reason for the conclusion is that, assuming the current compensation
policies and philosophy remain in place, Section 162(m) will not be applicable
in the near term for any executive's compensation. However, the Committee also
notes that while generally it wishes to maximize the deductibility of
compensation, the Committee believes the 162(m) requirements are not fully
consistent with sound executive compensation policy and incentives to improve
shareholder value. Therefore, the Committee may in the future approve incentive
payments that do not qualify for deduction if the recipient's compensation
exceeds the $1 million limit.
Jerome W. Geckle, Chairman Dan A. Colussy
J. Owen Cole Michael D. Sullivan
68
<PAGE>
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth the beneficial ownership of common stock of
the Company of the five executive officers shown in the Summary Compensation
Table on page 62, and all directors and executive officers as a group as of
January 17, 1997. None of such persons beneficially owns shares of any other
class of equity securities of the Company.
<TABLE>
<CAPTION>
BENEFICIAL OWNERSHIP
NAME (SHARES OF COMMON STOCK)(1)
---- ---------------------------
<S><C>
Bruce M. Ambler....................................................................... 36,418(2)
H. Furlong Baldwin.................................................................... 750
Beverly B. Byron...................................................................... 1,000
J. Owen Cole.......................................................................... 4,263
Dan A. Colussy........................................................................ 1,500
George C. Creel....................................................................... 27,150(3)
Edward A. Crooke...................................................................... 64,393(4)
James R. Curtiss...................................................................... 300
Robert E. Denton...................................................................... 24,483
Jerome W. Geckle...................................................................... 6,961
Freeman A. Hrabowski, III............................................................. 550
Nancy Lampton......................................................................... 2,220
George V. McGowan..................................................................... 103,803(5)
Christian H. Poindexter............................................................... 94,772(6)
George L. Russell, Jr................................................................. 1,271
Michael D. Sullivan................................................................... 1,500
All Directors and Executive Officers
as a Group (27 Individuals)......................................................... 556,233
</TABLE>
- -----------
(1) Each of the individuals listed, as well as all directors and executive
officers as a group, beneficially owned less than 1% of the Company's
outstanding common stock. If the individual participates in the Company's
Dividend Reinvestment and Stock Purchase Plan or the Company's Employee
Savings Plan, shares held by such plans on behalf of the participant are
included.
(2) Includes shares awarded under the Company's Long-Term Incentive Plan.
(3) Includes shares awarded under the Company's Long-Term Incentive Plan. Of the
total shares, 11,848 shares are held in the name of Mr. Creel's wife of
which Mr. Creel disclaims beneficial ownership.
(4) Includes shares awarded under the Company's Long-Term Incentive Plan. Of the
total shares, 1,057 shares are beneficially owned by Mr. Crooke with his
wife, and 3,000 shares are held in trust which Mr. Crooke votes.
(5) 1,476 shares are beneficially owned by Mr. McGowan with his wife. He owns
the other shares directly.
(6) Includes shares awarded under the Company's Long-Term Incentive Plan. Of the
total shares, 18,600 shares are held in the name of Mr. Poindexter's wife,
and 12,000 shares are held as trustee.
On September 22, 1995, BGE and Potomac Electric Power Company ("PEPCO")
signed reciprocal stock option agreements in connection with the proposed Merger
("the Merger") of BGE and PEPCO with and into Constellation Energy Corporation
(formerly named RH Acquisition Corp.). Pursuant to the stock option agreements,
BGE granted PEPCO an irrevocable option to purchase up to 29,357,896 shares of
BGE common stock under certain circumstances if the Agreement and Plan of Merger
dated as of September 22, 1995 ("the Merger Agreement") becomes terminable.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Company and certain of its subsidiaries paid legal fees to the law firm
of Piper & Marbury L. L. P. of which Mr. George L. Russell, Jr., a Company
director, is a partner. It is expected that the Company and subsidiaries will
continue to do business with this firm in 1997.
69
<PAGE>
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 17, 1997 of Coopers & Lybrand
L.L.P.
Consolidated Statements of Income for three years ended December 31, 1996
Consolidated Balance Sheets at December 31, 1996 and December 31, 1995
Consolidated Statements of Cash Flows for three years ended December 31, 1996
Consolidated Statements of Common Shareholders' Equity for three years ended
December 31, 1996
Consolidated Statements of Capitalization at December 31, 1996 and December
31, 1995
Consolidated Statements of Income Taxes for three years ended December 31,
1996
Notes to Consolidated Financial Statements
2. Financial Statement Schedules:
Schedule II -- Valuation and Qualifying Accounts
Schedules other than those listed above are omitted as not applicable or not
required.
3. Exhibits Required by Item 601 of Regulation S-K Including Each Management
Contract or Compensatory Plan or Arrangement Required to be Filed as an
Exhibit.
70
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT
NUMBER
- -------
<S><C>
*2(a) -- Agreement and Plan of Merger dated as of September 22, 1995, by and among Baltimore Gas and Electric
Company, Potomac Electric Power Company, and RH Acquisition Corp. (Designated as Exhibit A in the
Joint Proxy Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which
was filed as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective
February 9, 1996, Registration No. 33-64799.)
*2(b) -- BGE Stock Option Agreement dated as of September 22, 1995, by and between Baltimore Gas and Electric
Company and Potomac Electric Power Company. (Designated as Exhibit B1 in the Joint Proxy Statement of
Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed as part of
Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9, 1996,
Registration No. 33-64799.)
*2(c) -- PEPCO Stock Option Agreement dated as of September 22, 1995, by and between Baltimore Gas and
Electric Company and Potomac Electric Power Company. (Designated as Exhibit B2 in the Joint Proxy
Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed
as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective February
9, 1996, Registration No. 33-64799.)
*2(d) -- Registration Statement on Form S-4 of Constellation Energy Corporation, as amended, which became
effective February 9, 1996, Registration 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 April 18, 1995. (Designated as Exhibit No. 3(b) in Form 10-Q dated May
11, 1995, 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:
</TABLE>
<TABLE>
<CAPTION>
DESIGNATED IN
--------------------------------------------------------------------------
EXHIBIT
DATED FILE NO. NUMBER
----- -------- -------
<S><C>
*August 1, 1967 1-1910 (Form 10-K Annual Report for 1967) D-1
*January 1, 1972 1-1910 (Form 10-K Annual Report for 1971) A-2
*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
</TABLE>
<TABLE>
<S><C>
*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).)
*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.)
</TABLE>
71
<PAGE>
<TABLE>
<S><C>
*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.
*10(e) -- Baltimore and Gas and Electric Company Nonqualified Deferred Compensation Plan for Non-Employee
Directors (formerly Baltimore Gas and Electric Company Deferred Compensation Plan for Non-Employee
Directors). (Designated as Exhibit No. 10(f) to the Annual Report on Form 10-K for the year ended
December 31, 1993, 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.)
*10(g) -- Summary of Baltimore Gas and Electric Company Long Term Performance Program. (Designated as Exhibit
No. 10(h) to the Annual Report on Form 10-K for the year ended December 31, 1993, File No. 1-1910.)
*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) -- Summary 1994-96 Long Term Incentive Plan of Constellation Holdings, Inc. (Designated as Exhibit No.
10(l) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.)
*10(k) -- Employment Agreement of Christian H. Poindexter. (Designated as Exhibit C2 in the Joint Proxy
Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed
as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective February
9, 1996, Registration No. 33-64799.)
*10(l) -- Employment Agreement of Edward A. Crooke. (Designated as Exhibit C3 in the Joint Proxy Statement of
Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed as part of
Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9, 1996,
Registration No. 33-64799.)
*10(m) -- Severance Agreements between BGE and 15 key employees. (Designated as Exhibit No. 10(o) to the Annual
Report on Form 10-K for the year ended December 31, 1995, File No. 1-1910.)
*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 Coopers & Lybrand L.L.P., 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.)
*99(b) -- Corporations and Associations Article, Section 2-418 of the Annotated Code of Maryland. (Designated
as Exhibit 28(b) to the Annual Report on Form 10-K for the year ended December 31, 1987, File No.
1-1910.)
</TABLE>
- ----------
*Incorporated by Reference.
(b) Reports on Form 8-K:
<TABLE>
<CAPTION>
DATE FILED ITEM REPORTED
---------- -------------
<S><C>
December 30, 1996 Item 5. Other Events
</TABLE>
72
<PAGE>
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
<TABLE>
<CAPTION>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- -------------------------------------------- ---------- --------------------------- --------------- --------
ADDITIONS
---------------------------
BALANCE CHARGED
AT TO BALANCE
BEGINNING COSTS CHARGED TO OTHER AT END
OF AND ACCOUNTS -- (DEDUCTIONS) -- OF
DESCRIPTION PERIOD EXPENSES DESCRIBE DESCRIBE PERIOD
- ----------- --------- -------- ---------------- --------------- --------
(IN THOUSANDS)
<S><C>
Reserves deducted in the Balance Sheet from
the assets to which they apply:
Accumulated Provision for Uncollectibles
1996.................................... $16,390 $24,955 $ -- $(23,317)(A) $18,028
1995.................................... 14,960 19,170 -- (17,740)(A) 16,390
1994.................................... 13,957 20,557 -- (19,554)(A) 14,960
Valuation Allowance --
Net unrealized (gain) loss on available
for sale securities
1996.................................... (8,401) -- (4,071)(B) -- (12,472)
1995.................................... 5,609 -- (14,010)(B) -- (8,401)
1994.................................... -- -- 5,609(B) -- 5,609
Provision for possible disallowance of
replacement energy costs
1996.................................... 35,000 83,000 -- -- 118,000
1995.................................... 35,000 -- -- -- 35,000
1994.................................... 35,000 -- -- -- 35,000
Loan loss reserve
1996.................................... -- -- -- -- --
1995.................................... -- -- -- -- --
1994.................................... 5,123 -- -- (5,123)(C) --
Energy projects under development reserves
1996.................................... 302 5,201 -- (302)(D) 5,201
1995.................................... 1,806 -- -- (1,504)(D) 302
1994.................................... 1,778 28 -- -- 1,806
</TABLE>
- ----------
(A) Represents principally net amounts charged off as uncollectible.
(B) Represents net unrealized (gains)/losses (credited)/charged to common
shareholders' equity.
(C) Represents reversal of loan loss reserve due to reclassification of this
amount as part of the purchase price of certain real estate partnership
interests.
(D) Represents removal of a reserve associated with an energy project of a
subsidiary which was abandoned.
73
<PAGE>
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 21, 1997 By /s/ C. H. POINDEXTER
----------------------------------
C. H. POINDEXTER
CHAIRMAN OF THE BOARD
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.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S><C>
Principal executive officer and director:
By /s/ C. H. POINDEXTER Chairman of the Board and March 21, 1997
--------------------------------- Director
C. H. POINDEXTER
Principal financial and accounting officer:
By /s/ D. A. BRUNE Vice President and Secretary March 21, 1997
---------------------------------
D. A. BRUNE
Directors:
/s/ H. F. BALDWIN Director March 21, 1997
---------------------------------
H. F. BALDWIN
/s/ B. B. BYRON Director March 21, 1997
---------------------------------
B. B. BYRON
/s/ J. O. COLE Director March 21, 1997
---------------------------------
J. O. COLE
/s/ D. A. COLUSSY Director March 21, 1997
---------------------------------
D. A. COLUSSY
/s/ E. A. CROOKE Director March 21, 1997
---------------------------------
E. A. CROOKE
/s/ J. R. CURTISS Director March 21, 1997
---------------------------------
J. R. CURTISS
/s/ J. W. GECKLE Director March 21, 1997
---------------------------------
J. W. GECKLE
/s/ F. A. HRABOWSKI III Director March 21, 1997
---------------------------------
F. A. HRABOWSKI III
/s/ N. LAMPTON Director March 21, 1997
---------------------------------
N. LAMPTON
/s/ G. V. MCGOWAN Director March 21, 1997
---------------------------------
G. V. MCGOWAN
/s/ G. L. RUSSELL, JR. Director March 21, 1997
---------------------------------
G. L. RUSSELL, JR.
/s/ M. D. SULLIVAN Director March 21, 1997
---------------------------------
M. D. SULLIVAN
</TABLE>
74
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NUMBER
- -------
<S><C>
*2(a) -- Agreement and Plan of Merger dated as of September 22, 1995, by and among Baltimore Gas and Electric
Company, Potomac Electric Power Company, and RH Acquisition Corp. (Designated as Exhibit A in the
Joint Proxy Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which
was filed as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective
February 9, 1996, Registration No. 33-64799.)
*2(b) -- BGE Stock Option Agreement dated as of September 22, 1995, by and between Baltimore Gas and Electric
Company and Potomac Electric Power Company. (Designated as Exhibit B1 in the Joint Proxy Statement of
Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed as part of
Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9, 1996,
Registration No. 33-64799.)
*2(c) -- PEPCO Stock Option Agreement dated as of September 22, 1995, by and between Baltimore Gas and
Electric Company and Potomac Electric Power Company. (Designated as Exhibit B2 in the Joint Proxy
Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed
as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective February
9, 1996, Registration No. 33-64799.)
*2(d) -- Registration Statement on Form S-4 of Constellation Energy Corporation, as amended, which became
effective February 9, 1996, Registration 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 April 18, 1995. (Designated as Exhibit No. 3(b) in Form 10-Q dated May
11, 1995, 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:
</TABLE>
<TABLE>
<CAPTION>
DESIGNATED IN
---------------------------------------------------------------------------
EXHIBIT
DATED FILE NO. NUMBER
----- -------- -------
<S><C>
*August 1, 1967 1-1910 (Form 10-K Annual Report for 1967) D-1
*January 1, 1972 1-1910 (Form 10-K Annual Report for 1971) A-2
*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
</TABLE>
<TABLE>
<S><C>
*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).)
*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.)
</TABLE>
75
<PAGE>
<TABLE>
<S><C>
*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.
*10(e) -- Baltimore and Gas and Electric Company Nonqualified Deferred Compensation Plan for Non-Employee
Directors (formerly Baltimore Gas and Electric Company Deferred Compensation Plan for Non-Employee
Directors). (Designated as Exhibit No. 10(f) to the Annual Report on Form 10-K for the year ended
December 31, 1993, 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.)
*10(g) -- Summary of Baltimore Gas and Electric Company Long Term Performance Program. (Designated as
Exhibit No. 10(h) to the Annual Report on Form 10-K for the year ended December 31, 1993, File No.
1-1910.)
*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) -- Summary 1994-96 Long Term Incentive Plan of Constellation Holdings, Inc. (Designated as Exhibit
No. 10(l) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No.
1-1910.)
*10(k) -- Employment Agreement of Christian H. Poindexter. (Designated as Exhibit C2 in the Joint Proxy
Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which was
filed as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective
February 9, 1996, Registration No. 33-64799.)
*10(l) -- Employment Agreement of Edward A. Crooke. (Designated as Exhibit C3 in the Joint Proxy Statement
of Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed as part
of Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9,
1996, Registration No. 33-64799.)
*10(m) -- Severance Agreements between BGE and 15 key employees. (Designated as Exhibit No. 10(o) to the
Annual Report on Form 10-K for the year ended December 31, 1995, File No. 1-1910.)
*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 Coopers & Lybrand L.L.P., 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.)
*99(b) -- Corporations and Associations Article, Section 2-418 of the Annotated Code of Maryland.
(Designated as Exhibit 28(b) to the Annual Report on Form 10-K for the year ended December 31,
1987, File No. 1-1910.)
</TABLE>
*Incorporated by Reference.
76
EXHIBIT 10(D)
BALTIMORE GAS AND ELECTRIC COMPANY
NONQUALIFIED DEFERRED COMPENSATION PLAN (PLAN)
1. OBJECTIVE. The objective of this Plan is to enable certain management
employees of BGE and its subsidiaries to defer compensation.
2. DEFINITIONS. All words beginning with an initial capital letter and not
otherwise defined herein shall have the meaning set forth in the
Employee Savings Plan. All singular terms defined in this Plan will
include the plural and VICE VERSA. As used herein, the following terms
will have the meaning specified below:
"Basic Compensation" means such compensation as set forth in the
Employee Savings Plan, without regard to the Internal Revenue Code
Section 401(a)(17) annual compensation limitation.
"BGE" means Baltimore Gas and Electric Company, a Maryland corporation,
or its successor.
"Committee" means the Committee on Management of the Board of Directors
of BGE.
"Deferred Compensation" means any compensation payable by BGE or its
subsidiaries to a participant that is deferred under the provisions of
this Plan.
"Employee Savings Plan" means the Baltimore Gas and Electric Company
Employee Savings Plan as may be amended from time to time, or any
successor plan.
"Executive Incentive Plan" means the Executive Incentive Plan of
Baltimore Gas and Electric Company as may be amended from time to time,
or any successor plan, and/or any other incentive plan designated in
writing by the Plan Administrator.
"Incentive Award" means an award granted under the Executive Incentive
Plan or the Managers' Incentive Plan.
"Managers' Incentive Plan" means the Managers' Incentive Plan of
Baltimore Gas and Electric Company as may be amended from time to time,
or any successor plan, and/or any other incentive plan designated in
writing by the Plan Administrator.
"Matching Contributions" means the matching contributions described in
Section 8.
"Plan Accounts" means amounts of a participant's Deferred Compensation,
Matching Contributions, and earnings under the Plan.
"Plan Administrator" means, as set forth in Section 3, the Vice
President -- Management Services of BGE, (or the Vice-President
succeeding to that function).
"Rabbi Trust" means the trust established by BGE pursuant to Grantor
Trust Agreement dated as of June 1, 1996 between BGE and T. Rowe Price
Trust Company.
"Termination From Employment with BGE" means a participant's separation
from service with BGE or a subsidiary of BGE; however, a participant's
transfer of employment to or from a subsidiary of BGE shall not
constitute a Termination From Employment with BGE.
3. PLAN ADMINISTRATION. The Vice President -- Management Services of BGE,
(or the Vice-President succeeding to that function) is the Plan
Administrator and has the sole authority (except as specified otherwise
herein) to interpret the Plan, and, in general, to make all other
determinations advisable for the administration of the Plan to achieve
its stated objective.
Appeals of written decisions by the Plan Administrator may be made to
the Committee. Decisions by the Committee shall be final and not
subject to further appeal. The Plan Administrator shall have the power
to delegate all or any part of his/her duties to one or more designees,
and to withdraw such authority, by written designation.
4. ELIGIBILITY AND PARTICIPATION. Each officer or key employee of BGE or
its subsidiaries, or employees of BGE or its subsidiaries who hold
manager level positions, may be designated in writing by the Plan
Administrator as eligible to participate with respect to one or more of
the provisions of
77
<PAGE>
Sections 5, 6, 7 and 8, which designation will also indicate whether
all or part of such participant's Plan Accounts will be held in the
Rabbi Trust. Once designated, eligibility shall continue until such
designation is withdrawn at the discretion and by written order of the
Plan Administrator. Notwithstanding subsequent withdrawal of
eligibility of an employee, such an employee with Plan Accounts will
remain a participant of the Plan, except that no further deferrals of
compensation under the Plan are permitted. While designated as eligible
with respect to one or more of the provisions of Sections 5, 6, 7 or 8,
an employee may participate in the Plan to the extent set forth in such
designation.
5. BASIC COMPENSATION DEFERRAL ELECTION. Unless otherwise designated in
writing by the Plan Administrator, a participant may defer Basic
Compensation as set forth in this Section 5. A participant may elect to
defer up to 15% of monthly Basic Compensation. A participant may also
elect to defer up to 100% of Basic Compensation, if any, in excess of
the dollar limitation set forth in Internal Revenue Code Section
401(a)(17) (as adjusted by the Commissioner for increases in the cost
of living in accordance with Internal Revenue Code Section
401(a)(17)(B)). Any deferrals shall be in 1% multiples, subject to
adjustment as necessary to provide for any required withholding taxes.
Such election shall be made by notification in the form and manner
established by the Plan Administrator from time to time, and shall be
effective as of the beginning of the month following the month during
which the election is received by the Plan Administrator. Such election
may be revoked by notification in the form and manner established by
the Plan Administrator from time to time, and shall be effective as of
the beginning of the month following the month during which the
revocation is received by the Plan Administrator.
6. INCENTIVE AWARD DEFERRAL ELECTION. A participant may elect to defer
Incentive Award compensation in 1% multiples, subject to adjustment as
necessary to provide for any required withholding taxes. Such election
shall be made annually by notification in the form and manner
established by the Plan Administrator from time to time. Such annual
election shall be made prior to the Incentive Award performance year,
and shall be effective as of the first day of such performance year. If
a participant initially becomes eligible to participate in the Plan
during a performance year, the election for such performance year must
be made prior to the date the participant initially becomes eligible to
participate in the Plan, and shall be effective on such date. Elections
under this Section are irrevocable once effective.
7. OTHER DEFERRAL ELECTION. A participant may elect to defer, in 1%
multiples, other forms of compensation that are designated in writing
by the Plan Administrator. Such election must be made prior to the date
the compensation is earned by the participant, by notification in the
form and manner established by the Plan Administrator from time to
time. Such election is effective as of the date the compensation is
earned. Elections under this Section are irrevocable once effective.
8. MATCHING CONTRIBUTIONS. Matching Contributions are made by BGE to the
Plan in an amount equal to (i) up to the rate of Company Matching
Contributions under the Employee Savings Plan multiplied by a
participant's monthly Basic Compensation deferral, less (ii) the amount
of Company Matching Contributions made to the Employee Savings Plan on
behalf of such participant with respect to such month.
9. PLAN ACCOUNTS. Deferred Compensation and Matching Contributions shall
be (i) credited to participant Plan Accounts as soon as practicable;
(ii) to the extent designated by the Plan Administrator, held for the
benefit of the participant in the Rabbi Trust; and (iii) credited with
earnings at the T. Rowe Price Prime Reserve Fund rate. However, a
participant may elect (by notification in the form and manner
established by the Plan Administrator from time to time) to have all or
a portion of his/her Plan Accounts credited with earnings at a rate
equal to the T. Rowe Price Prime Reserve Fund rate, the T. Rowe Price
New Income Fund rate, or one or more of the rates earned by investment
options available under the Employee Savings Plan, except the Common
Stock Fund and the Interest Income Fund. Earnings are credited to Plan
Accounts commencing on the day the Deferred Compensation and Matching
Contributions are credited to the Plan Accounts. Plan Accounts will be
valued daily in the same manner as for Investment Funds under the
Employee Savings Plan.
A participant may elect to change the investment option of future
Deferred Compensation and Matching Contributions, which election shall
be effective when the next Deferred Compensation
78
<PAGE>
contributions and/or Matching Contributions are credited to the
participant's Plan Accounts. A participant may elect to reallocate to
other investment options current Plan Accounts, which election shall be
effective at the same time as, and valued in accordance with, the
interfund transfer provisions under the Employee Savings Plan. Such
elections shall be made by notification in the form and manner
established by the Plan Administrator from time to time.
10. DISTRIBUTIONS OF PLAN ACCOUNTS. Distributions of Plan Accounts shall be
made in cash only, and to the extent designated by the Plan
Administrator, from the Rabbi Trust.
Prior to the end of the calendar year of a participant's Termination
From Employment with BGE, such participant must elect the timing of
distributions of his/her Plan Accounts. The participant may elect (by
notification in the form and manner established by the Plan
Administrator from time to time) to begin distributions (i) in the
calendar year following the calendar year of the participant's
Termination From Employment with BGE, (ii) in the year following the
year in which a participant attains age 70-1/2, if later, or (iii) any
calendar year between (i) and (ii). A participant may elect (by
notification in the form and manner established by the Plan
Administrator from time to time) to receive distributions in a single
payment or in annual installments during a period not to exceed fifteen
years. The single payment or the first installment payment, whichever
is applicable, shall be made within the first sixty (60) days of the
calendar year elected for distribution. Subsequent installments, if
any, shall be made within the first sixty (60) days of each succeeding
calendar year until the participant's Plan Accounts have been paid. In
the event no election is made prior to the end of the year of a
participant's Termination From Employment with BGE, a participant shall
receive a distribution in a single payment within the first sixty (60)
days of the following year. Earnings are credited to Plan Accounts
through the date of distribution, and amounts held for installment
payments shall continue to be credited with earnings, as specified in
Section 9.
If a participant dies, the entire unpaid balance of his/her Plan
Accounts shall be paid to the beneficiary(ies) designated by the
participant by notification in the form and manner established by the
Plan Administrator from time to time or, if no designation was made, to
the estate of the participant. Payment shall be made within sixty (60)
days after notice of death is received by the Plan Administrator,
unless prior to the end of the calendar year of the participant's
Termination From Employment with BGE, the participant elected (in the
form and manner established by the Plan Administrator from time to
time) a delayed and/or installment distribution option for such
beneficiary(ies); provided, however that (i) such a distribution option
election shall be effective only if the value of the participant's Plan
Accounts is more than $50,000 on the date of the participant's death;
and (ii) the final distribution must be made to such beneficiary(ies)
no later than 15 years after the participant's death. After the end of
the calendar year of a participant's Termination From Employment with
BGE, a distribution option election for a particular beneficiary is
irrevocable; provided, however, that the participant may make a
distribution option election for a new beneficiary who is initially
designated after the participant's Termination From Employment with
BGE, and such election is irrevocable with respect to the new
beneficiary.
In the event a participant's deferred Incentive Award is credited to
the Plan after the participant's death, such Incentive Award shall be
either paid to his/her beneficiary(ies), or if a delayed and/or
installment distribution option was elected for such beneficiary(ies),
paid as part of the aggregate Plan Accounts in accordance with such
election.
Upon the death of a participant's beneficiary for whom a delayed and/or
installment distribution option was elected, the entire unpaid balance
of the participant's Plan Accounts shall be paid to the
beneficiary(ies) designated by the participant's beneficiary by
notification in the form and manner established by the Plan
Administrator from time to time or, if no designation was made, to the
estate of the participant's beneficiary. Payment shall be made within
sixty (60) days after notice of death is received by the Plan
Administrator.
Notwithstanding anything herein contained to the contrary, the
Committee shall have the right in its sole discretion to vary the
manner and timing of distributions, and may make such distributions in
a single payment or over a shorter or longer period of time than that
elected by a participant.
11. BENEFICIARIES. A participant shall have the right to designate a
beneficiary(ies) who is to receive a distribution(s) pursuant to
Section 10 in the event of the death of the participant. A
participant's
79
<PAGE>
beneficiary(ies) for whom a delayed and/or installment distribution
option was elected shall have the right to designate a beneficiary(ies)
who is to receive a distribution pursuant to Section 10 in the event of
the death of the participant's beneficiary(ies).
Any designation, change or recision of the designation of beneficiary
shall be made by notification in the form and manner established by the
Plan Administrator from time to time. The last designation of
beneficiary received by the Plan Administrator shall be controlling
over any testamentary or purported disposition by the participant (or,
if applicable, the participant's beneficiary(ies)), provided that no
designation, recision or change thereof shall be effective unless
received by the Plan Administrator prior to the death of the
participant (or, if applicable, the participant's beneficiary(ies)).
If the designated beneficiary is the estate, or the executor or
administrator of the estate, of the participant (or, if applicable, the
participant's beneficiary(ies)), a distribution pursuant to Section 10
may be made to the person(s) or entity (including a trust) entitled
thereto under the will of the participant (or, if applicable, the
participant's beneficiary(ies)), or, in the case of intestacy, under
the laws relating to intestacy.
A participant's beneficiary(ies) for whom a delayed and/or installment
distribution option was elected shall have the right, after the death
of the participant, to make investment elections or changes in
investment elections with respect to a participant's Plan Accounts to
the same extent available to the participant pursuant to Section 9. A
beneficiary(ies) of the participant's beneficiary(ies) shall have no
right to make any investment election or change in investment election
pursuant to Section 9 with respect to a participant's Plan Accounts.
12. VALUATION OF INTEREST. The Plan Administrator shall cause the value of
a participant's Plan Accounts, at least once per year as of December
31, to be determined separately and be reported to BGE and the
participant (or, if applicable, the participant's beneficiary(ies)).
Valuation of a participant's Plan Accounts shall be determined in
accordance with the procedures contained in the Employee Savings Plan.
13. WITHDRAWALS. No withdrawals of Plan Accounts may be made, except a
participant may at any time request a hardship withdrawal from his/her
Plan Accounts if he/she has incurred an unforeseeable emergency. An
unforeseeable emergency is defined as severe financial hardship to the
participant resulting from a sudden and unexpected illness or accident
of the participant (or of his/her dependents), loss of the
participant's property due to casualty, or other similar extraordinary
and unforeseeable circumstances arising as a result of events beyond
the control of the participant. The need to send a child to college or
the desire to purchase a home are not considered to be unforeseeable
emergencies. The circumstance that will constitute an unforeseeable
emergency will depend upon the facts of each case.
A hardship withdrawal will be permitted by the Plan Administrator only
as necessary to satisfy an immediate and heavy financial need. A
hardship withdrawal may be permitted only to the extent reasonably
necessary to satisfy the financial need. Payment may not be made to the
extent that such hardship is or may be relieved (i) through
reimbursement or compensation by insurance or otherwise, (ii) by
liquidation of the participant's assets, to the extent the liquidation
of such assets would not itself cause severe financial hardship, or
(iii) by cessation of deferrals under the Plan.
The request for hardship withdrawal shall be made by notification in
the form and manner established by the Plan Administrator from time to
time. Such hardship withdrawal will be permitted only with approval of
the Plan Administrator. The participant will receive a lump sum payment
after the Plan Administrator has had reasonable time to consider and
then approve the request.
14. MISCELLANEOUS. A participant's Plan Accounts shall not be subject to
alienation or assignment by any participant or beneficiary nor shall
any of them be subject to attachment or garnishment or other legal
process except (i) to the extent specially mandated and directed by
applicable State or Federal statute; and (ii) as requested by the
participant or beneficiary to satisfy income tax withholding or
liability.
This Plan may be amended from time to time or suspended or terminated
at any time. All amendments to this Plan which would increase or
decrease the compensation of any senior management officer or key
employee of BGE, either directly or indirectly, must be approved by the
Board of
80
<PAGE>
Directors. All other permissible amendments may be made at the written
direction of the Committee. No amendment to or termination of this Plan
shall prejudice the rights of any participant or beneficiary entitled
to receive payment hereunder at the time of such action.
Participation in this Plan shall not constitute a contract of
employment between BGE and any person and shall not be deemed to be
consideration for, or a condition of, continued employment of any
person.
The Plan, notwithstanding the creation of the Rabbi Trust, is intended
to be unfunded for purposes of Title I of the Employee Retirement
Income Security Act of 1974. BGE shall make contributions to the Rabbi
Trust in accordance with the terms of the Rabbi Trust. Any funds which
may be invested and any assets which may be held to provide benefits
under this Plan shall continue for all purposes to be a part of the
general funds and assets of BGE and no person other than BGE shall by
virtue of the provisions of this Plan have any interest in such funds
and assets. To the extent that any person acquires a right to receive
payments from BGE under this Plan, such rights shall be no greater than
the right of any unsecured general creditor of BGE.
This Plan shall be governed in all respects by Maryland law.
81
EXHIBIT 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
<TABLE>
<CAPTION>
12 Months Ended
-------------------------------------------------------
December December December December December
1996 1995 1994 1993 1992
-------------------------------------------------------
(In Thousands of Dollars)
<S> <C>
Net Income $310,824 $338,007 $323,617 $309,866 $264,347
Taxes on Income 169,202 172,388 156,702 140,833 105,994
-------- -------- -------- -------- --------
Adjusted Net Income $480,026 $510,395 $480,319 $450,699 $370,341
-------- -------- -------- -------- --------
Fixed Charges:
Interest and Amortization of Debt Discount
and Expense and Premium on all Indebtedness $203,923 $206,666 $204,206 $199,415 $200,848
Capitalized Interest 15,664 15,050 12,427 16,167 13,800
Interest Factor in Rentals 1,548 2,099 2,010 2,144 2,033
-------- -------- -------- -------- --------
Total Fixed Charges $221,135 $223,815 $218,643 $217,726 $216,681
-------- -------- -------- -------- --------
Preferred and Preference
Dividend Requirements: (1)
Preferred and Preference Dividends $ 38,536 $ 40,578 $ 39,922 $ 41,839 $ 42,247
Income Tax Required 20,849 20,434 19,074 18,763 16,729
-------- -------- -------- -------- --------
Total Preferred and Preference
Dividend Requirements $ 59,385 $ 61,012 $ 58,996 $ 60,602 $ 58,976
-------- -------- -------- -------- --------
Total Fixed Charges and Preferred
and Preference Dividend Requirements $280,520 $284,827 $277,639 $278,328 $275,657
-------- -------- -------- -------- --------
Earnings (2) $685,497 $719,160 $686,535 $652,258 $573,222
-------- -------- -------- -------- --------
Ratio of Earnings to Fixed Charges 3.10 3.21 3.14 3.00 2.65
Ratio of Earnings to Combined Fixed
Charges and Preferred and Preference
Dividend Requirements 2.44 2.52 2.47 2.34 2.08
</TABLE>
(1) Preferred and preference dividend requirements consist of an amount equal
to the pre-tax earnings that would be required to meet dividend
requirements on preferred stock and preference stock.
(2) Earnings are deemed to consist of net income that includes earnings of
BGE's consolidated subsidiaries, equity in the net income of BGE's
unconsolidated subsidiary, income taxes (including deferred income taxes
and investment tax credit adjustments), and fixed charges other than
capitalized interest.
EXHIBIT 21
SUBSIDIARIES OF THE REGISTRANT*
<TABLE>
<CAPTION>
JURISDICTION
OF
INCORPORATION
-------------
<S><C>
Constellation Holdings, Inc. ..................................................................... Maryland
Constellation Investments, Inc. .................................................................. Maryland
Constellation Energy Source, Inc. (formerly named BNG, Inc.)...................................... Delaware
Safe Harbor Water Power Corporation............................................................... Pennsylvania
BGE Home Products & Services, Inc................................................................. Maryland
BGE Energy Projects & Services, Inc............................................................... Maryland
</TABLE>
*The names of certain indirectly owned subsidiaries have been omitted because,
considered in the aggregate as a single subsidiary, they would not constitute a
significant subsidiary pursuant to Rule 1-02(w) of Regulation S-X.
83
EXHIBIT 23
CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS
We consent to the incorporation by reference in the Prospectuses of Baltimore
Gas and Electric Company prepared in accordance with the requirements of Forms
S-8 (File Nos. 33-56084 and 33-59545) and Forms S-3 (File Nos. 33-49801,
33-45260, 33-33559, 33-57658, and 333-19263) and the Prospectus of
Constellation Energy Corporation prepared in accordance with the requirements of
Form S-4 (File No. 33-64799) of our report dated January 17, 1997 accompanying
the consolidated financial statements and the consolidated financial statement
schedule of Baltimore Gas and Electric Company as of December 31, 1996 and 1995
and for each of the three years in the period ended December 31, 1996, included
in this Annual Report on Form 10-K of Baltimore Gas and Electric Company.
/s/ Coopers & Lybrand L.L.P.
______________________________
COOPERS & LYBRAND L.L.P.
Baltimore, Maryland
March 28, 1997
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from BGE's
December 31, 1996 Interim Consolidated Income Statement, Balance Sheet and
Statement of Cash Flows and is qualified in its entirety by reference to such
statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 5,582,350
<OTHER-PROPERTY-AND-INVEST> 1,473,165
<TOTAL-CURRENT-ASSETS> 902,198
<TOTAL-DEFERRED-CHARGES> 593,257
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 8,550,970
<COMMON> 1,429,942
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 1,419,065
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,857,113
134,500
210,000
<LONG-TERM-DEBT-NET> 2,758,769
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 333,185
<LONG-TERM-DEBT-CURRENT-PORT> 197,772
83,000
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,976,631
<TOT-CAPITALIZATION-AND-LIAB> 8,550,970
<GROSS-OPERATING-REVENUE> 3,153,247
<INCOME-TAX-EXPENSE> 166,333
<OTHER-OPERATING-EXPENSES> 2,483,782
<TOTAL-OPERATING-EXPENSES> 2,650,115
<OPERATING-INCOME-LOSS> 503,132
<OTHER-INCOME-NET> 6,130
<INCOME-BEFORE-INTEREST-EXPEN> 509,262
<TOTAL-INTEREST-EXPENSE> 198,438
<NET-INCOME> 310,824
38,536
<EARNINGS-AVAILABLE-FOR-COMM> 272,288
<COMMON-STOCK-DIVIDENDS> 233,109
<TOTAL-INTEREST-ON-BONDS> 217,622
<CASH-FLOW-OPERATIONS> 701,947
<EPS-PRIMARY> 1.85
<EPS-DILUTED> 1.85
</TABLE>
