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

         For the fiscal year ended                            1-1910
             December 31, 1995                        Commission file number

                       BALTIMORE GAS AND ELECTRIC COMPANY
             (Exact name of registrant as specified in its charter)

                 MARYLAND                                52-0280210
         (State of incorporation)           (I.R.S. Employer Identification No.)
          39 W. LEXINGTON STREET,
            BALTIMORE, MARYLAND                             21201
 (Address of principal executive offices)                (Zip Code)

                                  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>        <C>
                                                          New York Stock Exchange, Inc.
Common Stock -- Without Par Value              (brace)    Chicago Stock Exchange, Inc.
                                                          Pacific Stock Exchange, Inc.
Preferred Stock, Series B 4 1/2%, Cumulative,
  $100 Par Value                               (brace)    New York Stock Exchange, Inc.
Preferred Stock, Cumulative, $100 Par Value:
  Series C 4%
  Series D 5.40%
Preference Stock, Cumulative, $100 Par Value:  (brace)    Philadelphia Stock Exchange, Inc.
  7.78%, 1973 Series
  7.50%, 1986 Series
  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 29, 1996 was approximately $4,171,501,536 based
upon New York Stock Exchange composite transaction closing price.
 COMMON STOCK, WITHOUT PAR VALUE -- 147,527,114 SHARES OUTSTANDING ON FEBRUARY
                                   29, 1996.
                      DOCUMENTS INCORPORATED BY REFERENCE
<TABLE>
<CAPTION>
PART OF FORM 10-K                                       DOCUMENT INCORPORATED BY REFERENCE
<S>                 <C>
   III              Definitive Proxy Statement for the Annual Meeting of Shareholders of Baltimore Gas and
                    Electric Company to be held on April 23, 1996 (Proxy Statement).
</TABLE>

<PAGE>
                               TABLE OF CONTENTS
<TABLE>
<CAPTION>
                                                                                                                PAGE
<S>              <C>                                                                                            <C>
PART I
  Item 1  --     Business
                 General.....................................................................................     1
                 Capital Requirements........................................................................     2
                 Electric Business
                   Electric Regulatory Matters and Competition...............................................     3
                   Electric Rate Matters.....................................................................     4
                   Nuclear Operations........................................................................     5
                   Electric Load Management, Energy, and Capacity Purchases..................................     7
                   Fuel for Electric Generation..............................................................     8
                 Gas Business
                   Gas Regulatory Matters and Competition....................................................     9
                   Gas Operations............................................................................    10
                   Gas Rate Matters..........................................................................    10
                 Electric Operating Statistics...............................................................    11
                 Gas Operating Statistics....................................................................    12
                 Franchises..................................................................................    13
                 Diversified Businesses......................................................................    13
                 Environmental Matters.......................................................................    15
                 Employees...................................................................................    17
  Item 2  --     Properties..................................................................................    18
  Item 3  --     Legal Proceedings...........................................................................    18
  Item 4  --     Submission of Matters to a Vote of Security Holders.........................................    19
  Item 10 --     Executive Officers of the Registrant (Instruction 3 to Item 401(b) of Regulation S-K).......    20
PART II
  Item 5  --     Market for Registrant's Common Equity and Related 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.................................................    32
  Item 9  --     Changes in and Disagreements with Accountants on Accounting and Financial
                 Disclosure..................................................................................    56
PART III
  Item 10 --     Directors and Executive Officers of the Registrant..........................................    56
  Item 11 --     Executive Compensation......................................................................    56
  Item 12 --     Security Ownership of Certain Beneficial Owners and Management..............................    56
  Item 13 --     Certain Relationships and Related Transactions..............................................    56
PART IV
  Item 14 --     Exhibits, Financial Statement Schedules and Reports on Form 8-K.............................    56
  Signatures.................................................................................................    60
</TABLE>

<PAGE>
                                     PART I
ITEM 1.  BUSINESS
     Baltimore Gas and Electric Company and Subsidiaries are herein collectively
referred to as the Company. The Company is engaged in utility operations and
related businesses through Baltimore Gas and Electric Company (BGE). The Company
is engaged in diversified businesses primarily through four wholly owned
subsidiaries of BGE, Constellation Holdings, Inc. and its subsidiaries
(collectively, the Constellation Companies), BGE Home Products & Services, Inc.
(HP&S) and its subsidiary Maryland Environmental Systems, Inc. (MES), BGE Energy
Projects & Services, Inc. (EP&S), and BNG, Inc. For financial information by
segment of operation see NOTE 2 TO CONSOLIDATED FINANCIAL STATEMENTS.
     BGE was incorporated under the laws of the State of Maryland on June 20,
1906, and is primarily engaged in the business of producing, purchasing, and
selling electricity, and purchasing, transporting, and selling natural gas
within the State of Maryland. 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 -- ELECTRIC. BGE also owns two-thirds of the outstanding
capital stock, including one-half of the voting securities, of Safe Harbor Water
Power Corporation (Safe Harbor), a hydroelectric producer on the Susquehanna
River at Safe Harbor, Pennsylvania. (SEE ITEM 2. PROPERTIES -- ELECTRIC.)
     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.) Also, the
utility industry is facing potentially substantial regulatory change designed to
foster competition in the provision of gas and electric services. 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 on page 3 and GAS REGULATORY MATTERS AND COMPETITION on page 9.
     Diversified businesses conducted by the Constellation Companies, HP&S, MES,
EP&S, and BNG, Inc. are discussed under DIVERSIFIED BUSINESSES on page 13 and
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS (MD&A).
     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*
<S>                                              <C>         <C>    <C>              <C>         <C>    <C>
                                                 ELECTRIC    GAS    DIVERSIFIED      ELECTRIC    GAS    DIVERSIFIED
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
1991..........................................      79       14           7             90        6           4
</TABLE>

    Certain prior-year amounts have been reclassified to conform with the
    current year's presentation.
    *Net of income taxes.
     BGE currently derives approximately 22% of electric revenues and 42% of gas
revenues from customers located in the City of Baltimore and 78% and 58%,
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
                                       1

<PAGE>
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 $540 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 on page 33, gas purchased for resale as a
percentage of gas revenues (49%) is greater than electric fuel and purchased
energy as a percentage of electric revenues (26%). It should be noted that both
purchased gas costs and electric fuel costs are passed through to the customer
with no mark-up for profit. The combined effects of these factors yield the
observed relationship between operating revenues and income for electric and gas
operations.
     BGE and Potomac Electric Power Company (PEPCO) have agreed to merge. 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 in March 1997. The reasons for the merger and
other information about the merger are discussed in more detail under ELECTRIC
REGULATORY MATTERS AND COMPETITION on pages 3 and 4 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, as discussed in ELECTRIC REGULATORY MATTERS AND COMPETITION on pages 3
and 4 and GAS REGULATORY MATTERS AND COMPETITION on page 9, BGE (and after the
merger the new company to be named Constellation Energy 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, acquisitions of related or unrelated
businesses, business combinations, and additions to or dispositions of portions
of its franchised service territories. BGE and its subsidiaries may from time to
time be engaged in preliminary discussions, either internally or with third
parties, regarding one or more of these potential strategies.
                              CAPITAL REQUIREMENTS
     The Company's actual capital requirements for 1993 through 1995, along with
estimated amounts for 1996 through 1998, are set forth below. Certain prior-year
amounts have been restated to conform with the current year's presentation.
<TABLE>
<CAPTION>
                                                                     1993     1994    1995    1996    1997    1998
<S>                                                                 <C>       <C>     <C>     <C>     <C>     <C>
                                                                                     (IN MILLIONS)
Utility Business
  Construction expenditures (excluding AFC)
     Electric....................................................   $   365   $ 345   $ 223   $ 231   $ 205   $ 212
     Gas.........................................................        52      68      70      68      73      67
     Common......................................................        41      42      51      41      47      46
       Total construction expenditures...........................       458     455     344     340     325     325
  AFC (a)........................................................        23      34      22      11      10      10
  Nuclear fuel (uranium purchases and processing charges)........        47      42      46      45      45      44
  Deferred energy conservation expenditures (b)..................        33      41      46      34      25      27
  Deferred nuclear expenditures (b)..............................        14       8      --      --      --      --
  Retirement of long-term debt and redemption of preference
     stock.......................................................       907     203     279      98     164     125
       Total utility business....................................     1,482     783     737     528     569     531
Diversified Businesses...........................................       300      88     173     141     206     220
       Total.....................................................   $ 1,782   $ 871   $ 910   $ 669   $ 775   $ 751
</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.
                                       2

<PAGE>
     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. The Constellation Companies' capital
requirements for diversified businesses may vary from the estimates set forth
above due to a number of factors including market and economic conditions and
are discussed in detail under MD&A -- DIVERSIFIED BUSINESSES CAPITAL
REQUIREMENTS on page 30.
     BGE's estimated construction, nuclear fuel, and deferred energy
conservation expenditures are expected to amount to approximately $1.6 billion,
$220 million, and $145 million, respectively, for the five-year period
1996-2000. Electric construction expenditures reflect the installation of a
5,000-kilowatt diesel generator at the Calvert Cliffs Nuclear Power Plant which
is scheduled to be placed in service in 1996 and 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, 1991 through December 31, 1995, BGE expended
$2,156 million for gross additions to utility plant or approximately 27% of its
total utility plant (exclusive of nuclear fuel) at December 31, 1995. During the
same period, a total of $376 million of utility plant was retired. Nuclear fuel
expenditures include uranium purchases and processing charges.
     BGE presently estimates that approximately $930 million will be required
for retirements and redemptions of long-term debt (including sinking fund
payments) and BGE preference stock during the five-year period 1996-2000.
     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.
                               ELECTRIC BUSINESS
                  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 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
wholesale electric generation market and so increased competition in the
wholesale segment of the electric utility industry. Pursuant to its authority
under the 1992 Act, the FERC issued a number of orders in specific cases
commencing in December 1993 directing utilities to provide transmission
services. The FERC's actions have increased the availability of transmission
services, thus creating significant competition in the wholesale power market.
Other developments resulted from policies at the 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. Each company
independently reached the conclusion that key factors contributing to success in
this 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. The accelerating pace of electric utility mergers
attests to the appropriateness of business combinations between electric utility
companies to address such needs. During 1993, one electric utility company
merger was announced. In 1994, the number was increased to two, and during 1995,
including those following the announcement of the Merger on September 25, 1995,
six such transactions were announced. At the date of this report, there had been
one electric utility company merger announced in 1996.
                                       3

<PAGE>
     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 and
a number of regulatory approvals) 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 by March
1997.
     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
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 (PSC) held hearings in 1995 to consider electric utility
restructuring, the impact of competition, and regulatory reform and considered
possible scenarios ranging from limited to full competition. The PSC issued a
general policy statement in June, 1995 on changes recommended for Maryland's
electric industry. It concluded that wholesale competition remains in the best
interests of the state's energy consumers, but that in view of the availability
of efficient, reliable, comparatively low-cost power, Maryland energy consumers
do not currently need retail competition to capture the benefits of the
competitive energy market. In addition, the PSC mandated competitive bidding for
all new generation and agreed that utilities need flexibility to offer their
customers terms and conditions that meet unique customer needs.
     It is not possible to predict the ultimate effect competition will have on
BGE's earnings in the future.
     In April 1993, the PSC directed that an independent study be performed
regarding the distribution of costs between BGE's regulated utility operations
and unregulated merchandise and appliance services activities. A coalition of
HVAC contractors had alleged that the unregulated operations were being
subsidized by the utility. A cost allocation proceeding was held to examine the
Company's allocation procedures as well as to deal with the demand by the
coalition that the unregulated activities be required to pay a royalty based on
unregulated revenues to compensate ratepayers for the use of the BGE name and
its goodwill. In August, 1995, the PSC issued an order denying the imposition of
royalty payments and requiring BGE to file a cost allocation manual based upon
the principle of fully distributed cost allocation. BGE filed the manual in
February, 1996.
                             ELECTRIC RATE MATTERS
ENERGY CONSERVATION SURCHARGE
     The PSC 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. 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 PSC. (See discussion in ITEM
7. MANAGEMENT'S DISCUSSION AND ANALYSIS.) The surcharge is reset on July 1 of
each year.
                                       4

<PAGE>
ELECTRIC FUEL RATE PROCEEDINGS
     By statute, electric fuel costs are recoverable if the PSC finds that BGE
demonstrates that, among other things, it has maintained the productive capacity
of its generating plants at a reasonable level. The PSC 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 PSC 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.)
     BGE is required to submit to the PSC the actual generating performance data
for each calendar year 45 days after year end. The PSC reviews BGE's performance
for each calendar 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 PSC which are
conducted in accordance with the procedures outlined above under 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 believes, therefore, it is 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 PSC 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 would 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 PSC by both BGE and People's
Counsel. If the PSC upholds the Hearing Examiner, the Company's earnings would
be impacted by approximately $4.5 million.
                                       5

<PAGE>
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 PSC disallow
recovery of $2 million of replacement energy costs. On November 14, 1991, a
Hearing Examiner at the PSC 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 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, are estimated to be $458 million. This estimate is 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 are being reviewed by the PSC
in the 1989-1991 fuel rate proceeding, and People's Counsel and others have
challenged recovery of some part of the associated replacement energy costs. In
the PSC's Rate Order issued in BGE's 1990 Base Rate Case, it found that $4
million of operations and maintenance expenses incurred by BGE during the
1989-1990 outages at the Plant should not be recoverable from customers. The PSC
concluded that the related work, which was performed at Unit 1 during the
1989-1990 outage, was avoidable and caused by Company actions which were
deficient. The work characterized as avoidable had a significant impact on the
duration of the Unit 1 outage. The PSC's Order stated that its conclusions in
this proceeding did not have a binding effect in the fuel rate proceeding on the
recoverability of Calvert Cliffs' replacement energy costs. However, BGE
believes that it is doubtful that the PSC will authorize recovery of the full
amount of replacement energy costs presently under investigation. Based on a
review of the circumstances surrounding the extended outages by BGE personnel as
well as independent consultants, in 1990 BGE recorded a provision of $35 million
against the possible disallowance of such costs. However, BGE cannot determine
whether replacement energy costs may be disallowed in the 1989-1991 fuel rate
proceeding in excess of the provision, but such amounts could be material.
     On March 15, 1994, the PSC Staff and the Office of People's Counsel filed
testimony in the 1989-1991 fuel rate proceedings. The PSC Staff concluded that
approximately 46% of the outage time was unreasonably incurred and that
approximately $200 million of replacement energy costs should be disallowed.
People's Counsel concluded that approximately $400 million of the replacement
energy costs should be disallowed. BGE filed rebuttal testimony in January 1995
in which it vigorously contested the findings of Staff and People's Counsel.
Additional testimony was filed by the PSC Staff and People's Counsel in October
1995 and BGE will file its final testimony in May 1996. Further hearings in this
matter are expected to occur in 1996.
     As previously reported, in December 1988, the NRC categorized the Plant as
one requiring close monitoring and increased NRC attention. The NRC did so
following certain events that the NRC indicated raised questions about the
effectiveness of past corrective action regarding engineering and technical
areas and the overall approach to safety at the Plant. Details of such events
were described in the Report on Form 10-K for the year ended December 31, 1990
in the section titled "Nuclear Operations" on pages 4 through 7. In February
1992, the NRC removed the Plant from its list of nuclear plants categorized as
requiring close monitoring as a result of improved performance in previously
identified problem areas and the demonstration of a sustained period of safe
operation.
                                       6

<PAGE>
OPERATIONS IN 1991 AFTER THE EXTENDED OUTAGE
     The Plant generated 9,036,100 MWH in 1991, which resulted in a capacity
factor of 63%. BGE filed a fuel rate application under GUPP in June 1992,
however, the Hearing Examiner has determined that the 1991 case will not be
addressed until the case covering the extended outage has been resolved.
OPERATIONS SUBSEQUENT TO THE EXTENDED OUTAGE
     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. 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%. A review of 1995
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; the summer
peak capacity impact for 1996 from active load management is expected to be
approximately 474 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
December 31, 1995 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 PSC.
                                       7

<PAGE>
                          FUEL FOR ELECTRIC GENERATION
     Information regarding BGE's electric generation by fuel type and the cost
of fuels in the five-year period 1991-1995 is set forth in the following tables:
<TABLE>
<CAPTION>
                                                                                  AVERAGE COST OF FUEL CONSUMED
                                       GENERATION BY FUEL TYPE                      ((CENTS) PER MILLION BTU)
<S>                              <C>     <C>     <C>     <C>     <C>     <C>       <C>       <C>       <C>       <C>
                                 1995    1994    1993    1992    1991     1995      1994      1993      1992      1991
Nuclear (a)...................    43 %    39 %    43 %    40 %    33 %     47.22     52.06     53.01     45.54     48.64
Coal..........................    57      56      55      54      44      148.64    148.64    151.85    154.76    160.74
Oil...........................     1       3       3       1       5      267.59    245.28    253.36    254.19    284.87
Hydro & Gas...................     3       3       3       3       4          --        --        --        --        --
                                 104     101     104      98      86
Interchange/Purchases (b).....   ( 4 )   ( 1 )   ( 4 )     2      14
                                 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%. The average delivered costs per ton paid by BGE for
Brandon Shores coal for the years 1991 through 1995 were $39.80, $39.98, $39.49,
$37.55 and $37.36, respectively. 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. Coal purchased in 1995 had a sulfur content of less than 1%
compared to approximately 2.4% in prior years to meet the requirements of the
Clean Air Act. The average delivered costs per ton paid by BGE for coal at Crane
for the years 1991 through 1995 were $38.88, $38.37, $37.25, $37.42 and $46.50,
respectively. 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%. The average delivered costs per ton paid by BGE for coal at Wagner for
the years 1991 through 1995 were $44.49, $43.19, $40.62, $37.54 and $37.73,
respectively.
     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. The average delivered
costs per ton for coal for these plants for the years 1991 through 1995 were
$33.07, $31.53, $32.42, $33.22 and $32.49, respectively.
     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. The average delivered prices per barrel paid by BGE for
residual fuel oil for the years 1991 through 1995 were $15.53, $17.25, $15.69,
$16.30 and $17.41, respectively.
     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 concentrates to meet approximately 80% of its requirements
                               through 1997 and approximately 50% of its requirements for 1998.
</TABLE>
                                       8

<PAGE>
<TABLE>
<S>                            <C>
Conversion:                    BGE has contractual commitments providing for the conversion of uranium
                               concentrates into uranium hexafluoride which will meet approximately 40%
                               of its requirements through 1998.
Enrichment:                    BGE has a contract with the U.S. Energy Corporation for the enrichment of
                               70% of BGE's enrichment requirements through 1998.
Fuel Assembly Fabrication:     BGE has contracted for the fabrication of fuel assemblies for reloads it
                               requires through 1996.
</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 MD&A -- LIQUIDITY AND CAPITAL RESOURCES on
page 29.
     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 $12 million
for Calvert Cliffs each year.
     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.
     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 THE CONSOLIDATED FINANCIAL
STATEMENTS on page 42 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.
                                  GAS BUSINESS
                     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 PSC 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. Currently as part of its response to the increase in
competition in the natural gas business, BGE has proposals before the PSC for
profit sharing for capacity release revenues and savings from gas purchases
which are less than a predefined city gate index (called Market Based Rates) for
sales in BGE's gas territory.
                                       9

<PAGE>
                                 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 473,597 dekatherms (DTH) per day during the winter period and 291,731
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.
     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 suppliers and pipelines. BGE also plans to conduct a pilot
transportation program for residential customers. 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
PSC 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 PSC 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 4.8% of total 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 PSC 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.
                                       10

<PAGE>
                         ELECTRIC OPERATING STATISTICS
<TABLE>
<CAPTION>
                                                                   YEAR ENDED DECEMBER 31,
                                                 1995          1994          1993          1992          1991
<S>                                           <C>           <C>           <C>           <C>           <C>
Electric Output (In Thousands) -- MWH:
  Generated................................       30,548        28,413        28,907        25,626        22,767
  Purchased (A)............................        7,403         6,270         3,643         4,323         5,522
       Subtotal............................       37,951        34,683        32,550        29,949        28,289
  Less Interchange and Other Sales.........        8,149         5,684         4,149         3,180         1,167
       Total Output........................       29,802        28,999        28,401        26,769        27,122
Power Generated and Purchased at
  Times of Peak Load (MW) (one hour):
  Generated by Company.....................        5,162         3,384         5,245         3,679         4,948
  Net Purchased (A)........................          785         2,654           631         1,879           962
  Peak Load (B)............................        5,947         6,038         5,876         5,558         5,910
Annual System Load Factor (%)..............         57.2          54.7          55.2          54.8          52.4
Revenues (In Thousands)
  Residential..............................   $  955,239    $  931,711    $  931,643    $  839,954    $  882,591
  Commercial...............................      879,438       852,989       869,829       842,694       850,038
  Industrial...............................      208,441       205,611       199,042       201,950       212,864
  System Sales.............................    2,043,118     1,990,311     2,000,514     1,884,598     1,945,493
  Interchange and Other Sales..............      166,964       118,027        91,543        64,323        23,845
  Other....................................       21,029        19,083        20,090        16,611        21,531
       Total...............................   $2,231,111    $2,127,421    $2,112,147    $1,965,532    $1,990,869
Sales (In Thousands) -- MWH:
  Residential..............................       10,966        10,670        10,614         9,735        10,097
  Commercial...............................       12,635        12,351        12,395        11,909        11,707
  Industrial...............................        4,591         4,433         3,763         3,663         3,708
  System Sales.............................       28,192        27,454        26,772        25,307        25,512
  Interchange and Other Sales..............        8,149         5,684         4,149         3,180         1,166
       Total...............................       36,341        33,138        30,921        28,487        26,678
Customers
  Residential..............................      988,179       978,591       968,212       956,570       939,734
  Commercial...............................      103,399       101,957       100,820        99,673        98,254
  Industrial...............................        4,161         3,967         3,800         3,761         3,584
       Total...............................    1,095,739     1,084,515     1,072,832     1,060,004     1,041,572
Average Cost of Fuel Consumed ((cents) per
  million Btu).............................       104.78        112.44        112.77        110.20        127.89
</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 page 7 for a discussion of active load management programs which may be
    activated at times of peak load.
     Certain prior-year amounts have been reclassified to conform with the
current year's presentation.
                                       11

<PAGE>
                            GAS OPERATING STATISTICS
<TABLE>
<CAPTION>
                                                                        YEAR ENDED DECEMBER 31,
                                                          1995        1994        1993        1992        1991
<S>                                                     <C>         <C>         <C>         <C>         <C>
Gas Output (In Thousands) -- DTH:
  Purchased..........................................     70,391      68,541      71,221      70,211      63,160
  LNG Withdrawn from Storage.........................        815         698         725         742         551
  Produced...........................................        528         828         259          92          17
       Total Output..................................     71,734      70,067      72,205      71,045      63,728
Delivery Service Gas
  Delivered (A)......................................     44,177      41,897      38,521      41,048      40,503
       Total.........................................    115,911     111,964     110,726     112,093     104,231
Peak Day Sendout (DTH)...............................    706,287     761,900     657,700     609,200     610,200
Capability on Peak Day (DTH).........................    847,000     847,000     847,000     847,000     817,000
Revenues (In Thousands)
  Residential........................................   $248,283    $262,736    $265,601    $242,737    $220,653
  Commercial
     Excluding Delivery Service......................    109,859     121,005     121,832     112,147      96,189
     Delivery Service................................      3,696       2,285       3,287       3,591       3,031
  Industrial
     Excluding Delivery Service......................     16,730      20,140      22,250      21,123      14,855
     Delivery Service................................     16,332       9,635      12,920      14,290      14,288
  Other..............................................      5,604       5,448       7,273       6,511       6,777
       Total.........................................   $400,504    $421,249    $433,163    $400,399    $355,793
Sales (In Thousands) -- DTH:
  Residential........................................     40,211      40,279      40,029      39,042      36,519
  Commercial
     Excluding Delivery Service......................     23,612      23,712      23,830      23,478      20,687
     Delivery Service................................      6,982       6,490       7,428       7,102       6,433
  Industrial
     Excluding Delivery Service......................      4,102       4,410       5,298       5,314       3,605
     Delivery Service................................     35,925      33,837      31,390      33,638      34,240
       Total.........................................    110,832     108,728     107,975     108,574     101,484
Customers
  Residential........................................    506,739     498,152     491,165     486,863     482,085
  Commercial.........................................     38,422      37,891      37,518      37,000      36,561
  Industrial.........................................      1,334       1,354       1,353       1,412       1,385
       Total.........................................    546,495     537,397     530,036     525,275     520,031
</TABLE>

     BGE achieved an all-time peak day sendout of 761,900 DTH on January 19,
1994.
(A) Represents gas purchased by alternate fuel customers directly from suppliers
    for which BGE receives a fee for transportation through its system
    ("delivery service"). (SEE MD&A -- RESULTS OF OPERATIONS.)
     Certain prior-year amounts have been reclassified to conform with the
current year's presentation.
                                       12

<PAGE>
                                   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
GENERAL
     Diversified businesses consist of the operations of the Constellation
Companies, HP&S and its subsidiary MES, EP&S, and BNG, Inc.
     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 25 power
generating projects in operation or under construction accounting for $345
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 121 MW, waste coal 182 MW, wood burning 70 MW,
hydro 30 MW, and natural gas 182 MW. In addition, another $12 million has been
spent on projects in development. The Constellation Companies also participate
in the operation and maintenance of 14 power generation projects existing or
under construction, 10 of which are projects in which the Constellation
Companies hold an ownership interest. Financial investments account for $206
million of the Constellation Companies' assets. These assets include $92 million
in internally and externally managed securities portfolios, $78 million in a
monoline financial guaranty (credit enhancement) company, and $36 million in
tax-oriented transactions. Real estate and senior living projects account for
$495 million of the Constellation Companies' assets. These projects include raw
land, office buildings, retail, and commercial projects, an entertainment,
dining, and retail complex in Orlando, Florida, 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 $197 million representing ownership interests in 16 projects
which 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 next lowest cost
generation to service the demands on its system. These power generation projects
are scheduled to convert to supplying electricity at avoided cost rates in
various years beginning in late 1996 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 could experience reduced earnings or incur losses
associated with these projects, which could be significant. While nine projects
transition from fixed to variable energy rates in the 1996 through 1998
timeframe, revenues from the other projects having SO4 contracts are expected to
continue to increase during this period tending to offset revenue declines on
the nine projects. Six of the seven largest revenue producing projects will not
make the transition to variable energy rates until the 1999-2000
                                       13

<PAGE>
timeframe such that any material reductions in revenues would not be anticipated
until the years 2000 and 2001. 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, renegotiating the power purchase agreements, restructuring financings,
and selling its ownership interests in the projects. Two of these wholesale
power generating projects, in which the Constellation Companies' investment
totals $30 million, have executed agreements with Pacific Gas & Electric (PG&E)
providing for the curtailment of output through the end of the fixed-price
period in return for payments from PG&E. The payments from PG&E during the
curtailment period will be sufficient to fully amortize the existing project
finance debt. However, following the curtailment period, the projects remain
contractually obligated to commence production of electricity at the avoided
cost rates, which could result in reduced earnings or losses for the reasons
described above. The Company cannot predict the impact that these matters
regarding any of the 16 projects may have on the Constellation Companies or the
Company, but the impact could be material.
     HP&S was formed in mid 1994. HP&S is engaged in the sales and service of
gas and electric appliances. This business recently was expanded to include
kitchen remodeling and servicing of heating and air conditioning systems. In
December 1994, HP&S acquired MES, a company specializing in installation of
commercial and residential heating, air conditioning, and plumbing.
     EP&S was formed in late 1995. EP&S provides a broad range of customized
energy services to major customers including industrial, institutional, and
government customers in commercial office buildings, warehouses, educational,
healthcare, and retail facilities. These energy services include customer
electrical system improvements, lighting and mechanical engineering services,
campus and multi-building systems, brokering and associated financial contracts,
and district chilled water systems.
     BNG, Inc. is a wholly owned subsidiary of BGE which engages in natural gas
brokering.
CAPITAL REQUIREMENTS
     Capital requirements for diversified businesses for 1993 through 1995,
along with estimated amounts for 1996 through 1998, are set forth below:
<TABLE>
<CAPTION>
                                                           1993    1994   1995    1996    1997    1998
<S>                                                        <C>     <C>    <C>     <C>     <C>     <C>
                                                                          (IN MILLIONS)
Retirement of long-term debt............................   $222    $37    $ 55    $ 49    $135    $138
Investment requirements.................................     78     51     118      92      71      82
  Total diversified businesses..........................   $300    $88    $173    $141    $206    $220
</TABLE>

     The investment requirements shown above include the Constellation
Companies' portion of equity funding to committed projects under development as
well as net loans made to project partnerships. The investment requirements for
past periods reflect actual funding of projects, whereas investment requirements
for the years 1996-1998 reflect the Constellation Companies' estimate of funding
during such periods for ongoing and anticipated projects. Also, guarantees of
$35 million may be called which are not included above.
     Estimates of the Constellation Companies' 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. The Constellation Companies' investment requirements have been
met in the past through the internal generation of cash and through borrowings
from institutional lenders.
     The investment requirements shown above do not include amounts for the
Company's other diversified businesses because to date the investment
requirements of those businesses have been minimal.
     See NOTES 3 AND 4 TO CONSOLIDATED FINANCIAL STATEMENTS AND
MD&A -- LIQUIDITY AND CAPITAL RESOURCES -- DIVERSIFIED BUSINESSES CAPITAL
REQUIREMENTS for additional information about diversified activities.
                                       14

<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
$174 million during the five-year period 1991-1995. It is estimated that the
capital expenditures necessary to comply with such standards and regulations
will be approximately $9 million, $20 million, and $39 million for 1996, 1997,
and 1998, 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 ash as structural fill material in a
                                       15

<PAGE>
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 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. 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.
                                       16

<PAGE>
     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. No formal legal proceedings have been instituted
against BGE with respect to these sites. The technology for cleaning up such
sites is still developing, and potential remedies for these sites have not been
determined. As explained in NOTE 12 TO THE CONSOLIDATED FINANCIAL STATEMENTS on
page 52, BGE has recognized estimated environmental costs at these sites
totaling $38.6 million as of December 31, 1995. Any cleanup costs for these
sites in excess of the amount accrued, which could be significant in total,
cannot presently be estimated.
     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). The plaintiffs are owners of a non-hazardous waste landfill located
in Imperial County, California. The plaintiffs allege that defendants delivered
hazardous materials consisting of spent geothermal filters containing certain
metals used in the operation of four geothermal projects. The claims are made
under the Superfund statute and state and common law against the operators,
project owners and others. Certain CPI subsidiaries have ownership interests in
three of the projects. These Constellation Companies have indemnification rights
from project lessees and operators. Approximately 45 other defendants, in
addition to CPI, have been named to date. The Constellation Companies are
currently evaluating the claims and site investigation is at a preliminary
stage. As a result, total investigation and clean up costs, as well as the
Constellation Companies' share of such costs, cannot presently be estimated.
                                   EMPLOYEES
     As of December 31, 1995, BGE employed 7,275 people for its utility
operations and 729 people for its subsidiaries, excluding the Constellation
companies. Five hundred seventy-five people were employed by Constellation
Holdings, Inc., including its subsidiaries involved in the operation of power
projects and senior living facilities. In addition, the Constellation Companies
employ approximately 800 employees at an entertainment, dining, and retail
complex in Orlando, Florida.
                                       17

<PAGE>
ITEM 2.  PROPERTIES
     ELECTRIC:  The principal electric generating plants of BGE are as follows:
<TABLE>
<CAPTION>
                                                           INSTALLED                            GENERATION (MWH)
          PLANT                      LOCATION            CAPACITY (MW)     PRIMARY FUEL        1995           1994

                                                    (AT DECEMBER 31, 1995)
<S>                          <C>                         <C>               <C>              <C>            <C>
Steam
  Calvert Cliffs             Calvert County, MD              1,675            Nuclear       12,937,965     11,219,516
  Brandon Shores             Anne Arundel County, MD         1,291             Coal          9,091,443      8,857,557
  Herbert A. Wagner          Anne Arundel County, MD         1,006         Coal/Oil/Gas      3,002,183      2,940,978
  Charles P. Crane           Baltimore County, MD              380             Coal          1,631,798      1,847,851
  Gould Street               Baltimore City, MD                104              Oil             66,851        124,323
  Riverside                  Baltimore County, MD               78            Oil/Gas           40,229          9,146
Jointly Owned -- Steam
  Keystone                   Armstrong and                     359(A)          Coal          2,429,568      2,188,760
                             Indiana Counties, PA
  Conemaugh                  Indiana County, PA                181(A)          Coal          1,244,060      1,156,109
Combustion Turbine
  Notch Cliff                Baltimore County, MD              128              Gas             27,702         11,472
  Perryman                   Harford County, MD                350            Oil/Gas           42,875         26,960
  Westport                   Baltimore City, MD                121              Gas             19,133         10,266
  Riverside                  Baltimore County, MD              173            Oil/Gas            7,118          8,711
  Philadelphia Road          Baltimore City, MD                 64              Oil              4,813          8,250
  Charles P. Crane           Baltimore County, MD               14              Oil              1,237          1,804
  Herbert A. Wagner          Anne Arundel County, MD            14              Oil                971          1,300
    Totals                                                   5,938                          30,547,946     28,413,003
</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 on page 10.
     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 as 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.
ITEM 3.  LEGAL PROCEEDINGS
ASBESTOS
     Since 1993, BGE was 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. The 516 non-employee plaintiffs each claim $6
million in damages ($2 million compensatory and $4 million punitive). BGE does
not know
                                       18

<PAGE>
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 two manufacturers -- Owens Corning
Fiberglass and Pittsburgh Corning Corp. -- against BGE and approximately eight
others, as third-party defendants. Owens Corning Fiberglass has dismissed its
claims against BGE. The second type 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 two manufacturers, 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.
ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
     Not Applicable.
                                       19

<PAGE>
ITEM 10.  EXECUTIVE OFFICERS OF THE REGISTRANT
     Executive Officers of the Registrant are:
<TABLE>
<CAPTION>
                                                                           OTHER OFFICES OR POSITIONS
          NAME              AGE            PRESENT OFFICE                 HELD DURING PAST FIVE YEARS
<S>                         <C>   <C>                                <C>
Christian H. Poindexter      57   Chairman of the Board (A)          Vice Chairman of the Board
                                    (Since January 1, 1993)
Edward A. Crooke             57   Chairman of the Board -            President, Utility Operations
                                    Subsidiaries and President (B)
                                    (Since January 1, 1996)
Bruce M. Ambler              56   President and Chief Executive
                                    Officer
                                    Constellation Holdings, Inc.
                                    (Since August 1, 1989)
George C. Creel              62   Executive Vice President           Senior Vice President, Generation
                                    and acting Chief Operating       Senior Vice President
                                    Officer                          Vice President, Nuclear Energy
                                    (Since January 1, 1996)
Robert E. Denton             53   Senior Vice President              Vice President, Nuclear Energy
                                    Generation                       Plant General Manager, Calvert
                                    (Since January 1, 1996)          Cliffs Nuclear Power Plant
Thomas F. Brady              46   Vice President                     Vice President, Customer Service
                                    Customer Service and             and Accounting
                                    Distribution                     Vice President, Accounting and
                                    (Since July 1, 1993)             Economics
Herbert D. Coss, Jr.         61   Vice President                     Vice President, Marketing and
                                    Gas                              Gas Operations
                                    (Since October 1, 1994)          Vice President, Electric Intercon-
                                                                     nection and Transmission
                                                                     Vice President, Interconnection
                                                                     and Operations
Charles H. Cruse             51   Vice President                     Plant General Manager, Calvert
                                    Nuclear Energy                   Cliffs Nuclear Power Plant
                                    (Since January 1, 1996)          Manager, Nuclear Engineering
Carserlo Doyle               53   Vice President                     Manager, Telecommunications
                                    Electric Interconnection         Principal Engineer -- Electric
                                    and Transmission                 Interconnection
                                    (Since January 1, 1994)
Jon M. Files                 60   Vice President
                                    Management Services
                                    (Since September 1, 1981)
Sharon S. Hostetter          51   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             51   Vice President                     Manager, Fossil Engineering
                                    Fossil Energy                    Manager, Fossil Engineering
                                    (Since January 1, 1993)          Services
G. Dowell Schwartz, Jr.      59   Vice President
                                    General Services
                                    (Since April 1, 1990)
Charles W. Shivery           50   Vice President                     Vice President, Corporate
                                    Finance and Accounting,          Finance Group
                                    Chief Financial Officer and      Treasurer and Secretary
                                    Secretary
                                    (Since July 1, 1993)
Joseph A. Tiernan            57   Vice President                     Vice President, Corporate
                                    Corporate Affairs                Administration
                                    (Since February 1, 1993)
</TABLE>
                                       20

<PAGE>
<TABLE>
<S>                         <C>   <C>                                <C>
Stephen F. Wood              43   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
                                                                     Manager, Transportation
</TABLE>

(A) Chief Executive Officer, Director, and member of the Executive Committee.
(B) Chief Operating Officer, Director, and member of the Executive Committee.
                                       21

<PAGE>
     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 officer and any other person pursuant
to which the officer was selected.
                                    PART II
ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
STOCK TRADING
     BGE's Common Stock, which is traded under the ticker symbol BGE, is listed
on the New York, Chicago, and Pacific stock exchanges, and has unlisted trading
privileges on the Boston, Cincinnati, and Philadelphia exchanges.
     As of February 29, 1996, there were 79,507 common shareholders of record.
DIVIDEND POLICY
     The Common Stock is entitled to dividends when and as declared by the Board
of Directors. There are no limitations in any indenture or other agreements on
payment of dividends; however, holders of Preferred Stock (first) and holders of
Preference Stock (next) are entitled to receive, when and as declared, from the
surplus or net profits, cumulative yearly dividends at the fixed preferential
rate specified for each series and no more, payable, quarterly, and to receive
when due the applicable Preference Stock redemption payments, before any
dividend on the Common Stock shall be paid or set apart.
     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, 1995 and 1994 in the amounts set forth below.
COMMON STOCK DIVIDENDS AND PRICE RANGES
<TABLE>
<CAPTION>
                              1996 (THROUGH MARCH 12, 1996)
                             DIVIDEND             PRICE*
                             DECLARED       HIGH         LOW
<S>                          <C>          <C>          <C>
First Quarter.............   $ .39        $29-1/2      $26-3/8
Second Quarter............
Third Quarter.............
Fourth Quarter............
  Total...................
</TABLE>

<TABLE>
<CAPTION>
                                          1995
                             DIVIDEND             PRICE*
                             DECLARED       HIGH         LOW
<S>                          <C>          <C>          <C>
First Quarter.............   $ .38        $25          $22
Second Quarter............     .39         26-1/2       23-1/8
Third Quarter.............     .39         26-5/8       24-3/8
Fourth Quarter............     .39         29           25-1/2
  Total...................   $1.55
</TABLE>

<TABLE>
<CAPTION>
                                          1994
                             DIVIDEND                 PRICE*
                             DECLARED       HIGH         LOW
<S>                          <C>          <C>          <C>
First Quarter.............   $ .37        $25-1/2      $22-3/8
Second Quarter............     .38         24-3/8       20-1/2
Third Quarter.............     .38         23-3/4       20-3/4
Fourth Quarter............     .38         23-5/8       21-1/4
  Total...................   $1.51
</TABLE>

*Based on New York Stock Exchange Composite Transactions as reported in the
 eastern edition of THE WALL STREET JOURNAL.
                                       22

<PAGE>

Item 6. Selected Financial Data
<TABLE>
<CAPTION>
                                                                                                                  Compound
                                                   1995         1994         1993          1992       1991         Growth
---------------------------------------------------------------------------------------------------------------------------
                                               (Dollar amounts in thousands, except per share amounts)         5-year  10-Year
<S>                                          <C>          <C>          <C>           <C>         <C>         <C>       <C>
Summary of Operations

   Total Revenues                            $2,934,799   $2,782,985   $2,741,385    $2,559,536  $2,514,631    5.47%    4.56%
   Expenses Other Than Interest and Income
      Taxes                                   2,239,107    2,147,726    2,124,993     2,024,227   2,026,910    3.10     4.93
----------------------------------------------------------------------------------------------------------------------------
   Income From Operations                       695,692      635,259      616,392       535,309     487,721   16.36     3.46
   Other Income                                   8,819       32,365       20,310        22,132      28,095  (23.87)   (4.60)
---------------------------------------------------------------------------------------------------------------------------
   Income Before Interest and Income Taxes      704,511      667,624      636,702       557,441     515,816   14.33     3.30
   Net Interest Expense                         196,977      190,154      188,764       189,747     196,588    3.58     5.98
----------------------------------------------------------------------------------------------------------------------------
   Income Before Income Taxes                   507,534      477,470      447,938       367,694     319,228   21.03     2.43
   Income Taxes                                 169,527      153,853      138,072       103,347      85,547   53.41     1.11
----------------------------------------------------------------------------------------------------------------------------
   Income Before Cumulative Effect of
      Change in Accounting Method               338,007      323,617      309,866       264,347     233,681   14.01     3.17
   Cumulative Effect of Change in the
      Method of Accounting for Income Taxes         ---          ---          ---           ---     19,745      ---      ---
----------------------------------------------------------------------------------------------------------------------------
   Net Income                                   338,007      323,617      309,866       264,347     253,426    9.65     3.17
   Preferred and Preference Stock Dividends      40,578       39,922       41,839        42,247      42,746    0.16     4.02
----------------------------------------------------------------------------------------------------------------------------
   Earnings Applicable to Common Stock       $  297,429   $  283,695   $  268,027    $  222,100  $  210,680   11.45     3.06
============================================================================================================================

   Earnings Per Share of Common Stock
      Before Cumulative Effect of Change
         in Accounting Method                     $2.02        $1.93        $1.85         $1.63      $1.511    3.13     0.77
      Cumulative Effect of Change in the
         Method of Accounting for Income
         Taxes                                      ---          ---          ---           ---         .16     ---      ---
----------------------------------------------------------------------------------------------------------------------------
   Total Earnings Per Share of Common Stock       $2.02        $1.93        $1.85         $1.63       $1.67    7.61     0.77
============================================================================================================================

   Dividends Declared Per Share of Common
      Stock                                       $1.55        $1.51        $1.47         $1.43       $1.40    2.06     3.40

Ratio of Earnings to Fixed Charges                 3.21         3.14         3.00          2.65        2.27   12.52    (2.51)
   Ratio of Earnings to Fixed Charges and
      Preferred and Preference Stock Dividends
      Combined                                     2.52         2.47         2.34          2.08        1.82   11.38    (1.99)

Financial Statistics at Year End

   Total Assets                              $8,316,663   $8,037,502   $7,829,613    $7,208,660  $6,963,547    4.39     6.88
============================================================================================================================
   Capitalization
      Long-term debt                         $2,598,254   $2,584,932   $2,823,144    $2,376,950  $2,390,115    3.44     5.69
      Preferred stock                            59,185       59,185       59,185        59,185      59,185     ---      ---
      Redeemable preference stock               242,000      279,500      342,500       395,500     398,500   (7.89)   11.70
      Preference stock not subject to mandatory
         redemption                             210,000      150,000      150,000       110,000     110,000   13.81     1.84
      Common shareholders' equity             2,812,682    2,717,866    2,620,511     2,534,639   2,153,306    6.29     6.33
----------------------------------------------------------------------------------------------------------------------------
      Total Capitalization                   $5,922,121   $5,791,483   $5,995,340    $5,476,274  $5,111,106    4.29     5.92
============================================================================================================================

   Book Value Per Share of Common Stock          $19.07       $18.42       $17.94        $17.63      $17.00    2.84     3.98

   Number of Common Shareholders                 79,811       81,505       82,287        80,371      71,131    1.79     0.04
</TABLE>

Certain  prior-year  amounts have been  reclassified to conform with the current
year's presentation.

                                      23

                             Baltimore Gas and Electric Company and Subsidiaries

<PAGE>


Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations



This annual report presents the financial condition and results of
operations of Baltimore Gas and Electric Company (BGE) and its
subsidiaries (collectively, the Company).   Among  other  information,
it  provides   Consolidated   Financial Statements,   Notes  to
Consolidated  Financial  Statements  (Notes),   Utility Operating
Statistics,  and Selected  Financial  Data. The following  discussion
explains factors that significantly  affect the Company's results of
operations, liquidity, and capital resources.

   
Effective November 1, 1995, BGE formed a wholly owned subsidiary, BGE
Energy Projects & Services, Inc. (EP&S). EP&S' revenues and expenses are
included in diversified businesses revenues and diversified businesses
selling, general, and administrative expenses, respectively.
    

Results of Operations

Earnings per Share of Common Stock
Consolidated  earnings  per share  were  $2.02  for 1995 and $1.93 for
1994,  an increase of $.09 and $.08 from prior-year amounts,
respectively. The changes in earnings  per share  reflect a higher
level of  earnings  applicable  to common stock,  offset  partially by a
larger number of outstanding  common shares.  The summary below presents
the earnings-per-share amounts.

<TABLE>
<CAPTION>
                                     1995       1994     1993
--------------------------------------------------------------------
<S>                                 <C>        <C>      <C>
Utility business                    $1.84      $1.81    $1.77
Diversified businesses                .18        .12      .08
--------------------------------------------------------------------
Total                               $2.02      $1.93    $1.85
====================================================================
</TABLE>

Earnings Applicable to Common Stock
Earnings  applicable to common stock  increased  $13.7 million in 1995
and $15.7 million in 1994. The increases reflect higher utility and
diversified businesses earnings.

Utility  earnings  increased  in 1995  compared  to the prior year due
to higher electric  system sales  resulting from the extremely hot
summer weather in 1995, and  higher  electric  and gas sales  resulting
from the  colder  fall  weather experienced in 1995.  These factors were
partially  offset by lower electric and gas system sales resulting from
the milder weather  experienced during the first half of the year as
compared to last year; lower net other income and deductions in 1995;
and a decrease in the allowance for funds used during construction.

Utility  earnings  increased  in 1994  compared  to the prior  year due
to three principal factors: lower operations and maintenance expenses;
an increase in the allowance for funds used during construction;  and
greater sales of electricity. The higher sales of  electricity  were
primarily due to an increased  number of customers  compared to 1993.
Both 1995 and 1994 earnings  increases were offset partially by higher
depreciation and amortization  expense,  which includes the write-off of
certain Perryman costs in both years (see discussion on page 27). The
effect of weather on utility sales is discussed below.

The following factors influence BGE's utility operations earnings:
regulation by the Maryland Public Service Commission (PSC); the effect
of weather and economic conditions on sales;  and competition in the
generation and sale of electricity. The gas base rate  increase
authorized  by the PSC in November  1995  favorably affected utility
earnings  beginning in December 1995. The electric and gas base rate
increases  authorized by the PSC in April 1993 favorably  affected
utility earnings through April 1994. The electric fuel rate cases now
pending before the PSC discussed in Notes 1 and 12 could affect future
years' earnings.

Future  competition  may also affect  earnings in ways that are not
possible to predict (see discussion on page 31).


   
Earnings from diversified businesses,  which primarily represent the
operations of Constellation  Holdings, Inc. (CHI) and its subsidiaries
(collectively,  the Constellation  Companies),  BGE Home  Products &
Services,  Inc. and  Subsidiary (HP&S),  and EP&S,  increased  during
both 1995 and 1994.  The  reasons for these changes are discussed in the
"Diversified  Businesses Earnings" section on pages 28 and 29.
    

Effect of Weather on Utility Sales
Weather  conditions affect BGE's utility sales. BGE measures weather
conditions using  degree  days. A degree day is the  difference  between
the average  daily actual  temperature and the baseline  temperature of
65 degrees.  Hotter weather during the summer,  measured by more
cooling  degree  days,  results in greater demand for electricity to
operate cooling  systems.  Conversely,  cooler weather during the
summer, measured by fewer cooling degree days, results in less demand
for electricity to operate cooling systems. Colder weather during the
winter, as measured  by  greater  heating  degree  days,  results  in
greater  demand  for electricity  and gas to operate  heating  systems.
Conversely,  warmer  weather during the winter, measured by fewer
heating degree days, results in less demand for electricity and gas to
operate heating systems.  The degree-days chart below presents
information  regarding  cooling and  heating  degree days for 1995 and
1994.

                                      24

Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

<TABLE>
<CAPTION>
                                                    30-Year
                                   1995      1994   Average
--------------------------------------------------------------------
<S>                               <C>         <C>       <C>
Cooling degree days               1,056       949       804
Percentage change
    compared to prior year         11.3%       9.7%
Heating degree days               4,601     4,670     4,901
Percentage change
    compared to prior year         (1.5)%    (5.8)%
</TABLE>

BGE Utility Revenues and Sales
Electric revenues changed during 1995 and 1994 because of the following
factors:

<TABLE>
<CAPTION>
                                              1995          1994
--------------------------------------------------------------------
                                                 (In millions)
<S>                                       <C>          <C>
System sales volumes                      $43.4        $  9.9
 Base rates                                23.2           1.4
 Fuel rates                               (13.8)        (21.5)
--------------------------------------------------------------------
Revenues from system sales                 52.8         (10.2)

Interchange and other sales                49.0          26.5

Other revenues                              1.4          (1.9)
--------------------------------------------------------------------
Total electric revenues                  $103.2        $ 14.4
====================================================================
</TABLE>

Electric system sales represent  volumes sold to customers  within BGE's
service territory at rates  determined  by the PSC.  These amounts
exclude  interchange sales and sales to other utilities,  discussed
separately later.  Following is a comparison of the changes in electric
system sales volumes:

<TABLE>
<CAPTION>
                                          1995         1994
--------------------------------------------------------------------
<S>                                         <C>           <C>
Residential                                 2.8%          0.5%
Commercial                                  2.3          (0.4)
Industrial                                  3.6          17.8
Total                                       2.7           2.5
</TABLE>

The  increase  in sales to  residential  and  commercial  customers
during 1995 reflects the  extremely  hot summer and colder fall  weather
during 1995 and an increase  in the  number  of  customers,  offset
partially  by  milder  weather experienced during the first half of the
year as compared to last year. Sales to industrial  customers  increased
primarily  due to an increase in the number of customers and the
increased  sale of  electricity  to Bethlehem  Steel,  offset partially
by lower usage by other industrial customers. Bethlehem Steel has been
purchasing its full electricity requirements from BGE since March of
1994 and is selling  power  produced with its own  generating
facilities to BGE rather than using the power to reduce its
requirements.

In  1994,  sales  to  residential  and  commercial  customers  were
essentially unchanged  from the prior year due to three  factors:  the
number of  customers increased;  higher  sales  from  extreme  weather
conditions  early in the year slightly  exceeded  lower  sales from
milder  weather in the second half of the year; and  usage-per-customer
decreased.  Sales to industrial customers reflect primarily  an increase
in the sale of  electricity  to  Bethlehem  Steel,  which purchased more
electricity  from BGE due to increased steel  production and the fact
that Bethlehem Steel has been purchasing its full electricity
requirements from BGE since March of 1994.

Base rates are  affected  by two  principal  items:  rate  orders by the
PSC and recovery of eligible  electric  conservation  program  costs
through the energy conservation  surcharge.  Base rates  increased in
1995  compared to 1994 due to recovery of a higher level of eligible
electric  conservation  program costs and the  ability  to  collect  the
full  amount  of  energy  conservation  surcharge revenues,  portions
of which  had been  deferred  subject  to refund in 1994 as discussed
below. Base rates increased  slightly during 1994 due to the remaining
effect of the PSC's April 1993 rate order,  offset  partially by the
deferral of the portion of energy conservation surcharge billings
subject to refund.

Under the  energy  conservation  surcharge,  if the PSC  determines
that BGE is earning in excess of its authorized rate of return,  BGE
will have to refund (by means of lowering future surcharges) a portion
of energy conservation  surcharge revenues to its customers. The portion
subject to the refund is compensation for foregone  sales  from
conservation   programs  and  incentives  for  achieving conservation
goals and will be refunded to customers with interest beginning in the
ensuing July when the annual resetting of the  conservation  surcharge
rates occurs.  BGE  earned  in  excess of its  authorized  rate of
return on  electric operations  for the period July 1, 1993 through June
30, 1994. As a result,  BGE deferred the portion of electric energy
conservation  revenues subject to refund for the period December 1993
through November 1994. The deferral of these billings totaled $20.1
million.

Changes in fuel rate  revenues  result from the  operation of the
electric  fuel rate  formula.  The fuel rate  formula is designed to
recover the actual cost of fuel, net of revenues from  interchange
sales and sales to other utilities (see Notes 1 and 12).  Changes in
fuel rate revenues and  interchange and other sales normally do not
affect earnings.  However,  if the PSC were to disallow recovery of any
part of these costs, earnings would be reduced as discussed in Note 12.

Fuel rate revenues decreased during both 1995 and 1994 due to a lower
fuel rate, offset partially by increased electric system sales volumes.
The rate was lower in  both  years  because  of a  less-costly
twenty-four  month  generation  mix resulting from greater  generation
at the Calvert Cliffs Nuclear Power Plant and Brandon  Shores Power
Plant compared to the previous year, as well as lower fuel costs.  BGE
expects  electric fuel rate revenues to remain  relatively  constant
through 1996.

Interchange   and  other  sales   represent   sales  of  BGE's   energy
to  the Pennsylvania-New  Jersey-Maryland Interconnection (PJM) and
other utilities. The PJM is a regional  power pool of eight member
companies  including  BGE.  These sales  occur  after BGE has  satisfied
the demand  for its own system  sales of electricity,  if BGE's
available  generation  is the  least  costly  available. Interchange
and other sales  increased  during 1995 and 1994  because BGE had a
less-costly  generation  mix than  the  other  utilities.  The
less-costly  mix reflects  greater  generation  from  the  Brandon
Shores  Power  Plant  and the continued operation of the Calvert Cliffs
Nuclear Power Plant, which generated a record level of electricity
during 1995.

                                      25

                             Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

Gas revenues changed during 1995 and 1994 because of the following factors:

<TABLE>
<CAPTION>
                                          1995          1994
--------------------------------------------------------------------
                                              (In millions)
<S>                                       <C>           <C>
Sales volumes                             $  0.2        $  3.6
Base rates                                   6.4           2.4
Gas cost adjustment revenues               (27.4)        (16.1)
Other revenues                               0.1          (1.8)
--------------------------------------------------------------------
Total gas revenues                        $(20.7)       $(11.9)
====================================================================
</TABLE>


The changes in gas sales volumes compared to the year before were:

<TABLE>
<CAPTION>
                                          1995         1994
--------------------------------------------------------------------
<S>                                         <C>           <C>
Residential                                 (0.2)%        0.6%
Commercial                                   1.3         (3.4)
Industrial                                   4.7          4.2
Total                                        1.9          0.7
</TABLE>

Total gas sales increased  during 1995 as a result of higher sales to
commercial and industrial customers,  while sales to residential
customers were essentially the same as last year. Sales to commercial
customers increased compared to last year  due to an  increase  in the
number  of  customers,  increased  usage  per customer,  and the colder
fall  weather  in 1995,  offset  partially  by milder weather  during
the  first  half of the  year.  Sales to  industrial  customers
increased compared to last year due to greater usage of gas per
customer.  Total gas sales  increased  during 1994  because of higher
sales to  residential  and industrial  customers,  offset partially by
lower sales to commercial customers. Sales to industrial  customers
reflect primarily greater usage of natural gas by Bethlehem  Steel.
Sales to commercial and industrial  customers were negatively impacted
because delivery service  customers either  voluntarily  switched their
fuel  source  from  natural  gas  to  alternate  fuels,  or  were
involuntarily interrupted by BGE as a result of extreme winter weather
conditions in the first quarter of 1994. Interruptible customers
maintain alternate fuel sources and pay reduced rates in exchange for
BGE's right to interrupt service during periods of peak demand.

Base rates increased  slightly during 1995 and 1994 due to an increased
recovery of eligible  gas  conservation  program  costs  through the
energy  conservation surcharge. In addition, base rates increased
slightly during 1995 as a result of the PSC's November 1995 rate order,
which increased annual base rate revenues by $19.3 million,  including
$2.4 million to recover higher  depreciation  expense. Future gas base
rate revenues are expected to be impacted  favorably as a result of this
order.

Changes in gas cost adjustment  revenues result  primarily from the
operation of the purchased gas adjustment clause, commodity
charge  adjustment  clause,  and the actual cost  adjustment  clause,
which are designed  to  recover  actual  gas  costs  (see  Note  1).
Changes  in gas cost adjustment  revenues  normally  do not  affect
earnings.  Gas  cost  adjustment revenues  decreased  during  1995  and
1994  because  of lower  gas  prices  for purchased gas and lower sales
volumes  subject to gas cost  adjustment  clauses. Delivery  service
sales volumes are not subject to gas cost  adjustment  clauses because
delivery  service  customers  purchase  their gas  directly  from third
parties.

BGE Utility Fuel and Energy Expenses
Electric fuel and purchased energy expenses were as follows:

<TABLE>
<CAPTION>
                                    1995       1994      1993
--------------------------------------------------------------------
                                          (In millions)
<S>                               <C>        <C>       <C>   
Actual costs                      $554.5     $541.2    $483.9
Net recovery of costs
   under electric fuel rate
   clause (see Note 1)              24.3        1.1      50.7
--------------------------------------------------------------------
Total expense                     $578.8     $542.3    $534.6
====================================================================
</TABLE>


Total electric fuel and purchased energy expenses  increased in 1995 as
a result of the operation of the electric fuel rate clause and increased
actual electric costs.  Actual electric fuel and purchased  energy costs
increased  during 1995 primarily due to a higher net output of
electricity and higher  purchased energy and capacity costs,  offset
partially by a less costly  generation mix resulting primarily from a
shorter refueling and maintenance  outage at the Calvert Cliffs Nuclear
Power Plant as compared to the prior year.

Total electric fuel and purchased energy expenses  increased in 1994 as
a result of increased  actual  electric costs and the operation of the
electric fuel rate clause. Actual electric fuel and purchased energy
costs increased during 1994 as a result of a more  costly  generation
mix and an increase in the net output of electricity generated to meet
the demand of BGE's system and the PJM system. The cost of the
generation mix increased due to higher  purchased  energy costs and
scheduled outages at the Calvert Cliffs Nuclear Power Plant in 1994.

Purchased gas expenses were as follows:

<TABLE>
<CAPTION>
                                    1995       1994     1993
--------------------------------------------------------------------
                                           (In millions)
<S>                                <C>       <C>       <C>   
Actual costs                       $205.9    $222.7    $246.4
Net (deferral) recovery of costs
  under purchased gas adjustment
  clause (see Note 1)                (7.8)      1.9      (3.7)
--------------------------------------------------------------------
Total expense                      $198.1    $224.6    $242.7
====================================================================
</TABLE>

Total purchased gas expenses decreased in 1995 due to significantly
lower actual purchased gas costs and the operation of the  purchased gas
adjustment  clause. Actual purchased gas costs

                                      26

Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

decreased in 1995 due to lower gas prices which reflect market
conditions.  This decrease would have been greater  except for a
take-or-pay  refund which reduced actual costs in 1994.

Total purchased gas expenses decreased in 1994 due to significantly
lower actual purchased  gas costs,  offset  partially by the  operation
of the  purchased gas adjustment  clause.  Actual  purchased gas costs
decreased  during 1994 for two reasons:  lower gas prices and lower
output associated with the decreased demand for BGE gas. The lower gas
prices reflect market  conditions and take-or-pay and other supplier
refunds,  offset by higher costs related to the implementation of
Federal Energy Regulatory Commission (FERC) Order 636 and higher demand
charges.

Purchased  gas costs  exclude  gas  purchased  by  delivery  service
customers, including Bethlehem Steel, who obtain gas directly from third
parties.

Other Operating Expenses
Operations  and  maintenance  expenses  were  essentially  unchanged  in
1995 as compared to the prior year.  Operations  expense decreased
during 1994 primarily due to labor savings  achieved as a result of the
Company's  employee  reduction programs discussed in Note 7 and
continuing cost control efforts.  These savings offset $18.1  million of
expense from the  amortization  of the cost of the 1993 and 1992
Voluntary Special Early Retirement Programs (VSERP) and a $10.0 million
charge for a bonus paid to  employees  in lieu of a general  wage
increase.  In addition,  operations  expense for 1994 decreased because
operations expense for 1993 included a $17.2 million charge for certain
employee  reduction  programs, offset  partially by a credit to expense
equivalent to the $9.8 million cost of termination  benefits  associated
with the Company's 1992 VSERP.  Operations and maintenance expenses are
expected to decline in 1996 due to ongoing cost control efforts of the
Company.  Maintenance expense decreased during 1994 due primarily to
lower costs at the Calvert Cliffs Nuclear Power Plant.

Depreciation  and amortization  expense  increased during 1995 because
of higher levels of depreciable  plant in service and energy
conservation  program costs, and the completion of a facility-specific
study of the cost to decommission the Calvert  Cliffs Nuclear Power
Plant.  The higher level of  depreciable  plant in service,  which is
primarily  due to certain  capital  additions at the Calvert Cliffs
Nuclear  Power  Plant,  resulted in an increase of  approximately  $12.9
million  in   depreciation   and   amortization   expense   during 1995.
The facility-specific  study  resulted  in a $9  million increase  in
depreciation expense.  Depreciation and amortization expense increased
during 1994 because of higher levels of depreciable plant in service and
energy  conservation  program costs. The increase in depreciable plant
in service resulted from the addition of electric  transmission and
distribution plant and certain capital additions at the Calvert Cliffs
Nuclear Power Plant during 1994. Additionally,  as discussed below,
depreciation and amortization expense during 1995 and 1994 reflected the
write-off of certain Perryman costs.

Initially,  BGE had planned to build two combined cycle  generating
units at its Perryman site with each unit  consisting of two  combustion
turbines and a heat recovery steam generator. However, due to
significant changes in the environment in which  utilities  operate,
BGE decided in 1994 not to  construct  the second combined  cycle  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 PSC'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  (PEPCO) which has some
available  generating  capacity,  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 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.

Taxes  other than  income  taxes  increased  slightly  during  1995 and
1994 due primarily to higher property taxes resulting from higher levels
of utility plant in service.

Inflation  affects the Company through increased  operating  expenses
and higher replacement  costs for utility plant assets.  Although timely
rate increases can lessen the effects of inflation, the regulatory
process imposes a time lag which can delay BGE's recovery of increased
costs. There is a regulatory lag primarily because rate  increases  are
based on  historical  costs  rather than  projected costs. The PSC has
historically  allowed recovery of the cost of replacing plant assets,
together with the opportunity to earn a fair return on BGE's investment,
beginning at the time of replacement.

Other Income and Expenses
The allowance for equity funds used during  construction  (AFC)
decreased during 1995 because of a lower level of construction work in
progress  resulting from a decrease in new  construction  activity and
the placement of several projects in service.  AFC  increased  during
1994 because of a higher level of  construction work in progress which
was offset partially by the lower AFC rate established by the PSC in the
April 1993 rate order.

                                      27

                             Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

Net other income and deductions decreased in 1995 primarily due to
approximately $12.1 million in lower other interest and finance charge
income,  and a decrease of $3.8 million in the gain on the sale of
receivables  and property.  Net other income  and  deductions  increased
in 1994  primarily  due to a lower  level of charitable contributions
and $3.9 million of gains on the sale of receivables.

Interest expense  increased during 1995 due to a combination of higher
levels of debt outstanding and higher  short-term  interest rates
compared to 1994, offset partially  by increased  capitalized  interest
on the  Constellation  Companies' projects. Interest expense increased
slightly during 1994 due primarily to lower capitalized  interest on the
Constellation  Companies' power generation systems, offset partially by
the accrual by BGE of carrying charges on electric  deferred fuel costs
excluded from rate base (see Note 5).

Income tax expense  increased  during 1995 and 1994 due to higher
taxable income from utility operations and the Constellation Companies.

Diversified Businesses Earnings
Earnings per share from diversified businesses were:

<TABLE>
<CAPTION>
                                        1995    1994    1993
--------------------------------------------------------------------
<S>                                    <C>      <C>     <C> 
Constellation Companies
  Power generation systems             $ .13    $ .10   $ .07
  Financial investments                  .08      .03     .10
  Real estate development and senior
    living facilities                   (.02)    (.03)   (.04)
  Effect of 1993 Tax Act                  -       -      (.04)
  Other                                 (.01)    (.01)   (.01)
--------------------------------------------------------------------
Total Constellation Companies            .18      .09     .08
BGE Home Products & Services, Inc.
  and Subsidiary                         .00      .03     -
BGE Energy Projects & Services, Inc.     .00      -       -
--------------------------------------------------------------------
Total diversified businesses           $ .18    $ .12   $ .08
====================================================================
</TABLE>


The  Constellation  Companies'  power generation  systems business
includes the development,  ownership, management, and operation of
wholesale power generating projects in which the Constellation
Companies hold ownership interests, as well as the provision of services
to power  generation  projects under  operation and maintenance
contracts.  Power generation systems earnings increased during 1995 due
primarily to higher equity earnings on the  Constellation  Companies'
energy projects and a gain on the sale of certain operating and
maintenance  contracts. Power generation  systems  earnings  increased
in 1994 primarily due to payments for the  curtailment  of output at two
wholesale  power  generating  projects as discussed below.

The Constellation Companies' investment in wholesale power generating
projects includes $197 million representing ownership interests in 16
projects which sell electricity in California under Interim Standard
Offer No. 4 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  next lowest cost  generation  to
service the demands on its system. These  power generation   projects
are  scheduled  to  convert  to  supplying electricity  at  avoided
cost  rates in various  years  beginning  in late 1996 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. If current avoided  cost  levels were to  continue
into 1996 and  beyond,  the Constellation  Companies  could  experience
reduced  earnings  or incur losses associated with these projects,
which could be significant.  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,  renegotiating
the  power  purchase agreements, restructuring financings, and selling
its ownership interests in the projects.  Two of these  wholesale  power
generating  projects,  in  which  the Constellation Companies'
investment totals $30 million, have executed agreements with  Pacific
Gas & Electric  (PG&E)  providing  for the curtailment  of output
through the end of the fixed price period in return for payments from
PG&E.  The payments  from PG&E during the curtailment  period will be
sufficient to fully amortize the existing project finance debt.
However,  following the curtailment period, the projects remain
contractually  obligated to commence  production of electricity at the
avoided cost rates, which could result in reduced earnings or losses for
the reasons  described  above.  The Company cannot predict the impact
that  these  matters   regarding  any  of  the 16  projects  may  have
on  the Constellation Companies or the Company, but the impact could be
material. See the section titled "Diversified Businesses" on page 13 for a
more recent update of these matters.

Earnings from the Constellation  Companies'  portfolio of financial
investments include  capital  gains and losses,  dividends,  income from
financial  limited partnerships,  and income from financial guaranty
insurance companies. Financial investment  earnings  were  higher  in
1995  due to  favorable  earnings  on the Companies' marketable
securities,  increased gains from financial  partnerships, and higher
earnings from  financial  guaranty  insurance  companies.  Financial
investment  earnings  decreased  during  1994 due to reduced  earnings
from the investment portfolio.  Additionally,  1993 results reflected a
$6.1 million gain from the sale of a portion of an  investment in a
financial  guaranty  insurance company.

The  Constellation  Companies' real estate  development  business
includes land under development;  office buildings; retail pro-jects;
commercial projects; an entertainment,  dining  and retail  complex in
Orlando,  Florida;  a  mixed-use planned-unit-development;  and senior
living  facilities.  The majority of these projects  are in the
Baltimore-Washington  corridor.  They have  been  affected adversely by
the  oversupply of and limited demand for land and office space due to
modest economic growth and corporate downsizings.

                                      28

Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

Earnings from real estate  development and senior living facilities in
1995 were essentially unchanged from the prior year. Earnings from real
estate development increased  slightly  during  1994 due to gains
recognized  from the sale of two retail  centers,  an  office  building,
and  interests  in  two  senior  living facilities.  The increases in
diversified  businesses'  revenues and in selling, general,  and
administrative  expenses during 1994 reflect the proceeds of these sales
and the cost of the facilities sold, respectively.

The  Constellation  Companies' real estate portfolio has experienced
continuing carrying costs and depreciation.  Additionally, the
Constellation Companies have been expensing rather than capitalizing
interest on certain undeveloped land for which  substantially  all
development  activities  have been  suspended.  These factors have
affected earnings  negatively and are expected to continue to do so
until the levels of  undeveloped  land are  reduced.  Cash flow from
real estate operations  has been  insufficient  to cover the debt
service  requirements  of certain of these projects. Resulting cash
shortfalls have been satisfied through cash  infusions  from
Constellation  Holdings,  Inc.,  which obtained the funds through a
combination  of cash flow generated by other  Constellation  Companies
and its corporate borrowings.  To the extent the real estate market
continues to improve, earnings from real estate activities are expected
to improve also.

The Constellation  Companies'  continued investment in real estate
projects is a function of market demand, interest rates, credit
availability, and the strength of the economy in general. The
Constellation Companies' Management believes that although  the real
estate  market  has  improved,  until the  economy  reflects sustained
growth   and   the   excess   inventory   in  the   market   in  the
Baltimore-Washington  corridor  goes down,  real estate  values will not
improve significantly.  If the  Constellation  Companies  were to sell
their real estate projects  in the  current  depressed  market,  losses
would  occur  in  amounts difficult to determine.  Depending  upon
market  conditions,  future sales could also result in losses. In
addition,  were the Constellation  Companies to change their  intent
about  any  project  from an intent to hold to an intent to sell,
applicable  accounting rules would require a write-down of the project
to market value at the time of such change in intent if market value is
below book value.

BGE Home  Products & Services'  earnings  decreased  during  1995 and
increased during 1994 primarily due to higher gains from receivables
sales in 1994.

   
Environmental Matters
The Company is subject to increasingly stringent federal,  state, and
local laws and  regulations  relating  to  improving  or  maintaining
the  quality  of the environment.  These laws and regulations require
the Company to remove or remedy the effect on the environment of the
disposal or release of specified substances at ongoing and former
operating sites, including Environmental Protection Agency Superfund
sites.   Details   regarding  these  matters,   including   financial
information, are presented in Note 12 and in this Annual Report
on Form 10-K under Item 1. Business - Environmental Matters.
    

Liquidity and Capital Resources

Capital Requirements
The Company's capital requirements reflect the  capital-intensive nature
of the utility business.  Actual capital  requirements for the years
1993 through 1995, along with estimated amounts for the years 1996
through 1998, are reflected below.  Certain  prior-year amounts have
been restated to conform with the current year's presentation.

<TABLE>
<CAPTION>

                                                                     1993      1994       1995       1996      1997   1998
                                                                                          (In millions)
<S>                                                                <C>         <C>        <C>       <C>       <C>     <C>
  Utility Business:
   Construction expenditures (excluding AFC)
      Electric                                                     $  365      $345       $223      $231      $205    $212
      Gas                                                              52        68         70        68        73      67
      Common                                                           41        42         51        41        47      46
---------------------------------------------------------------------------------------------------------------------------
      Total construction expenditures                                 458       455        344       340       325     325
   AFC                                                                 23        34         22        11        10      10
   Nuclear fuel (uranium purchases and processing charges)             47        42         46        45        45      44
   Deferred energy conservation expenditures                           33        41         46        34        25      27
   Deferred nuclear expenditures                                       14         8         --        --        --      --
   Retirement of long-term debt and redemption of preference stock    907       203        279        98       164     125
---------------------------------------------------------------------------------------------------------------------------
   Total utility business                                           1,482       783        737       528       569     531
Diversified Businesses:
   Retirement of long-term debt                                       222        37         55        49       135     138
   Investment requirements                                             78        51        118        92        71      82
---------------------------------------------------------------------------------------------------------------------------
   Total diversified businesses                                       300        88        173       141       206     220
Total                                                              $1,782      $871       $910      $669      $775    $751
===========================================================================================================================
</TABLE>

                                      29

                             Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

BGE Utility Capital Requirements
BGE's construction program is subject to continuous review and
modification, and actual  expenditures  may vary from the estimates
above.  Electric  construction expenditures  include the  installation
of a 5,000 kilowatt diesel  generator at the  Calvert  Cliffs  Nuclear
Power Plant  which is  scheduled  to be placed in service in 1996, and
improvements in BGE's existing  generating  plants and its transmission
and   distribution   facilities.   Future  electric   construction
expenditures do not include additional generating units.

   
During  1995,  1994,  and 1993,  the  internal  generation  of cash from
utility operations  provided 100%, 72%, and 71% respectively,  of the
funds required for BGE's capital requirements  exclusive of retirements
and redemptions of debt and preference stock. In addition,  in 1994, $70
million of cash was provided by the sale of certain BGE and HP&S
receivables  (see Note 12).  During the  three-year period  1996
through  1998,  the  Company  expects to provide  through  utility
operations 115% of the funds required for BGE's capital requirements,
exclusive of retirements and redemptions.
    

Utility capital requirements not met through the internal generation of
cash are met through the issuance of debt and equity  securities.
During the  three-year period ended December 31, 1995,  BGE's issuances
of long-term  debt,  preference stock,  and common stock were $1,237
million,  $190  million,  and $92 million, respectively.  During the
same  period,  retirements  and  redemptions  of BGE's long-term  debt
and  preference  stock totaled  $1,148 million and $219 million,
respectively,  exclusive of any redemption premiums or discounts. The
amount and timing of future  issuances and redemptions  will depend upon
market  conditions and BGE's actual capital requirements.

BGE's fixed income  securities  are rated by various  independent
credit rating agencies.  The ratings assigned reflect the rating
agencies' current  assessment of BGE's ability to pay interest,
dividends, and principal on these securities. The ratings  impact  BGE's
cost of raising  fixed  income  capital in the public markets. At the
date of this Report, BGE's securities ratings were as follows:

                            Securities Ratings Table
<TABLE>
<CAPTION>
---------------------------------------------------------------------------
                          Standard        Moody's
                           & Poors       Investors         Duff & Phelps
                        Rating Group      Service        Credit Rating Co.
---------------------------------------------------------------------------
<S>                     <C>              <C>             <C>
Senior Secured Debt           A+            A1                 AA-
(First Mortgage Bonds)
Unsecured Debt                A             A2                  A+
Preferred Stock               A            "a1"                 A+
Preference Stock              A            "a2"                 A
</TABLE>


The  Constellation  Companies'  capital  requirements are discussed
below in the section titled "Diversified Businesses Capital
Requirements-Debt and Liquidity." The Constellation Companies are
exploring expansion of their energy, real estate service, and senior
living facility  businesses.  Expansion may be achieved in a variety of
ways,  including,  without limitation,  increased investment activity
and  acquisitions.  The  Constellation  Companies  plan  to meet  their
capital requirements  with a  combination  of debt and internal
generation of cash from their  operations.  Additionally,  from  time to
time,  BGE may  make  loans to Constellation  Holdings,  Inc.,  or
contribute  equity to enhance  the  capital structure of Constellation
Holdings, Inc.

Historically, Constellation's energy projects have been in the United
States. As of  December  31,  1995,  one  of  the  Constellation
Companies  had  invested approximately $10 million in a Bolivian power
generation  company.  In addition, $10 million has been committed, of
which $1.2 million has been funded, to a fund that will invest in and
develop power projects in Latin America. Constellation's energy business
expansion may include domestic and international projects.

Diversified Businesses Capital Requirements
Debt and Liquidity
The Constellation  Companies intend to meet capital  requirements by
refinancing debt as it comes due and  through  internally  generated
cash.  These  internal sources include cash that may be generated from
operations,  sale of assets, and cash generated by tax benefits  earned
by the  Constellation  Companies.  In the event the  Constellation
Companies can obtain  reasonable value for real estate properties,
additional cash may become  available  through the sale of projects (for
additional  information see the discussion of the real estate business
and market on pages 28 and 29). The  ability of the Constellation Companies
to sell or liquidate  assets  described  above  will  depend on market
conditions,  and no assurances can be given that such sales or
liquidations  can be made.  Also, to provide  additional  liquidity to
meet interim  financial  needs,  CHI has a $50 million revolving credit
agreement.

Investment Requirements
The investment  requirements of the Constellation  Companies include its
portion of equity funding to committed projects under development,  as
well as net loans made to project partnerships. Investment requirements
for the years 1996 through 1998 reflect the  Constellation  Companies'
estimate of funding for ongoing and anticipated  projects  and are
subject to  continuous  review and  modification. Actual investment
requirements may vary significantly from the estimates on page 29 because
of 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. The Constellation
Companies have met their  investment  requirements  in the past through
the internal  generation of cash and through borrowings from
institutional lenders.

                                      30

Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

Response to Regulatory Change

Electric utilities  presently face competition in the construction of generating
units to meet  future  load  growth and in the sale of electricity  in the bulk
power markets.  Electric  utilities also face the future prospect of competition
for electric sales to retail customers.  As previously disclosed,  BGE regularly
considered various strategies  designed to enhance its competitive  position and
to increase  its ability to adapt to and  anticipate  regulatory  changes in its
utility  business.  In September  1995,  BGE concluded  that a merger with PEPCO
would enhance two key factors  regarding its competitive  position--maintaining
low-cost  production and increasing in size. The merger is discussed in Note 12.
Although BGE believes the merger will have a positive  effect on its competitive
position in future years,  it is not possible to predict  currently the ultimate
effect  competition  will have on BGE's  earnings in future years,  or after the
merger,  on the  earnings of the new  company.  In  response to the  competitive
forces and regulatory changes, as discussed in Part 1 of BGE's Reports on Form
10-K under the headings Electric Regulatory Matters and Competition and Gas
Regulatory Matters and Competition, BGE (and after the merger the new company)
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, acquisitions  of
related or unrelated businesses,  business combinations,  and additions to or
dispositions of portions of its franchised service  territories. BGE may  from
time  to time be engaged  in  preliminary  discussions,  either internally  or
with third  parties,  regarding  one or more of these  potential strategies. No
assurances can be given as to whether any potential transaction of the type
described  above may actually  occur,  or as to the ultimate effect thereof on
the financial condition or competitive position of BGE.

                                      31

                             Baltimore Gas and Electric Company and Subsidiaries

<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, 1995 and 1994, 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, 1995, 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, 1995 and 1994, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1995 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, 1993, 1992, and 1991, 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, 1992 (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, 1995, 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 19, 1996
                                       32


Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

                        Consolidated Statements of Income
<TABLE>
<CAPTION>

Year Ended December 31,                                                    1995                1994             1993
--------------------------------------------------------------------------------------------------------------------
                                                                        (In thousands, except per share amounts)
<S>                                                                  <C>                 <C>              <C>
Revenues
   Electric                                                          $2,229,774          $2,126,581       $2,112,147
   Gas                                                                  400,504             421,249          433,163
   Diversified businesses                                               304,521             235,155          196,075
--------------------------------------------------------------------------------------------------------------------
   Total revenues                                                     2,934,799           2,782,985        2,741,385

Expenses Other Than Interest and Income Taxes
   Electric fuel and purchased energy                                   578,801             542,314          534,628
   Gas purchased for resale                                             198,069             224,590          242,685
   Operations                                                           550,811             552,817          574,073
   Maintenance                                                          168,269             164,892          181,208
   Diversified businesses - selling, general, and administrative        220,573             167,430          143,654
   Depreciation and amortization                                        317,417             295,950          253,913
   Taxes other than income taxes                                        205,167             199,733          194,832
--------------------------------------------------------------------------------------------------------------------
   Total expenses other than interest and income taxes                2,239,107           2,147,726        2,124,993

Income from Operations                                                  695,692             635,259          616,392
--------------------------------------------------------------------------------------------------------------------

Other Income
   Allowance for equity funds used during construction                   14,162              21,746           14,492
   Equity in earnings of Safe Harbor Water Power Corporation              4,559               4,349            4,243
   Net other income and deductions                                       (9,902)              6,270            1,575
--------------------------------------------------------------------------------------------------------------------
   Total other income                                                     8,819              32,365           20,310

Income Before Interest and Income Taxes                                 704,511             667,624          636,702
--------------------------------------------------------------------------------------------------------------------

Interest Expense
   Interest charges                                                     219,689             214,347          212,971
   Capitalized interest                                                 (15,050)            (12,427)         (16,167)
   Allowance for borrowed funds used during construction                 (7,662)            (11,766)          (8,040)
--------------------------------------------------------------------------------------------------------------------
   Net interest expense                                                 196,977             190,154          188,764

Income Before Income Taxes                                              507,534             477,470          447,938

Income Taxes                                                            169,527             153,853          138,072
--------------------------------------------------------------------------------------------------------------------

Net Income                                                              338,007             323,617          309,866

Preferred and Preference Stock Dividends                                 40,578              39,922           41,839
--------------------------------------------------------------------------------------------------------------------

Earnings Applicable to Common Stock                                  $  297,429          $  283,695       $  268,027
====================================================================================================================

Average Shares of Common Stock Outstanding                              147,527             147,100          145,072

Earnings Per Share of Common Stock                                        $2.02               $1.93            $1.85
====================================================================================================================
</TABLE>

See Notes to Consolidated Financial Statements.

Certain  prior-year  amounts have been  reclassified to conform with the
current year's presentation.

                                      33

                             Baltimore Gas and Electric Company and Subsidiaries


<PAGE>


                           Consolidated Balance Sheets

<TABLE>
<CAPTION>

At December 31,                                                                1995                 1994
--------------------------------------------------------------------------------------------------------
                                                                                    (In thousands)
<S>                                                                      <C>                   <C>
Assets

   Current Assets
      Cash and cash equivalents                                          $   23,443            $  38,590
      Accounts receivable (net of allowance for uncollectibles
         of $16,390 and $14,960, respectively)                              400,005              314,842
      Fuel stocks                                                            59,614               70,627
      Materials and supplies                                                145,900              149,614
      Prepaid taxes other than income taxes                                  60,508               57,740
      Deferred income taxes                                                  36,831               43,358
      Trading securities                                                     47,990               24,337
      Other                                                                  31,487               22,686
--------------------------------------------------------------------------------------------------------
      Total current assets                                                  805,778              721,794

   Investments and Other Assets
      Real estate projects                                                  479,344              471,435
      Power generation systems                                              358,629              311,960
      Financial investments                                                 205,841              224,340
      Nuclear decommissioning trust fund                                     85,811               66,891
      Safe Harbor Water Power Corporation                                    34,327               34,168
      Senior living facilities                                               16,045               11,540
      Net pension asset                                                      60,077                  ---
      Other                                                                  71,894               58,824
--------------------------------------------------------------------------------------------------------
      Total investments and other assets                                  1,311,968            1,179,158

   Utility Plant
      Plant in service
         Electric                                                         6,360,624            5,929,996
         Gas                                                                692,693              616,823
         Common                                                             522,450              511,016
--------------------------------------------------------------------------------------------------------
         Total plant in service                                           7,575,767            7,057,835
      Accumulated depreciation                                           (2,481,801)          (2,305,372)
--------------------------------------------------------------------------------------------------------
      Net plant in service                                                5,093,966            4,752,463
      Construction work in progress                                         247,296              506,030
      Nuclear fuel (net of amortization)                                    130,782              134,012
      Plant held for future use                                              25,552               24,320
--------------------------------------------------------------------------------------------------------
      Net utility plant                                                   5,497,596            5,416,825

   Deferred Charges
      Regulatory assets (net)                                               637,915              623,639
      Other                                                                  63,406               96,086
--------------------------------------------------------------------------------------------------------
      Total deferred charges                                                701,321              719,725

   Total Assets                                                          $8,316,663           $8,037,502
========================================================================================================
</TABLE>

See Notes to Consolidated Financial Statements.

Certain  prior-year  amounts have been  reclassified to conform with the
current year's presentation.
                                      34

Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

                           Consolidated Balance Sheets

<TABLE>
<CAPTION>

At December 31,                                                               1995                 1994
-------------------------------------------------------------------------------------------------------
                                                                                   (In thousands)
<S>                                                                     <C>                   <C>
Liabilities and Capitalization

   Current Liabilities
      Short-term borrowings                                             $  279,305            $  63,700
      Current portions of long-term debt and preference stock              146,969              323,675
      Accounts payable                                                     177,092              181,931
      Customer deposits                                                     26,857               24,891
      Accrued taxes                                                          8,244               19,585
      Accrued interest                                                      56,670               60,348
      Dividends declared                                                    67,198               66,012
      Accrued vacation costs                                                33,403               30,917
      Other                                                                 39,417               30,857
-------------------------------------------------------------------------------------------------------
      Total current liabilities                                            835,155              801,916




   Deferred Credits and Other Liabilities
      Deferred income taxes                                              1,311,530            1,199,787
      Pension and postemployment benefits                                  148,594              138,835
      Decommissioning of federal uranium enrichment facilities              43,695               45,836
      Other                                                                 55,568               59,645
-------------------------------------------------------------------------------------------------------
      Total deferred credits and other liabilities                       1,559,387            1,444,103




   Capitalization
      Long-term debt                                                     2,598,254            2,584,932
      Preferred stock                                                       59,185               59,185
      Redeemable preference stock                                          242,000              279,500
      Preference stock not subject to mandatory redemption                 210,000              150,000
      Common shareholders' equity                                        2,812,682            2,717,866
-------------------------------------------------------------------------------------------------------
      Total capitalization                                               5,922,121            5,791,483


   Commitments, Guarantees, and Contingencies - See Note 12


   Total Liabilities and Capitalization                                 $8,316,663           $8,037,502
=======================================================================================================
</TABLE>

See Notes to Consolidated Financial Statements.

Certain  prior-year  amounts have been  reclassified to conform with the
current year's presentation.
                                      35

                             Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

                      Consolidated Statements of Cash Flows

<TABLE>
<CAPTION>

Year Ended December 31,                                                                 1995            1994           1993
---------------------------------------------------------------------------------------------------------------------------
                                                                                                (In thousands)
<S>                                                                               <C>             <C>            <C>
Cash Flows From Operating Activities
   Net income                                                                     $  338,007      $  323,617     $  309,866
   Adjustments to reconcile to net cash provided by operating activities
      Depreciation and amortization                                                  378,977         351,064        314,027
      Deferred income taxes                                                          103,494          79,278         53,057
      Investment tax credit adjustments                                               (8,088)         (8,192)        (8,444)
      Deferred fuel costs                                                              5,565          11,461         51,445
      Accrued pension and postemployment benefits                                     (7,641)        (41,113)       (25,276)
      Allowance for equity funds used during construction                            (14,162)        (21,746)       (14,492)
      Equity in earnings of affiliates and joint ventures (net)                      (21,259)        (20,225)        (4,655)
      Changes in current assets other than sale of accounts receivable              (107,392)        (10,536)       (37,252)
      Changes in current liabilities, other than short-term borrowings                (7,293)        (24,447)        71,153
      Other                                                                            2,837          13,070         (4,020)
---------------------------------------------------------------------------------------------------------------------------
      Net cash provided by operating activities                                      663,045         652,231        705,409
Cash Flows From Financing Activities
   Proceeds from issuance of
      Short-term borrowings (net)                                                    215,605          63,700        (11,900)
      Long-term debt                                                                 184,422         207,169      1,206,350
      Preference stock                                                                59,329              ---       128,776
      Common stock                                                                       318          33,869         57,379
   Proceeds from sale of receivables                                                   2,000          70,000             ---
   Reacquisition of long-term debt                                                  (315,105)       (240,853)    (1,012,514)
   Redemption of preference stock                                                    (73,000)         (4,406)      (144,310)
   Common stock dividends paid                                                      (227,192)       (220,152)      (211,137)
   Preferred and preference stock dividends paid                                     (40,087)        (39,950)       (42,425)
   Other                                                                                  13            (437)        (7,094)
---------------------------------------------------------------------------------------------------------------------------
   Net cash used in financing activities                                            (193,697)       (131,060)       (36,875)
Cash Flows From Investing Activities
   Utility construction expenditures (including AFC)                                (366,037)       (488,976)      (480,501)
   Allowance for equity funds used during construction                                14,162          21,746         14,492
   Nuclear fuel expenditures                                                         (46,330)        (42,089)       (47,329)
   Deferred nuclear expenditures                                                          ---         (8,393)       (13,791)
   Deferred energy conservation expenditures                                         (45,503)        (40,440)       (32,909)
   Contributions to nuclear decommissioning trust fund                                (9,780)         (9,780)        (9,699)
   Purchases of marketable equity securities                                         (18,447)        (52,099)       (46,820)
   Proceeds from sales of marketable equity securities                                49,788          40,585         33,754
   Other financial investments                                                         9,423           2,469         19,589
   Real estate projects                                                              (15,599)         14,926        (30,330)
   Power generation systems                                                          (37,446)         (1,116)       (26,841)
   Other                                                                             (18,726)         (3,650)         8,965
---------------------------------------------------------------------------------------------------------------------------
   Net cash used in investing activities                                            (484,495)       (566,817)      (611,420)
Net Increase (Decrease) in Cash and Cash Equivalents                                 (15,147)        (45,646)        57,114
Cash and Cash Equivalents at Beginning of Year                                        38,590          84,236         27,122
---------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year                                          $   23,443       $  38,590      $  84,236
===========================================================================================================================

Other Cash Flow Information
   Cash paid during the year for:
      Interest (net of amounts capitalized)                                       $  198,001      $  184,441     $  183,266
      Income taxes                                                                $  132,274      $  112,923     $  126,034
</TABLE>

See Notes to Consolidated Financial Statements.

Certain  prior-year  amounts have been  reclassified to conform with the
current year's presentation.
                                      36

Baltimore Gas and Electric Company and Subsidiaries


<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, 1995, 1994, and 1993      Shares       Amount      Earnings    Securities  Adjustment     Amount
---------------------------------------------------------------------------------------------------------------------------
                                                                                 (In thousands)

<S>                                                <C>       <C>           <C>           <C>          <C>        <C>
Balance at December 31, 1992                       143,784   $1,335,002    $1,199,637    $    ---     $    ---   $2,534,639

Net income                                                                    309,866                               309,866
Dividends declared
  Preferred and preference stock                                              (41,839)                              (41,839)
  Common stock ($1.47 per share)                                             (213,407)                             (213,407)
Common stock issued                                  2,250       57,379                                              57,379
Other                                                              (917)       (3,117)                               (4,034)
Pension liability adjustment                                                                          (33,990)      (33,990)
Deferred taxes on pension liability adjustment                                                         11,897        11,897
---------------------------------------------------------------------------------------------------------------------------
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
===========================================================================================================================
</TABLE>

See Notes to Consolidated Financial Statements.

                                      37

                             Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

                    Consolidated Statements of Capitalization
<TABLE>
<CAPTION>

At December 31,                                                               1995               1994
-----------------------------------------------------------------------------------------------------
                                                                                  (In thousands)
<S>                                                                        <C>             <C>
Long-Term Debt
   First Refunding Mortgage Bonds of BGE
      9-1/8% Series, due October l5, 1995                                 $  ---           $  188,014
      5-1/8% Series, due April 15, 1996                                     26,187             26,454
      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                                    91,200             96,225
      5-1/2% Series, due July 15, 2000                                     125,000            125,000
      8-3/8% Series, due August 15, 2001                                   122,427            122,430
      7-1/8% Series, due January 1, 2002                                    39,698             49,957
      7-1/4% Series, due July 1, 2002                                      124,609            124,850
      5-1/2% Installment Series, due July 15, 2002                          11,045             11,650
      6-1/2% Series, due February 15, 2003                                 124,882            124,947
      6-1/8% Series, due July 1, 2003                                      124,925            124,925
      5-1/2% Series, due April 15, 2004                                    124,995            125,000
      7-1/2% Series, due January 15, 2007                                  123,667            125,000
      6-5/8% Series, due March 15, 2008                                    124,985            125,000
      7-1/2% Series, due March 1, 2023                                     124,973            124,998
      7-1/2% Series, due April 15, 2023                                    100,000            100,000
-----------------------------------------------------------------------------------------------------
      Total First Refunding Mortgage Bonds of BGE                        1,538,528          1,744,385
   Other long-term debt of BGE
      Term bank loan due March 29, 2001                                     50,000                ---
      Medium-term notes, Series A                                           10,500             10,500
      Medium-term notes, Series B                                          100,000            100,000
      Medium-term notes, Series C                                          200,000            173,050
      Medium-term notes, Series D                                           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                                    649,500            544,550
   Long-term debt of Constellation Companies
      Revolving credit agreement
         Variable rates based on LIBOR, due December 9, 1998                 1,000                ---
      Mortgage and construction loans and other collateralized notes
         7.6675%, due October 1, 1995                                          ---             13,000
         7.50%, due October 9, 2005                                          9,989                ---
         Variable rates, due through 2009                                  110,018            116,613
         7.357%, due March 15, 2009                                          5,896              6,152
      Unsecured notes                                                      420,000            440,000
-----------------------------------------------------------------------------------------------------
      Total long-term debt of Constellation Companies                      546,903            575,765
   Unamortized discount and premium                                        (15,708)           (17,593)
   Current portion of long-term debt                                      (120,969)          (262,175)
-----------------------------------------------------------------------------------------------------
   Total long-term debt                                                 $2,598,254         $2,584,932
</TABLE>

   
                                                           continued on page 39
    

See Notes to Consolidated Financial Statements.

                                      38

Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

                    Consolidated Statements of Capitalization
<TABLE>
<CAPTION>

At December 31,                                                                                 1995               1994
-----------------------------------------------------------------------------------------------------------------------
                                                                                                      (In thousands)
<S>                                                                                       <C>                 <C>
Preferred Stock
   Cumulative, $100 par value, 1,000,000 shares authorized
      Series B, 41/2%, 222,921 shares outstanding, callable at $110 per share             $   22,292          $  22,292
      Series C, 4%, 68,928 shares outstanding, callable at $105 per share                      6,893              6,893
      Series D, 5.40%, 300,000 shares outstanding, callable at $101 per share                 30,000             30,000
-----------------------------------------------------------------------------------------------------------------------
   Total preferred stock                                                                      59,185             59,185
Preference Stock
   Cumulative, $100 par value, 6,500,000 shares authorized
      Redeemable preference stock
      7.50%, 1986 Series, 425,000 and 455,000 shares outstanding. Callable
         at $105 per share prior to October 1, 1996 and at lesser amounts thereafter          42,500             45,500
      6.75%, 1987 Series, 455,000 shares outstanding. Callable at
         $104.50 per share prior to April 1, 1997 and at lesser amounts thereafter            45,500             45,500
      6.95%, 1987 Series, 500,000 shares redeemed at par on October 1, 1995                      ---             50,000
      7.80%, 1989 Series, 500,000 shares outstanding                                          50,000             50,000
      8.25%, 1989 Series, 300,000 and 500,000 shares outstanding                              30,000             50,000
      8.625%, 1990 Series, 650,000 shares outstanding                                         65,000             65,000
      7.85%, 1991 Series, 350,000 shares outstanding                                          35,000             35,000
      Current portion of redeemable preference stock                                         (26,000)           (61,500)
-----------------------------------------------------------------------------------------------------------------------
      Total redeemable preference stock                                                      242,000            279,500
   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                ---
-----------------------------------------------------------------------------------------------------------------------
      Total preference stock not subject to mandatory redemption                             210,000            150,000
Common Shareholders' Equity
   Common stock without par value,  175,000,000 shares  authorized;  147,527,114
      shares issued and  outstanding at December 31, 1995 and 1994. (At December
      31, 1995,  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.)                                                                      1,425,805          1,425,378
   Retained earnings                                                                       1,381,417          1,312,655
   Unrealized gain (loss) on available for sale securities                                     5,460             (3,646)
   Pension liability adjustment                                                                  ---            (16,521)
-----------------------------------------------------------------------------------------------------------------------
   Total common shareholders' equity                                                       2,812,682          2,717,866
Total Capitalization                                                                      $5,922,121         $5,791,483
=======================================================================================================================
</TABLE>

See Notes to Consolidated Financial Statements.

                                      39

                             Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

                     Consolidated Statements of Income Taxes
<TABLE>
<CAPTION>

Year Ended December 31,                                                               1995            1994           1993
-------------------------------------------------------------------------------------------------------------------------
                                                                                        (Dollar amounts in thousands)
<S>                                                                               <C>             <C>            <C>
Income Taxes
   Current                                                                        $ 74,121        $ 82,767       $ 93,459
-------------------------------------------------------------------------------------------------------------------------
   Deferred
      Change in tax effect of temporary differences                                118,300          88,896         63,972
      Change in income taxes recoverable through future rates                       (1,006)         (8,580)       (30,086)
      Deferred taxes credited (charged) to shareholders' equity                    (13,800)         (1,038)        11,897
-------------------------------------------------------------------------------------------------------------------------
      Deferred taxes charged to expense                                            103,494          79,278         45,783
   Effect on deferred taxes of enacted change in federal corporate income tax rate
      Increase in deferred tax liability                                               ---             ---         20,105
      Income taxes recoverable through future rates                                    ---             ---        (12,831)
-------------------------------------------------------------------------------------------------------------------------
      Deferred taxes charged to expense                                                ---             ---          7,274
   Investment tax credit adjustments                                                (8,088)         (8,192)        (8,444)
      Income taxes per Consolidated Statements of Income                          $169,527        $153,853       $138,072
=========================================================================================================================
Reconciliation of Income Taxes Computed at Statutory
 Federal Rate to Total Income Taxes
   Income before income taxes                                                     $507,534        $477,470       $447,938
      Statutory federal income tax rate                                                 35%             35%            35%
---------------------------------------------------------------------------------------------------------------------------
      Income taxes computed at statutory federal rate                              177,637         167,115        156,778
      Increases (decreases) in income taxes due to
         Depreciation differences not normalized on regulated activities            10,953           9,791          9,253
         Allowance for equity funds used during construction                        (4,957)         (7,611)        (5,072)
         Amortization of deferred investment tax credits                            (8,088)         (8,164)        (8,444)
         Tax credits flowed through to income                                         (521)         (1,754)        (9,736)
         Change in federal corporate income tax rate charged to expense                ---             ---          7,274
         Amortization of deferred tax rate differential on regulated activities     (2,013)         (1,885)        (5,789)
         Other                                                                      (3,484)         (3,639)        (6,192)
---------------------------------------------------------------------------------------------------------------------------
      Total income taxes                                                          $169,527        $153,853       $138,072
===========================================================================================================================
      Effective federal income tax rate                                               33.4%           32.2%          30.8%
</TABLE>

<TABLE>
<CAPTION>

At December 31,                                                                                 1995                  1994
--------------------------------------------------------------------------------------------------------------------------
Deferred Income Taxes                                                                       (Dollar amounts in thousands)
<S>                                                                                       <C>                   <C>
   Deferred tax liabilities
      Accelerated depreciation                                                            $  878,470            $  840,376
      Allowance for funds used during construction                                           210,928               208,726
      Income taxes recoverable through future rates                                           94,305                93,952
      Deferred termination and postemployment costs                                           49,591                53,749
      Deferred fuel costs                                                                     39,559                41,507
      Leveraged leases                                                                        29,842                31,948
      Percentage repair allowance                                                             38,295                36,630
      Energy conservation expenditures                                                        28,121                   ---
      Other                                                                                  151,231               148,064
--------------------------------------------------------------------------------------------------------------------------
      Total deferred tax liabilities                                                       1,520,342             1,454,952
   Deferred tax assets
      Alternative minimum tax                                                                 32,626                71,074
      Accrued pension and postemployment benefit costs                                        31,707                51,163
      Deferred investment tax credits                                                         49,512                52,288
      Capitalized interest and overhead                                                       39,439                34,071
      Contributions in aid of construction                                                    34,404                32,707
      Nuclear decommissioning liability                                                       16,708                14,870
      Other                                                                                   41,247                42,350
--------------------------------------------------------------------------------------------------------------------------
      Total deferred tax assets                                                              245,643               298,523
   Deferred tax liability, net                                                            $1,274,699            $1,156,429
==========================================================================================================================
</TABLE>

See Notes to Consolidated Financial Statements.

                                      40

Baltimore Gas and Electric Company and Subsidiaries


<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   have  been  eliminated  in consolidation.  Under this
policy, the accounts of Constellation  Holdings, Inc. and its
subsidiaries  (collectively,  the  Constellation  Companies),  BGE Home
Products & Services,  Inc. and Subsidiary (HP&S), BGE Energy Projects &
Services, Inc. (EP&S), and 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 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  Maryland
Public Service  Commission  (PSC).  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
Subject  to the  approval  of the  PSC,  the  cost  of fuel  used in
generating electricity,  net of revenues from  interchange  sales, and
the cost of gas sold may be  recovered  through  zero-based  electric
fuel  rate  (see  Note 12) and purchased gas adjustment  clauses,
respectively.  The difference between actual fuel costs and fuel
revenues is deferred on the balance  sheet 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. The purchased gas adjustment is based on recent annual volumes
of gas and the related current prices charged by BGE's gas suppliers.
Any deferred underrecoveries or  overrecoveries of purchased gas costs
for the twelve months ended November  30 each year are charged or
credited  to customers  over the ensuing calendar year.

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. It has been
recorded as a regulatory asset on the balance sheet. 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 year ended December 31, 1995
reflects utilization of AMT credits of $40 million. Deferred  income
taxes related to the remaining AMT credit  carryforward  of $33 million
have been classified as current assets at December 31, 1995.  Prior-year
amounts have been reclassified to conform with the current year's
presentation.

The  investment  tax  credit  (ITC)  associated  with  BGE's  regulated
utility operations  has been  deferred  (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.

Inventory Valuation
Fuel stocks and materials and supplies are generally stated at average cost.

Real Estate Projects
Real estate  projects  consist of the  Constellation  Companies'
investment  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 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.

                                      41

                             Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

Investments and Other Assets

Investments  in debt  and  equity  securities  subject  to the
requirements  of Statement of Financial  Accounting  Standards  No. 115
(Statement  No. 115) 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 PSC's November  1995 gas rate order,  BGE
revised its gas utility  plant  depreciation rates to reflect the
results of a detailed depreciation study. The new rates are expected to
result 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 PSC'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  (PEPCO),  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 $150  million as of  December  31, 1995.  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 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  PSC  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
$136.7  million  and $109.8  million at  December  31, 1995 and 1994,
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.  The Company plans to
use 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 balance sheet,  crediting the cost as a noncash  item on the income
statement.  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 April 23,  1993,  the Company  accrued AFC at a pre-tax  rate
of 9.94%. Effective  April 24,  1993, a rate order of the PSC reduced
the pre-tax AFC rate to 9.40%.  Effective  November  20,  1995,  a rate
order of the PSC  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.  BGE capitalizes
interest on carrying charges accrued on certain deferred fuel costs as
discussed in Note 5.

                                      42

Baltimore Gas and Electric Company and Subsidiaries


<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.  121,  regarding  accounting  for
asset  impairments, effective January 1, 1996.  Adoption of this
statement is not expected to have a material impact on the Company's
financial statements.

Note 2. Segment Information
<TABLE>
<CAPTION>

                                                                    1995             1994           1993
--------------------------------------------------------------------------------------------------------
                                                                             (In thousands)
<S>                                                           <C>              <C>            <C>
Electric
    Nonaffiliated revenues                                    $2,229,774       $2,126,581     $2,112,147
    Affiliated revenues                                            1,337              840            ---
--------------------------------------------------------------------------------------------------------
    Total revenues                                             2,231,111        2,127,421      2,112,147
    Income from operations                                       574,299          539,739        534,185
    Depreciation and amortization                                276,285          252,273        219,735
    Construction expenditures (including AFC)                    288,509          412,885        421,923
    Identifiable assets at December 31                         6,195,722        5,981,634      5,867,725

Gas
    Total revenues (nonaffiliated)                            $  400,504       $  421,249     $  433,163
    Income from operations                                        48,104           27,801         34,738
    Depreciation and amortization                                 29,637           32,478         23,875
    Construction expenditures (including AFC)                     77,528           76,091         58,578
    Identifiable assets at December 31                           748,462          726,759        677,857

Diversified Businesses
    Nonaffiliated revenues                                    $  304,521       $  235,155     $  196,075
    Affiliated revenues                                            6,609            8,245          6,825
--------------------------------------------------------------------------------------------------------
    Total revenues                                               311,130          243,400        202,900
    Income from operations                                        73,289           67,719         47,469
    Depreciation and amortization                                 11,495           11,199         10,303
    Identifiable assets at December 31                         1,266,049        1,200,551      1,166,997

Total
    Nonaffiliated revenues                                    $2,934,799       $2,782,985     $2,741,385
    Affiliated revenues                                            7,946            9,085          6,825
    Intercompany eliminations                                     (7,946)          (9,085)        (6,825)
--------------------------------------------------------------------------------------------------------
    Total revenues                                             2,934,799        2,782,985      2,741,385
    Income from operations                                       695,692          635,259        616,392
    Depreciation and amortization                                317,417          295,950        253,913
    Construction expenditures (including AFC)                    366,037          488,976        480,501
    Identifiable assets at December 31                         8,210,233        7,908,944      7,712,579
    Other assets at December 31                                  106,430          128,558        117,034
--------------------------------------------------------------------------------------------------------
    Total assets at December 31                                8,316,663        8,037,502      7,829,613
</TABLE>

Certain  prior-year  amounts have been  reclassified to conform with the
current year's presentation.

                                      43

                             Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

   
Note 3. Subsidiary Information
Diversified businesses consist of the operations of the Constellation
Companies, HP&S, EP&S, and BNG, Inc.
    

The Constellation Companies include Constellation Holdings, Inc., a
wholly owned subsidiary   which  holds  all  of  the  stock  of  three
other   subsidiaries, Constellation  Real Estate Group,  Inc.,
Constellation  Power,  Inc.  (formerly "Constellation  Energy,  Inc."),
and  Constellation  Investments,   Inc.  These companies are engaged in
real estate  development and ownership of senior living facilities;
development,  ownership, and operation of power generation systems; and
financial investments, respectively.

   
HP&S is a wholly owned subsidiary  which engages  predominantly in the
businesses of appliance and consumer electronics sales and service;
heating,  ventilation, and air conditioning  system sales,  installation
and service;  as well as, home improvements and services, primarily in
Central Maryland.

Effective  November 1, 1995,  BGE formed a wholly owned  subsidiary,
EP&S, which provides  a broad  range of  customized  energy  services  to
major  customers, including industrial, institutional, and   government
customers  in  commercial   office   buildings, warehouses, educational,
healthcare,  and retail facilities.  These energy services include
customer  electrical system  improvements, lighting and mechanical
engineering services, campus and multi-building systems,  brokering and
associated financial contracts, and district chilled water systems.
    

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  Constellation
Holdings, Inc. and its subsidiaries.  The condensed financial
information does not reflect the elimination of intercompany balances or
transactions which are eliminated in the Company's consolidated
financial statements.

<TABLE>
<CAPTION>

                                                                      1995             1994             1993

                                                                    (In thousands, except per share amounts)
<S>                                                             <C>              <C>              <C>
Income Statements
        Revenues
            Real estate projects                                $  108,414       $  106,915       $   77,598
            Power generation systems                                57,734           41,301           24,971
            Financial investments                                   25,201           12,126           21,195
------------------------------------------------------------------------------------------------------------
            Total revenues                                         191,349          160,342          123,764
        Expenses other than interest and income taxes              114,479          107,267           80,427
------------------------------------------------------------------------------------------------------------
        Income from operations                                      76,870           53,075           43,337
        Minority interest                                           (2,348)             ---             (280)
        Interest expense                                           (46,673)         (45,782)         (47,845)
        Capitalized interest                                        13,582           10,776           14,702
        Income tax benefit (expense)                               (14,355)          (4,305)           1,984
------------------------------------------------------------------------------------------------------------
        Net income                                              $   27,076       $   13,764       $   11,898
============================================================================================================
Contribution to the Company's earnings per share of common stock    $  .18           $  .09           $  .08
============================================================================================================
Balance Sheets
        Current assets                                          $   98,526       $   92,814       $   54,039
        Noncurrent assets                                        1,102,528        1,055,056        1,036,507
------------------------------------------------------------------------------------------------------------
        Total assets                                            $1,201,054       $1,147,870       $1,090,546
        Current liabilities                                     $   70,393        $  70,670       $   24,201
        Noncurrent liabilities                                     778,505          758,626          759,048
        Shareholder's equity                                       352,156          318,574          307,297
------------------------------------------------------------------------------------------------------------
        Total liabilities and shareholder's equity              $1,201,054       $1,147,870       $1,090,546
============================================================================================================
</TABLE>

                                      44

Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

Note 4. Real Estate Projects and Financial Investments

Real estate projects consist of the following investments held by the
Constellation Companies:

<TABLE>
<CAPTION>

At December 31,                            1995          1994
--------------------------------------------------------------------
                                             (In thousands)
<S>                                    <C>           <C>
Properties under development           $270,678      $267,483
Rental and operating properties
    (net of accumulated
    depreciation)                       207,666       203,000
Other real estate ventures                1,000           952
--------------------------------------------------------------------
Total                                  $479,344      $471,435
====================================================================
</TABLE>

Financial   investments  consist  of  the  following  investments  held
by  the Constellation Companies:

<TABLE>
<CAPTION>

At December 31,                            1995          1994
--------------------------------------------------------------------
                                            (In thousands)
<S>                                    <C>           <C>
Insurance companies                    $ 77,792      $ 87,700
Marketable equity securities             41,475        51,175
Financial limited partnerships           51,023        48,014
Leveraged leases                         35,551        37,451
--------------------------------------------------------------------
Total                                  $205,841      $224,340
====================================================================
</TABLE>

The Constellation  Companies' marketable equity securities 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 $3.2 million of unrealized net gains on
securities of equity-method investees, are as follows:

<TABLE>
<CAPTION>

                           Amortized   Unrealized   Unrealized      Fair
At December 31, 1995       Cost Basis    Gains        Losses       Value
---------------------------------------------------------------------------
                                          (In thousands)
<S>                         <C>          <C>         <C>         <C>
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
===========================================================================
</TABLE>

<TABLE>
<CAPTION>

                           Amortized   Unrealized   Unrealized      Fair
At December 31, 1994       Cost Basis    Gains        Losses       Value
---------------------------------------------------------------------------
                                          (In thousands)
<S>                         <C>          <C>        <C>           <C>
Marketable equity
  securities                $ 51,758     $1,276     $(1,859)      $ 51,175
U.S. government
  agency                       5,215        ---        (113)         5,102
State municipal
  bonds                       59,704        929      (2,599)        58,034
---------------------------------------------------------------------------
Total                       $116,677     $2,205     $(4,571)      $114,311
===========================================================================
</TABLE>

Gross and net realized gains and losses on available for sale securities
were as follows:

<TABLE>
<CAPTION>

                              1995         1994         1993
---------------------------------------------------------------------------
                                     (In thousands)
<S>                         <C>         <C>           <C>
Gross realized gains        $5,470      $ 1,108       $2,437
Gross realized losses       (2,446)      (3,150)      (1,389)
---------------------------------------------------------------------------
Net realized gains (losses) $3,024      $(2,042)      $1,048
===========================================================================
</TABLE>

Contractual maturities of debt securities:

<TABLE>
<CAPTION>

                                                       Amount
---------------------------------------------------------------------------
                                                  (In thousands)
<S>                                                   <C>
Less than 1 year                                      $  ---
1-5 years                                              10,975
5-10 years                                             52,920
More than 10 years                                      4,850
---------------------------------------------------------------------------
Total                                                 $68,745
===========================================================================
</TABLE>

Note 5. Regulatory Assets (net)
As discussed in Note 1, BGE's  utility  operations  are subject to
regulation by the PSC.  Except for  differences  in the timing of the
recognition  of certain utility  expenses  and  credits,  the
ratemaking  process  utilized  by the PSC generally is based upon the
same accounting  principles  applied by nonregulated entities. Under the
PSC's ratemaking process, these utility expenses and credits are
deferred on the balance sheet 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:

<TABLE>
<CAPTION>

At December 31,                            1995          1994
--------------------------------------------------------------------
                                             (In thousands)
<S>                                    <C>          <C>
Income taxes recoverable
    through future rates               $269,442     $268,436
Deferred fuel costs                     113,026      118,591
Deferred nuclear expenditures            86,519       90,937
Deferred postemployment benefit costs    81,616       73,591
Deferred energy conservation
    expenditures                         73,297       45,534
Deferred termination benefit costs       60,073       79,979
Deferred cost of
    decommissioning federal
    uranium enrichment facilities        51,104       52,748
Deferred environmental costs             38,371       35,015
Deferred investment tax credits        (141,463)    (149,394)
Other                                     5,930        8,202
--------------------------------------------------------------------
Total                                  $637,915     $623,639
====================================================================
</TABLE>

                                      45

                             Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

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 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:

<TABLE>
<CAPTION>

At December 31,                            1995         1994
--------------------------------------------------------------------
                                              (In thousands)
<S>                                    <C>          <C>
Electric
  Costs deferred                       $130,399     $152,815
  Reserve for possible
    disallowance of replacement
    energy costs (see Note 12)          (35,000)     (35,000)
--------------------------------------------------------------------
  Net electric                           95,399      117,815
Gas                                      17,627          776
--------------------------------------------------------------------
Total                                  $113,026     $118,591
====================================================================
</TABLE>

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 PSC.  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  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 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  PSC.  These
expenditures  consist  of  labor, materials, and indirect costs
associated with the conservation programs approved by the PSC.

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 PSC.

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  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 PSC 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  investment tax credits  represents  investment tax credits
associated with BGE's regulated utility operations as discussed in Note
1. Previously,  the Company reported  deferred  investment tax credits
on the  Consolidated  Balance Sheets  as  Deferred  Credits  and  Other
Liabilities.  In  1995,  the  Company reclassified  those credits as a
reduction of Regulatory Assets because they are deferred  solely
because of the regulatory  treatment.  Prior year amounts have been
reclassified to conform with the current year's presentation.

Electric  deferred  fuel costs in excess of $72.8 million are excluded
from rate base by the PSC for ratemaking purposes.  Effective April 24,
1993, BGE has been authorized  by the PSC to accrue  carrying  charges
on  deferred  fuel costs in excess of $72.8 million,  net of related
deferred income taxes.  These carrying charges are accrued
prospectively at the 9.40%  authorized rate of return.  The income
effect of the  equity  funds  portion of the  carrying  charges is being
deferred until such amounts are recovered in utility service rates
subsequent to the completion of the fuel rate  proceeding  examining the
1989-1991  outages at Calvert Cliffs Nuclear Power Plant as discussed in
Note 12. Deferred  investment tax credits 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
income  statement  at that  time,  resulting  in a charge to earnings,
net of applicable income taxes.

                                      46

Baltimore Gas and Electric Company and Subsidiaries


<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 its 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, 1995
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. At December 31, 1994,
the  accumulated  benefit  obligation  was  greater  than the fair
value of the Pension Plan's assets. As a result,  the Company recorded
an additional  pension liability, a portion of which was charged to
shareholders' equity.

Net pension cost shown below does not include the cost of  termination
benefits described in Note 7.

<TABLE>
<CAPTION>

At December 31,                                                              1995               1994
                                                                               (In thousands)
<S>                                                                      <C>                <C>
Vested benefit obligation                                                $688,084           $622,445
Nonvested benefit obligation                                               15,668              8,838
----------------------------------------------------------------------------------------------------
Accumulated benefit obligation                                            703,752            631,283
Projected benefits related to increase in future compensation levels      122,539             82,815
----------------------------------------------------------------------------------------------------
Projected benefit obligation                                              826,291            714,098
Plan assets at fair value                                                (744,645)          (614,284)
----------------------------------------------------------------------------------------------------
Projected benefit obligation less plan assets                              81,646             99,814
Unrecognized prior service cost                                           (24,357)           (23,863)
Unrecognized net loss                                                    (118,361)          (112,546)
Pension liability adjustment                                                  ---             52,177
Unamortized net asset from adoption of FASB Statement No. 87                  995              1,586
----------------------------------------------------------------------------------------------------
Accrued pension (asset) liability                                       $ (60,077)          $ 17,168
====================================================================================================
</TABLE>

<TABLE>
<CAPTION>

Year Ended December 31,                                                    1995               1994             1993
-------------------------------------------------------------------------------------------------------------------
                                                                               (In thousands)
<S>                                                                    <C>                 <C>               <C>
Components of net pension cost
    Service cost-benefits earned during the period                      $11,407            $15,015          $11,645
    Interest cost on projected benefit obligation                        58,433             58,723           51,183
    Actual return on plan assets                                       (150,510)             7,932          (56,225)
    Net amortization and deferral                                        94,674            (60,071)           6,591
-------------------------------------------------------------------------------------------------------------------
    Total net pension cost                                               14,004             21,599           13,194
    Amount capitalized as construction cost                              (1,422)            (2,578)          (1,800)
-------------------------------------------------------------------------------------------------------------------
    Amount charged to expense                                           $12,582            $19,021          $11,394
===================================================================================================================
</TABLE>


The Company  also  sponsors a defined  contribution  savings  plan
covering all eligible BGE employees  and certain  employees of its
subsidiaries.  Under this plan,  the  Company  makes  contributions  on
behalf of  participants.  Company contributions to this plan totaled
$8.5 million,  $8.7 million, and $9.0 million in 1995, 1994, and 1993,
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.

Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards  No.  106,  which  requires a change in the method
of  accounting  for postretirement  benefits other than pensions from
the pay-as-you-go  method used prior to 1993 to the accrual method. The
transition  obligation  existing at the beginning of 1993 is being
amortized over a 20-year period.

                                      47

                             Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

In April  1993,  the PSC 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, the increase in
annual PRB costs  applicable to regulated  operations  for the period
January through April 1993, net of amounts  capitalized as  construction
cost, has been deferred.  This amount, which totaled $5.7 million, as
well as 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 accordance  with the PSC's Order. In November 1995,
the PSC 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.

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,                                                         1995                                 1994

                                                                                 Life                                 Life
                                                               Health Care     Insurance           Health Care      Insurance
                                                                                       (In thousands)
<S>                                                              <C>            <C>                  <C>            <C>
Accumulated postretirement benefit obligation:
    Retirees                                                     $157,804       $44,769              $161,134       $45,146
    Fully eligible active employees                                20,942            84                15,777           101
    Other active employees                                         63,782        18,515                44,371        12,597
---------------------------------------------------------------------------------------------------------------------------
Total accumulated postretirement benefit obligation               242,528        63,368               221,282        57,844
Unrecognized transition obligation                               (149,907)      (43,521)             (158,725)      (46,081)
Unrecognized net gain (loss)                                      (12,767)       (5,764)                1,238        (2,141)
---------------------------------------------------------------------------------------------------------------------------
Accrued postretirement benefit liability                         $ 79,854      $ 14,083              $ 63,795       $ 9,622
===========================================================================================================================
</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.

<TABLE>
<CAPTION>

Year ended December 31,                                  1995      1994
------------------------------------------------------------------------
                                                         (In thousands)
<S>                                                   <C>       <C>
Net postretirement benefit cost:
    Service cost--benefits earned during
        the period                                    $ 3,918   $ 5,035
    Interest cost on accumulated post-
        retirement benefit obligation                  21,203    23,037
    Amortization of transition obligation              11,378    11,700
    Net amortization and deferral                         (86)      646
------------------------------------------------------------------------
    Total net postretirement benefit cost              36,413    40,418
    Amount capitalized as construction cost            (5,299)   (5,773)
    Amount deferred                                    (8,025)  (10,213)
------------------------------------------------------------------------
    Amount charged to expense                         $23,089   $24,432
========================================================================
</TABLE>

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
Company  adopted  Statement of Financial  Accounting  Standards  No.
112,  which requires  a change in the  method of  accounting  for  these
benefits  from the pay-as-you-go  method  to an  accrual  method,  as of
December  31,  1993.  The liability for these benefits  totaled $52
million and $48 million as of December 31, 1995 and 1994, respectively.
The portion of the December 31, 1993 liability attributable  to
regulated  activities was deferred.  Consistent  with the PSC's November
1995 order,  the amounts  deferred  will be  amortized  over a 15-year
period  beginning  in 1998.  The  adoption of  Statement  No. 112 did
not have a material impact on net income.

Assumptions

The pension, postretirement, and other postemployment benefit
liabilities were determined using the following assumptions.

<TABLE>
<CAPTION>

At December 31,                             1995       1994
--------------------------------------------------------------
<S>                                         <C>        <C>
Assumptions:
    Discount rate
      Pension and postretirement benefits   7.5%       8.5%
      Other postemployment benefits         6.0%       8.5%
    Average increase in
      future compensation levels            4.0%       4.0%
    Expected long-term rate of
      return on assets                      9.0%       9.0%
</TABLE>

The  health  care  inflation   rates  for  1995  are  assumed  to  be
8.7%  for Medicare-eligible  retirees and 11.8% for retirees not covered
by Medicare.  The health   care   inflation   rates   for  1996  are
assumed   to  be  8.0%  for Medicare-eligible retirees and 10.5% for
retirees not covered by Medicare. After 1996, 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 $40
million as of December  31, 1995 and would  increase  the  aggregate  of
the service  cost and interest cost  components of  postretirement
benefit cost by  approximately  $4 million annually.

                                      48

Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

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 accordance with Statement of Financial
Accounting Standards No. 88, "Employers'  Accounting for  Settlements
and  Curtailments  of Defined  Benefit Pension Plans and for
Termination  Benefits,"  the one-time cost of termination benefits
associated  with the 1992 VSERP,  which  consisted  principally  of an
enhanced pension benefit,  was recognized in 1992 and reduced net income
by $6.6 million,  or 5 cents per common share.  In April 1993, the PSC
authorized BGE to amortize  this  charge  over  a  five-year   period
for  ratemaking   purposes. Accordingly,  BGE  established a regulatory
asset and recorded a  corresponding credit to operating  expense for
this amount.  The reversal of the 1992 VSERP in April 1993 increased net
income by $6.6 million, or 5 cents per common share.

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.  In accordance with Statement
No. 88, the one-time cost of termination benefits associated with the
1993 VSERP and various programs,  which totaled $105.5 million, was
recognized in 1993. 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 PSC. The
$17.2 million remaining cost of termination  benefits was charged to
expense in 1993.

Note 8. Short-Term Borrowings

Information  concerning  short-term  borrowings  is set forth below.
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.

<TABLE>
<CAPTION>

                                                                                    1995            1994               1993
                                                                                       (Dollar amounts in thousands)
<S>                                                                             <C>              <C>               <C>
BGE's Bank Loans
    Borrowings outstanding at December 31                                       $  3,845         $     -           $      -
    Weighted average interest rate of borrowings outstanding at December 31         4.74%              - %                - %
    Maximum borrowings during the year                                          $  3,845         $     -           $      -

BGE's Commercial Paper Notes
    Borrowings outstanding at December 31                                       $275,300         $ 63,700          $      -
    Weighted average interest rate of notes outstanding at December 31              5.92%            6.10%                - %
    Unused lines of credit supporting commercial paper notes at December 31*    $238,000         $148,000          $ 208,000
    Maximum borrowings during the year                                          $339,100         $187,500          $  96,900

Constellation Companies' Lines of Credit
    Borrowings outstanding at December 31                                       $    160         $      -          $       -
    Weighted average interest rate of borrowings outstanding at December 31            -%               - %                - %
    Unused lines of credit at December 31                                       $    ---         $      -          $  20,000
    Maximum borrowings during the year                                          $    160         $      -          $       -
</TABLE>

*Exclusive of $150 million of revolving  credit  agreements  undrawn at
year-end (see Note 9).

                                      49

                             Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

   
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 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.

Other Long-Term Debt of BGE
BGE maintains  revolving  credit  agreements that expire at various
times during 1998. 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,  1995,  BGE  had no borrowings  under
these  revolving  credit  agreements  and had  available  $150 million
of unused capacity under these agreements.

On December 29, 1995 BGE entered into a $50 million term bank loan which
matures on March 29, 2001.  Under the terms of the loan, 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, 1995:

<TABLE>
<CAPTION>
                         Weighted-Average
Series                     Interest Rate       Maturity Dates
--------------------------------------------------------------------
<S>                            <C>                <C>
A                              8.22%              1996
B                              8.43%              1998-2006
C                              7.04%              1996-2003
D                              6.12%              1998-2005
</TABLE>

The principal  amounts of the 5-1/2%  Installment  Series  Mortgage Bonds
payable each year are as follows:

<TABLE>
<CAPTION>

Year
--------------------------------------------------------------------
                                                      (In thousands)
<C>                                                            <C>
1996 through 1997                                              $ 605
1998 and 1999                                                    690
2000 and 2001                                                    865
2002                                                           6,725
</TABLE>

Long-Term Debt of Constellation Companies
The Constellation Companies entered into an unsecured revolving credit
agreement on December 9, 1994 in the amount of $50  million.  This
agreement  matures  December 9, 1998 and will be used to provide
liquidity for general corporate  purposes.  As of December 31, 1995, the
Constellation Companies had $1 million outstanding under this agreement.

The mortgage and construction loans and other  collateralized notes have
varying terms.  The $9.9 million,  7.50%  mortgage note requires
monthly  principal and interest  payments  through  October 9, 2005.
The $110 million of variable rate mortgage notes require  periodic
payment of principal and interest with various maturities  from  January
1996  through  July 2009.  The $5.9  million,  7.357% mortgage note
requires  quarterly  principal and interest payments through March 15,
2009.

The  unsecured  notes  outstanding  as of December 31, 1995 mature in
accordance with the following schedule:

<TABLE>
<CAPTION>
                                                       Amount
--------------------------------------------------------------------
                                               (In thousands)
<S>                                                  <C>
8.71%, due August 28, 1996                           $ 23,000
6.19%, due September 9, 1996                           10,000
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
--------------------------------------------------------------------
Total                                                $420,000
====================================================================
</TABLE>

Weighted Average Interest Rates for Variable Rate Debt
The weighted average interest rates for variable rate debt during 1995
and 1994 were as follows:

<TABLE>
<CAPTION>
                                            1995        1994
--------------------------------------------------------------------
<S>                                         <C>        <C>
BGE
   Floating rate series mortgage bonds      6.30%      4.91%
   Pollution control loan                   3.79       2.80
   Port facilities loan                     4.06       3.02
   Adjustable rate pollution control loan   3.75       3.13
   Economic development loan                4.01       3.00
Constellation Companies
   Mortgage and construction loans
      and other collateralized notes        8.99       7.27
   Loans under credit agreements            6.74        -
</TABLE>

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:

<TABLE>
<CAPTION>
                                                 Constellation
Year                                     BGE       Companies
--------------------------------------------------------------------
                                        (In thousands)
<S>                                 <C>             <C>
1996                                $ 71,659        $ 49,310
1997                                  80,657         134,970
1998                                  92,328         138,351
1999                                 246,420         118,175
2000                                 251,441          85,521
</TABLE>

                                      50

Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

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.

<TABLE>
<CAPTION>
                                                    Beginning
Series                                  Shares        Year
--------------------------------------------------------------------
<S>                                    <C>             <C>
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
</TABLE>


The combined  aggregate  redemption  requirements  for all series of
redeemable preference stock for each of the next five years are as
follows:

<TABLE>
<CAPTION>

Year
--------------------------------------------------------------------
                                               (In thousands)
<C>                                                   <C>
1996                                                  $26,000
1997                                                   83,000
1998                                                   33,000
1999                                                   23,000
2000                                                   23,000
</TABLE>


With  regard  to  payment  of  dividends  or  assets  available  in the
event of liquidation,  preferred  stock ranks prior to preference  and
common stock;  all issues of preference stock, whether subject to
mandatory redemption or not, rank equally; and all preference stock
ranks prior to common stock.


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  $12.2
million,  $12.7  million,  and $13.8 million for the years ended 1995,
1994, and 1993, respectively.

The  future   minimum  lease   payments  at  December  31,  1995  for
long-term noncancelable operating leases are as follows:


<TABLE>
<CAPTION>

Year
--------------------------------------------------------------------
                                               (In thousands)
<S>                                                   <C>
1996                                                  $ 4,485
1997                                                    4,398
1998                                                    3,681
1999                                                    1,712
2000                                                    1,537
Thereafter                                              4,214
--------------------------------------------------------------------
Total minimum lease payments                          $20,027
====================================================================
</TABLE>


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 21 years,  with options to renew. The
net book value of property under operating  leases was $147  million at
December  31,  1995.  The future  minimum rentals to be received under
operating leases in effect at December 31, 1995 are as follows:


<TABLE>
<CAPTION>

Year
--------------------------------------------------------------------
                                               (In thousands)
<S>                                                  <C>
1996                                                 $ 14,412
1997                                                   12,134
1998                                                   10,883
1999                                                   10,130
2000                                                    9,459
Thereafter                                             66,660
--------------------------------------------------------------------
Total minimum rentals                                $123,678
====================================================================
</TABLE>

                                      51


                             Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

Note 12. Commitments, Guarantees, and Contingencies

Commitments

BGE has made substantial commitments in connection with its construction
program for 1995 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 $68.4, $69.4, and $68.7
million during 1995, 1994, and 1993,  respectively. At December 31,
1995, the estimated future payments for capacity and energy that BGE is
obligated to buy under these contracts are as follows:

<TABLE>
<CAPTION>

Year
--------------------------------------------------------------------
                                               (In thousands)
<S>                                                <C>
1996                                               $   62,989
1997                                                   60,355
1998                                                   78,950
1999                                                   90,224
2000                                                   91,365
Thereafter                                            902,432
--------------------------------------------------------------------
Total payments                                     $1,286,315
====================================================================
</TABLE>


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, 1995, the total amount of investment requirements committed
to by the Constellation Companies is $44 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, 1995,  BGE and HP&S had sold $30 million and $42 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 $45 million, of which $30 million represents
BGE's share of the guarantee. As of December  31,  1995,  outstanding
indebtedness  of Safe  Harbor  Water Power Corporation was $33 million,
of which $22 million is guaranteed by BGE. BGE has also agreed to
guarantee up to $20 million of obligations  and  indebtedness  of BNG,
Inc. As of December 31, 1995, 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, 1995,  the total  outstanding  loans and letters of
credit of certain  power   generation   and  real  estate   projects
guaranteed  by  the Constellation Companies were $35 million. Also, the
Constellation Companies have agreed to guarantee  cer-tain 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,  a District  of Columbia  and
Virginia corporation  (PEPCO) and Constellation  Energy  Corporation
(formerly named "RH Acquisition  Corp."), a Maryland  corporation which
will also be incorporated in Virginia (CEC),  have entered into an
Agreement and Plan of Merger,  dated as of September 22, 1995. CEC was
formed to accomplish the merger and its  outstanding capital  stock is
owned 50% by BGE and 50% by PEPCO.  The  Agreement and Plan of Merger
provides for a strategic  business  combination that will be
accomplished by merging both BGE and PEPCO into CEC (the Transaction).
The Transaction, which was  unanimously  approved  by the  Boards of
Directors  of BGE and  PEPCO,  is expected to close  during 1997 after
shareholder  approval is obtained  and all other  conditions to the
consummation of the  Transaction,  including  obtaining applicable
regulatory  approvals,  are met or waived.  In  connection  with the
Transaction,  BGE common shareholders will receive one share of CEC
common stock for each BGE share and PEPCO common shareholders will
receive 0.997 share of CEC common stock for each PEPCO share. Further
details about the proposed merger are provided in the report on Form 8-K
dated September 22, 1995 and 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.

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

                                      52

Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

environmentally  contaminated  sites  owned and  operated by third
parties.  In addition,  a  subsidiary  of  Constellation  Holdings,
Inc. has been named as a defendant in a case  concerning  an alleged
environmentally  contaminated  site owned and  operated by a third
party.  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.  However,  no  formal  legal  proceedings
have  been  instituted.  BGE has recognized  estimated  environmental
costs at these sites totaling $38.6 million as of December 31, 1995.
These costs, net of accumulated amortization, have been deferred as a
regulatory asset (see Note 5). The technology for cleaning up such sites
is still developing,  and potential remedies for these sites have not
been identified.  Cleanup costs in excess of the amounts  recognized,
which could be significant in total, cannot presently be estimated.

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 $6.08 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 short-fall of funds at the industry mutuals,  BGE and all
policyholders could be assessed, with BGE's share being up to $44.1
million.

Recoverability of Electric Fuel Costs
By statute,  actual electric fuel costs are recoverable so long as the
PSC finds that BGE demonstrates that, among other things, it has
maintained the productive capacity of its generating  plants at a
reasonable level. The PSC 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  PSC  authorized  the
establishment  of  the 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
future 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 PSC.

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 the GUPP program.  The
resultant  case before the PSC 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 Maryland
People's Counsel alleging that seven outages

                                      53

                             Baltimore Gas and Electric Company and Subsidiaries


<PAGE>


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 PSC. 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. 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
PSC by both BGE and  People's  Counsel.  If the PSC upholds the Hearing
Examiner,  the Company's earnings would be impacted by approximately
$4.5 million.

In May 1989,  BGE filed its fuel rate case in which 1988  performance
was to be examined. BGE met the system-wide and nuclear plant
performance targets in 1988. People's Counsel alleges 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 PSC 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 on 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, is  estimated  to be $458 million.

In a December  1990 Order issued by the PSC in a BGE base rate
proceeding,  the PSC found that certain  operations and maintenance
expenses incurred at Calvert Cliffs  during the test year should not be
recovered  from  ratepayers.  The PSC 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  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  power costs associated
with the outages at Calvert Cliffs.  The PSC 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 PSC's  statement  regarding no binding
effect,  BGE recognizes  that the views expressed by the PSC make 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. BGE cannot determine  whether  replacement energy costs
may be disallowed in the present fuel rate proceedings in excess of the
provision, but such amounts could be material.

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,                                                              1995                                 1994
                                                                  Carrying          Fair                Carrying        Fair
                                                                   Amount           Value                Amount         Value
                                                                                        (In thousands)
<S>                                                             <C>            <C>                   <C>           <C>
Cash and cash equivalents                                       $   23,443     $   23,443            $    38,590   $    38,590
Net accounts receivable                                            400,005        400,005                314,842       314,842
Other current assets                                                54,070         54,070                 29,344        29,344
Investments and other assets for which it is:
  Practicable to estimate fair value                               149,645        150,170                138,978       137,782
  Not practicable to estimate fair value                            73,042            ---                 69,514           ---
Short-term borrowings                                              279,305        279,305                 64,205        64,205
Current portions of long-term debt and preference stock            146,969        146,969                323,675       323,675
Accounts payable                                                   177,092        177,092                181,931       181,931
Other current liabilities                                          193,992        193,992                191,121       191,121
Long-term debt                                                   2,598,254      2,694,858              2,584,932     2,417,625
Redeemable preference stock                                        242,000        254,809                279,500       281,478
</TABLE>

                                      54

Baltimore Gas and Electric Company and Subsidiaries


<PAGE>

   
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 23 financial  partnerships  which invest in nonpublic
debt and equity securities or investments in four partnerships
which own solar powered energy  production  facilities 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 $50 million and $47 million at
December 31, 1995 and 1994, respectively, representing ownership
interests up to 10%. The aggregate assets of these partnerships totaled
$6.3 billion at December 31,  1994.  The  investments  in  solar
powered  energy   production   facility partnerships  totaled $23
million at  December  31, 1995 and 1994,  representing ownership
interests  up to 12%.  The  aggregate  assets  of these  partnerships
totaled $83 million at December 31, 1994.

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 $22 million and $35 million,
respectively, at December 31, 1995 and $23.3 million and $17.0 million,
respectively, at December 31, 1994 for which it is not practicable to
determine fair value. It is not anticipated  that these loan guarantees
will need to be funded.

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>             <C>             <C>            <C>            <C>
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
==============================================================================================================================

1994
Revenues                                              $767,686        $651,152        $753,878       $610,269       $2,782,985
Income from operations                                 162,559         136,778         232,472        103,450          635,259
Net income                                              82,145          66,708         126,616         48,148          323,617
Earnings applicable to common stock                     72,114          56,687         116,714         38,180          283,695
Earnings per share of common stock                        0.49            0.39            0.79           0.26             1.93
==============================================================================================================================
</TABLE>

Results for the first  quarter of 1994 reflect a $10.0  million
one-time  bonus paid to employees in lieu of a general increase.

Results for the third quarters of 1995 and 1994 reflect the $9.7 and
$11.0 million write-offs, respectively, of certain Perryman costs (see
Note 1).

Certain prior-quarter amounts have been reclassified to conform
with the current presentation.

                                      55


                             Baltimore Gas and Electric Company and Subsidiaries



<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
     The information required by this item with respect to directors is set
forth on pages 2 through 4 under "Item 1. Election of 14 Directors" in the Proxy
Statement and is incorporated herein by reference.
     The information required by this item with respect to executive officers
is, pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K,
set forth in Item 10 of Part I of this Form 10-K under "Executive Officers of
the Registrant."
ITEM 11. EXECUTIVE COMPENSATION
     The information required by this item is set forth on pages 7 through 14
under "Item 1. Election of 14 Directors -- Compensation of Executive Officers by
the Company" in the Proxy Statement and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
     The information required by this item is set forth on page 6 under "Item 1.
Election of 14 Directors -- Security Ownership of Directors and Executive
Officers" in the Proxy Statement and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
     The information required by this item is set forth on page 5 under "Item 1.
Election of 14 Directors -- Certain Relationships and Transactions" in the Proxy
Statement and is incorporated herein by reference.
                                    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:
           Auditors' Report dated January 19, 1996 of Coopers & Lybrand L.L.P.,
           Independent Accountants
           Consolidated Statements of Income for three years ended December 31,
           1995
           Consolidated Balance Sheets at December 31, 1995 and December 31,
           1994
           Consolidated Statements of Cash Flows for three years ended December
           31, 1995
           Consolidated Statements of Common Shareholders' Equity for three
           years ended
            December 31, 1995
           Consolidated Statements of Capitalization at December 31, 1995 and
           December 31, 1994
           Consolidated Statements of Income Taxes for three years ended
           December 31, 1995
           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.
                                       56

<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 April 25, 1995. (Designated as Exhibit No. 3(a) in Form 10-Q dated May
            11, 1995, File No. 1-1910.)
  *3(b)  -- Articles Supplementary, dated as of September 5, 1995, to the Charter of BGE. (Designated as Exhibit
            No. 3 in Form 10-Q dated November 13, 1995, File No. 1-1910.)
  *3(c)  -- 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>        <C>                                                  <C>
          *April 15, 1966        2-26278                                                             4-3
          *August 1, 1967        1-1910     (Form 10-K Annual Report for 1967)                       D-1
          *July 1, 1972          2-45452                                                             2-3
          *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)
</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 in Form 10-Q dated August 11, 1995, 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>
                                       57

<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 Non-qualified Deferred Compensation Plan for Executive Officers.
            (Designated as Exhibit No. 10(d) to the Annual Report on Form 10-K for the year ended December 31,
            1992, File No. 1-1910.)
*10(e)   -- Baltimore and Gas and Electric Company Non-qualified 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)   -- Constellation Holdings, Inc., Summary of Amended Executive Benefits Plan. (Designated as Exhibit No.
            10(i) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.)
*10(j)   -- 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(k)   -- Amended Summary 1992 Long Term Incentive Plan of Constellation Holdings, Inc. (Designated as Exhibit
            No. 10(k) to the Annual Report on Form 10-K for the year ended December 31, 1993, File No. 1-1910.)
*10(l)   -- 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(m)   -- 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(n)   -- 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(o)   -- Severance Agreements between BGE and 15 key employees.
 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: None.
                                       58

<PAGE>
              BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
                SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
<TABLE>
<CAPTION>
                                                                     COLUMN C
                                                COLUMN B             ADDITIONS
                                                BALANCE     CHARGED                                              COLUMN E
                                                   AT         TO                                                 BALANCE
                                                BEGINNING    COSTS     CHARGED TO OTHER         COLUMN D          AT END
COLUMN A                                           OF         AND        ACCOUNTS --        (DEDUCTIONS) --         OF
DESCRIPTION                                      PERIOD     EXPENSES       DESCRIBE             DESCRIBE          PERIOD
<S>                                             <C>         <C>        <C>                 <C>                   <C>
                                                                             (IN THOUSANDS)
Reserves deducted in the Balance Sheet from
  the assets to which they apply:
  Accumulated Provision for Uncollectibles
     1995....................................   $14,960     $19,170        $     --             $(17,740)        $16,390
     1994....................................    13,957      20,557              --              (19,554)(A)      14,960
     1993....................................    12,484      19,155              --              (17,682)(A)      13,957
  Valuation Allowance --
     Net unrealized (gain) loss on available
     for sale securities
     1995....................................     5,609          --         (14,010)(B)               --          (8,401 )
     1994....................................        --          --           5,609(B)                --           5,609
     1993....................................        --          --              --                   --              --
  Provision for possible disallowance of
     replacement energy costs
     1995....................................    35,000          --              --                   --          35,000
     1994....................................    35,000          --              --                   --          35,000
     1993....................................    35,000          --              --                   --          35,000
  Loan loss reserve
     1995....................................        --          --              --                   --              --
     1994....................................     5,123          --              --               (5,123)(C)          --
     1993....................................     4,382         741              --                   --           5,123
  Energy projects under development reserves
     1995....................................     1,806          --              --               (1,504)(D)         302
     1994....................................     1,778          28              --                   --           1,806
     1993....................................       492       1,286              --                   --           1,778
</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.
                                       59

<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)
                                          By /s/        C. H. POINDEXTER
Date: March 15, 1996
                                                      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>                                   <C>
Principal executive officer and director:
         By /s/              C. H. POINDEXTER           Chairman of the Board and Director    March 15, 1996
                    C. H. POINDEXTER
Principal financial and accounting officer:
         By /s/              C. W. SHIVERY              Vice President and Secretary          March 15, 1996
                    C. W. SHIVERY
Directors:
            /s/              H. F. BALDWIN              Director                              March 15, 1996
                    H. F. BALDWIN
            /s/              B. B. BYRON                Director                              March 15, 1996
                    B. B. BYRON
            /s/              J. O. COLE                 Director                              March 15, 1996
                    J. O. COLE
            /s/              D. A. COLUSSY              Director                              March 15, 1996
                    D. A. COLUSSY
            /s/              E. A. CROOKE               Director                              March 15, 1996
                    E. A. CROOKE
            /s/              J. R. CURTISS              Director                              March 15, 1996
                    J. R. CURTISS
            /s/              J. W. GECKLE               Director                              March 15, 1996
                    J. W. GECKLE
            /s/              M. L. GRASS                Director                              March 15, 1996
                    M. L. GRASS
</TABLE>
                                       60

<PAGE>
<TABLE>
<S>                                                     <C>                                   <C>
            /s/              F. A. HRABOWSKI III        Director                              March 15, 1996
                    F. A. HRABOWSKI III
            /s/              N. LAMPTON                 Director                              March 15, 1996
                    N. LAMPTON
            /s/              G. V. MCGOWAN              Director                              March 15, 1996
                    G. V. MCGOWAN
            /s/              G. L. RUSSELL, JR.         Director                              March 15, 1996
                    G. L. RUSSELL, JR.
            /s/              M. D. SULLIVAN             Director                              March 15, 1996
                    M. D. SULLIVAN
</TABLE>

                                       61

<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 April 25, 1995. (Designated as Exhibit No. 3(a) in Form 10-Q dated May
            11, 1995, File No. 1-1910.)
  *3(b)  -- Articles Supplementary, dated as of September 5, 1995, to the Charter of BGE. (Designated as Exhibit
            No. 3 in Form 10-Q dated November 13, 1995, File No. 1-1910.)
  *3(c)  -- 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>        <C>                                                    <C>
          *April 15, 1966        2-26278                                                               4-3
          *August 1, 1967        1-1910     (Form 10-K Annual Report for 1967)                         D-1
          *July 1, 1972          2-45452                                                               2-3
          *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)
</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 in Form 10-Q dated August 11, 1995, File No. 1-1910.)
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<PAGE>
<TABLE>
<S>       <C>
 *10(b)   -- Executive Incentive Plan of the Baltimore Gas and Electric Company. (Designated as Exhibit No.
             10(b) to the Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1910.)
 *10(c)   -- Baltimore Gas and Electric Company 1995 Long-Term Incentive Plan. (Designated as Exhibit No. 10(c)
             to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.)
 *10(d)   -- Baltimore Gas and Electric Company Non-qualified Deferred Compensation Plan for Executive
             Officers. (Designated as Exhibit No. 10(d) to the Annual Report on Form 10-K for the year ended
             December 31, 1992, File No. 1-1910.)
 *10(e)   -- Baltimore and Gas and Electric Company Non-qualified 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)   -- Constellation Holdings, Inc., Summary of Amended Executive Benefits Plan. (Designated as Exhibit
             No. 10(i) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No.
             1-1910.)
 *10(j)   -- 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(k)   -- Amended Summary 1992 Long Term Incentive Plan of Constellation Holdings, Inc. (Designated as
             Exhibit No. 10(k) to the Annual Report on Form 10-K for the year ended December 31, 1993, File No.
             1-1910.)
 *10(l)   -- 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(m)   -- 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(n)   -- 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(o)   -- Severance Agreements between BGE and 15 key employees.
     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.)
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*Incorporated by Reference.
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