UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549
                                   FORM 10-K
                                 --------------
                ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
                    THE SECURITIES AND EXCHANGE ACT OF 1934
<TABLE>
<S><C>
         For the fiscal year ended                            1-1910
             December 31, 1996                        Commission file number
</TABLE>

                                 --------------

                       BALTIMORE GAS AND ELECTRIC COMPANY
             (Exact name of registrant as specified in its charter)
<TABLE>
<S><C>
                 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)
</TABLE>

                                  410-783-5920
              (Registrant's telephone number, including area code)
          SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
<TABLE>
<CAPTION>
                                                                        NAME OF EACH EXCHANGE
                TITLE OF EACH CLASS                                      ON WHICH REGISTERED
                -------------------                                     ---------------------
<S><C>
                                                                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
</TABLE>

          SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
                                 Not Applicable
     Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months, and (2) has been subject to such filing
requirements for the past 90 days.   Yes  x    No    .
                                         ---
     Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K (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.

<PAGE>
                               TABLE OF CONTENTS
<TABLE>
<CAPTION>
                                                                                                                PAGE
<S><C>
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
</TABLE>

<PAGE>
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.
                                       1

<PAGE>
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:
<TABLE>
<CAPTION>
                                                       OPERATING REVENUES                  OPERATING INCOME*
                                                       ------------------                  -----------------
                                                 ELECTRIC    GAS    DIVERSIFIED      ELECTRIC    GAS    DIVERSIFIED
                                                 --------    ---    -----------      --------    ---    -----------
<S><C>
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
</TABLE>

    *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.
                                       2
 
<PAGE>
                       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.
<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 (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
                                                                    -----   -----   -----   -----   -----   -------

       Total utility business capital requirements...............     783     737     621     588     518       670
                                                                    -----   -----   -----   -----   -----   -------
Diversified Business Capital Requirements........................      88     173     170     322     345       391
                                                                    -----   -----   -----   -----   -----   -------
       Total capital requirements................................   $ 871   $ 910   $ 791   $ 910   $ 863   $ 1,061
                                                                    =====   =====   =====   =====   =====   =======
</TABLE>

(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.
                                       3

<PAGE>
                               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
                                       4

<PAGE>
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.)
                                       5
 
<PAGE>
     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
                                       6
 
<PAGE>
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