Settlement Agreement

Exhibit No. 10

by Constellation Energy
June 29th, 1999


                                                                  EXHIBIT NO. 10
                                                                  --------------

                                   BEFORE THE
                            PUBLIC SERVICE COMMISSION
                                   OF MARYLAND

- ------------------------------------------------------------
In the Matter of the Baltimore Gas And Electric
Company's Proposed:
(a) Stranded Cost Quantification Mechanism; (b) Price
Protection Mechanism; and (c) Unbundled Rates

In the Matter of the Petition of the Office of               Case Nos. 8794/8804
People's Counsel for a Reduction in the Rates and
Charges of the Baltimore Gas and Electric Company


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


                      STIPULATION AND SETTLEMENT AGREEMENT
                      ------------------------------------

         Baltimore Gas and Electric Company ("BGE"),  Maryland  Industrial Group
and  Millennium  Inorganic  Chemicals,  Inc.,  Maryland  Retailers  Association,
Building Owners and Managers  Association of Baltimore,  Inc., The Johns Hopkins
University   and  Johns  Hopkins  Health  System   Corporation,   Department  of
Defense/Federal  Executive  Agencies,  Board of County  Commissioners of Calvert
County,  Maryland,  Maryland  Energy  Administration,  The Power Plant  Research
Program of the Maryland  Department  of Natural  Resources,  Maryland  Office of
People's  Counsel  ("OPC"),  Enron  Energy  Services,  Inc.,  National  Railroad
Passenger  Corporation,  and the Staff of the Maryland Public Service Commission
(individually and collectively referred to as the "Settling Parties"),  agree as
follows:

                                       1


         WHEREAS,  the Public Service  Commission of Maryland (the "Commission")
instituted  this  proceeding  pursuant  to orders  entered  in the  Commission's
proceeding  to  investigate  regulatory  and  competitive  issues  affecting the
electric utility industry in Maryland, Case No. 8738;

         WHEREAS,  the orders  issued in Case No.  8738  required,  among  other
things,  that each major  investor-owned  electric utility operating in Maryland
make a filing on or before July 1, 1998 setting forth its  proposals  regarding:
(1) the  quantification  and recovery of costs, if any, that will be stranded in
connection with the transition to a restructured  electric industry in Maryland;
(2) price protection measures to be instituted during the transition period; and
(3) unbundled rates for retail electric services;

         WHEREAS,  on July 1, 1998, BGE filed its initial testimony and exhibits
in Case No. 8738 and BGE's filing was docketed as Case No. 8794;

         WHEREAS,  on September 3, 1998, OPC filed a petition for a reduction in
rates and charges of BGE, which was docketed by the Commission as Case No. 8804;

         WHEREAS, on October 23, 1998, the Commission consolidated Case No. 8804
with BGE's restructuring proceeding, Case No. 8794;

         WHEREAS,   pursuant  to   procedural   schedules   in  effect  in  this
consolidated  proceeding,  BGE and other parties filed additional  testimony and
exhibits on December 22, 1998, February 5, 1999, and March 22, 1999;

         WHEREAS, on April 8, 1999, Maryland Governor Glendening signed into law
the Electric  Customer Choice and  Competition  Act of 1999 (the  "Restructuring
Act")  and the  Electric  and  Gas  Utility  Tax  Reform  Act  (the  "Tax  Act,"
collectively,  the "Acts"),  which provide for the  transition to a restructured
electric industry in Maryland;


                                       2


         WHEREAS,  on April 29,  1999,  BGE  filed  supplemental  testimony  and
exhibits  to  address  changes to BGE's  previous  filings  necessitated  by the
legislation  and to enable the  Commission to make the findings  required by the
Acts;
         WHEREAS,  a  substantial  amount of discovery has been  conducted  with
         respect to BGE's  filings;

         WHEREAS,  the  Settling  Parties  have been  engaged  in  comprehensive
negotiations  with  respect  to BGE's  proposals  and  certain  related  matters
presented by this proceeding and the Acts;

         NOW, THEREFORE, the Settling Parties agree to the following stipulation
and settlement agreement ("Settlement"):

                                       I.

                                Transition Costs
                                ----------------

1.       BGE shall recognize  accelerated  depreciation or amortization totaling
         $150 million  (pre-tax) on generation  assets over the 12-month  period
         from  July  1,  1999  through  June  30,  2000.  For  purposes  of this
         Settlement,      however,      the     $150     million     accelerated
         depreciation/amortization has been immediately applied to calculate the
         transition cost recovery amount set forth in Paragraph 2.

2.       The after-tax transition costs to be recovered from customers by BGE is
         $528 million  expressed on a present value basis as of January 1, 2000,
         which does not include any future  claim for net  competitive  metering
         related  transition costs described in Paragraph 45. In accordance with
         the Public  Utility  Companies  Article  (hereinafter  "Code")  Section
         7-501(P),  "transition costs" whenever used in



                                       3


         this  Settlement  include,  but  are not  limited  to,  BGE's  stranded
         investment for its generation assets and facilities,  including capital
         improvements, facilities directly related to generation but recorded as
         transmission facilities, and the appropriate allocation of common plant
         (collectively,  "generation  assets"),  purchased power contracts,  and
         restructuring  costs, as defined in Paragraph 46. Upon approval of this
         Settlement by the Commission  without  modification  or condition,  the
         $528 million  amount shall be deemed (a) a final  determination  of the
         amount of  transition  costs or benefits  arising  from the  generation
         assets  to be  transferred,  as that  phrase  is used in Code  Sections
         7-508(C)(1)(II)  and  7-509(C)(2);  and  (b)  a  determination  of  the
         transition costs and the amounts of the transition costs that BGE shall
         be  provided  an  opportunity  to  recover  pursuant  to  Code  Section
         7-513(B).  Except for any  future  claim for net  competitive  metering
         related  transition costs, BGE shall be forever barred from filing for,
         or seeking  recovery  of, in any  manner,  any other  transition  costs
         whether  or not  sought  by BGE in this  proceeding.  The $528  million
         amount was agreed to by the Settling  Parties in  consideration  of the
         factors set forth in Code Section  7-513(E)(1)(II).  The  allocation of
         the $528 million  transition costs shall be as follows:  $193.8 million
         to residential  customers;  $53.8 million to Schedules G and GS; $112.6
         million to Schedule GL;  $100.7  million to Schedule P; $5.1 million to
         Schedule  SL; $2.5  million to Schedule  NRP;  and the balance of $59.5
         million to  Schedule  PL and  individual  customer  contracts  based on
         individually  negotiated  agreements  to be  separately  filed with the
         Commission.   The  allocation  of  transition  costs,  if  any,  to  an
         individual  contract  customer  shall  remain  the  obligation  of that
         customer if it


                                       4


         exercises any right to choose an alternative supplier.  Such individual
         contract  customers  reserve  all  rights to  protest or take any other
         position  on any BGE  attempt  to  recover  transition  costs from such
         customers.  The foregoing  transition  cost amount and allocation  were
         agreed to by the Settling  Parties in  consideration of the factors set
         forth in Code Section 7-513(E)(2).

3.       A  competitive  transition  charge  ("CTC"),  in the form of a  per-kWh
         charge as set forth in Appendix A, shall be imposed,  by rate schedule,
         to recover the amount of transition costs set forth in Paragraph 2. For
         Schedules R, RL, ES, NRP, and SL, these  per-kWh  charges are to remain
         unchanged  during the applicable  recovery  period  without  true-up or
         reconciliation  between  actual  collections  and the  transition  cost
         amount used to compute the per-kWh  charges.  For  Schedules G, GS, GL,
         and P, the  respective  CTCs shall be  adjusted  annually by CTC option
         within each rate schedule for the sole purpose of  reconciling,  by CTC
         option within each rate schedule, the annual revenues received from the
         CTC charge to take account of differences  between the actual  kilowatt
         hour  sales for the CTC  option  within  each rate  schedule  times the
         applicable CTCs in the prior year and the previously estimated kilowatt
         hour  sales for the CTC  option  within  each rate  schedule  times the
         applicable   CTCs  for  that  same  year,   pursuant  to  Code  Section
         7-513(D)(1).  The Settling Parties agree that the foregoing  mechanisms
         for transition cost recovery are  appropriate  mechanisms for such cost
         recovery   in   accordance    with   Code    Sections    7-513(B)   and
         7-513(D)(2)(III).  Pursuant to Code


                                       5


         Section  7-513(A)(4),   a  CTC  may  not  apply  to  on-site  generated
         electricity under certain circumstances.

4.       Notwithstanding  Paragraph  3, no later  than 30 days  prior to July 1,
         2000,  customers  on Schedule GL with a maximum  annual kW demand of at
         least  500  kW,  Schedule  P,  or  Schedule  NRP,  and  customers  with
         individual contracts may elect a lump sum payment in lieu of the CTC as
         described in Paragraphs 30 and 31. In addition, after July 1, 2000, BGE
         agrees to negotiate in good faith a lump sum buy out or, alternatively,
         permit any  customer on Schedule GL with a maximum  annual kW demand of
         at least 500 kW,  Schedule P, or Schedule  NRP to move to a shorter CTC
         payment  option (with an  appropriate  one time  adjustment).  Lump sum
         payments  in lieu of the CTC  shall  be  trued  up in  accordance  with
         Paragraphs 30 and 31.

5.       An  after-tax   discount  rate  of  7.25  percent,   using  a  mid-year
         discounting convention,  was utilized in the calculation of the CTC and
         shall be utilized in the  calculation  of any lump sum or other payment
         under Paragraph 4. The Settling Parties agree that use of this discount
         rate shall be of no precedential value.

                                       II.

                           Deregulation of Generation
                           --------------------------

6.       Following the  implementation  of full customer choice for all customer
         classes,  the generation  function of BGE shall be deregulated  and BGE
         shall transfer,  sell,


                                       6


         lease, assign,  mortgage,  or otherwise dispose or encumber some or all
         of  its  generation  assets  to  either  affiliated  or  non-affiliated
         entities  and the  Settling  Parties  agree  not to  object to any such
         transaction. For any such transaction entered into after June 30, 1999,
         BGE or its affiliate, as applicable, shall retain or absorb 100% of any
         revenues,  gains and losses on the transfer,  sale, lease,  assignment,
         mortgage or other  disposition or  encumbrance of generation  assets (a
         "Post-Settlement Transaction"),  including Post-Settlement Transactions
         between BGE and either affiliated or non-affiliated  entities,  as well
         as   Post-Settlement    Transactions   between   BGE   affiliates   and
         non-affiliated  entities.  No portion of the revenues,  gains or losses
         from any  Post-Settlement  Transaction shall be used by any party or by
         the Commission in any future proceeding to adjust rates in any way. Any
         transfer of a generation  asset from BGE to an affiliate shall occur at
         book  value  and the  Settling  Parties  agree  to  support  or take no
         position  before the  Commission  regarding  any such  transfer at book
         value.  Book value is the  original  cost less the related  accumulated
         depreciation  and  accumulated  deferred tax  effects.  The transfer of
         generation  assets shall be reflected on the books of the  affiliate by
         removing  from  the  books  of BGE and  recording  on the  books of the
         affiliate  the  amounts  shown  on the  books  of BGE as of the date of
         transfer  for  the  (i)  original   cost  of  the   generation   assets
         transferred;  (ii)  accumulated  depreciation on the generation  assets
         transferred;  and (iii)  accumulated  deferred  taxes on the generation
         assets transferred.  (For property tax assessment purposes,  the result
         of such  transfer  of  generation  assets will be that the books of the
         affiliate  will  reflect  the  same  original  cost  basis  used by the
         Maryland  Department of Assessments


                                       7


         and Taxation for determining the property tax assessment allocation for
         current and newly acquired generation assets and capital improvements.)
         With respect to BGE's  future  application  for transfer of  generation
         assets referenced in Paragraph 7, the Settling Parties agree to support
         or take no position with respect to BGE's  request for a  determination
         by the Commission,  in accordance with Code Section 7-508(C),  that the
         transfer at book value and the removal of that amount from rate base is
         the appropriate regulatory accounting; that such a transfer does not or
         would not result in an undue adverse  effect on the proper  functioning
         of a competitive electricity supply market; and that such a transfer is
         at the appropriate  transfer price and constitutes the appropriate rate
         making treatment for the transfer.  The Settling Parties agree that the
         foregoing  satisfies  Code Section  7-513(D)(2)(III)  and is in lieu of
         Code Section  7-513(D)(2)(II).  Nothing in  Paragraphs 6, 7, or 8 shall
         impair the operation of Code Sections 7-508 and 7-509.

7.       Pursuant  to  Code  Section  7-508(C)(3),   BGE  shall  file  with  the
         Commission by December 31, 1999,  and provide to the Settling  Parties,
         its  application  for  transfer  of  generation  assets and  supporting
         information,  including  a  schedule  of  generation  assets,  proposed
         allocations  of common plant,  and a  reconciliation  of its transition
         cost filing.  Subject to Paragraph 6, the Settling  Parties reserve all
         rights to protest or take any position on any such filing.

8.       The Settling Parties acknowledge that any Post-Settlement  Transactions
         may  require  various  regulatory  approvals  or waivers by the Federal
         Energy  Regulatory


                                       8


         Commission  ("FERC"),  the Nuclear  Regulatory  Commission  ("NRC") and
         other  agencies  having  lawful  authority  over these  Post-Settlement
         Transactions. The Settling Parties agree to support or take no position
         regarding BGE's requests to obtain such approvals or waivers. BGE shall
         provide  copies  of any such  filings  to the  Settling  Parties.  This
         Settlement  is not  contingent  on the  outcome of any such  regulatory
         approvals  or  waivers.  If for any  reason  the  Company  is unable to
         transfer  these  assets  and the  Commission  approves  the  Settlement
         without  modification or condition,  the Settlement continues in effect
         and the  generation  assets  shall  never be  included  in rate base or
         otherwise be reflected in rates in any fashion.

                                      III.

                          Customer Choice Availability
                          ----------------------------

9.       There is good cause shown and it is in the public interest, pursuant to
         Code Section 7-510(B),  to accelerate certain  implementation  dates as
         set forth in such  Section  7-510.  Effective  with their  first  meter
         reading on or after July 1, 2000,  100% of BGE's  retail  customers  of
         every class shall have the opportunity to be supplied with  electricity
         purchased from a supplier other than BGE,  provided  however,  that for
         those  customers who have entered into  individual  contracts  with BGE
         that will  continue in effect after July 1, 2000,  the  contract  shall
         determine when such customers shall have the opportunity to be supplied
         with  electricity  purchased  from  a  supplier  other  than  BGE.  For
         residential  customers,  BGE shall be  permitted  to delay the  initial
         implementation  date,  with  prior  Commission


                                       9


         approval,   if   it  is   experiencing   system   difficulties   during
         implementation.  However, in no event shall the initial  implementation
         date for residential customers be delayed beyond October 1, 2000.

10.      BGE agrees to allow  Schedule NS to lapse in accordance  with the terms
         of the  tariff  on  December  31,  1999  and  will not seek to renew or
         replace it with a similar generation service schedule. Furthermore, BGE
         will not commence  negotiations for any new NS contracts after June 30,
         1999,  but BGE may enter into a new NS  contract  with any  customer if
         negotiations  were ongoing as of that date.  BGE agrees to certify that
         negotiations  were  ongoing as of that date and attach an  affidavit to
         that effect with any Schedule NS contract  filing with the  Commission.
         Notwithstanding Paragraph 9, each NS customer with a generation related
         contract  shall have a unilateral,  one time option,  exercisable on or
         before  July 1,  2000,  to  terminate  its  contract  with BGE  without
         penalty,  in which case the  customer  shall  return to its former rate
         schedule,  select one of the options in this  Settlement  available  to
         that schedule,  and pay all applicable  rates and charges in accordance
         with this Settlement. At any time a Schedule NS customer terminates its
         Schedule NS contract and returns to its former schedule, the transition
         costs  allocated to that  contract  will remain the  obligation of that
         customer and no further  transition  costs shall be collected from that
         customer beyond the transition costs, if any, agreed to between BGE and
         the  customer.   Accordingly,  any  such  NS  customer  shall  make  an
         individually   negotiated


                                       10


         transition  cost  payment(s)  pursuant to Paragraph 2 and shall not pay
         the CTC charge applicable under the customer's newly chosen option.

                                       IV.

                             Standard Offer Service
                             ----------------------

11.      Standard Offer Service  ("SOS") is an electric  supply service that BGE
         will provide to customers  pursuant to Code Section  7-510(C).  The SOS
         provided  by  BGE  shall  include   energy,   capacity,   line  losses,
         transmission and related ancillary services.

12.      BGE will  provide two forms of Standard  Offer  Service:  (1)  Standard
         Offer Price  Freeze  Service  ("PFS") and (2)  Standard  Offer  Default
         Service ("DS").  Notwithstanding the provision of two forms of SOS, all
         SOS customers are free to choose a supplier other than BGE at any time,
         except that PFS  customers  are subject to the  provisions of Paragraph
         14.

13.      PFS is electric  supply  provided by BGE to certain  customers at a set
         price(s)  for a fixed  period of time.  On July 1, 2000,  customers  on
         Schedules  R, ES and RL will be PFS  customers  through  June 30,  2006
         unless served by an alternative  supplier.  In addition,  the following
         customers  are eligible  for PFS: all  customers on Schedules G, GS, GL
         Option 2, P Options 2 and 3, and NRP  Options 1 and 4. On July 1, 2000,
         customers on Schedules G, GS and customers  that elect or are deemed to
         have  elected  Schedule  GL  Option 2,  Schedule  P Options 2 and 3, or



                                       11


         Schedule  NRP  Options 1 and 4 will be deemed to be PFS  customers,  as
         will  those  customers  that  are  presumptively  PFS  customers  under
         Paragraphs 29, 30, and 31.

14.      A PFS  customer  may leave PFS at any time and may later  return to the
         same PFS  schedule or option if the  customer  signs a contract for PFS
         for: (a) at least a one-year  term; or (b) the remaining  term on BGE's
         price freeze  obligation to other customers on the same PFS schedule or
         option, whichever is less. A residential customer returning to PFS will
         not be required to sign a contract,  but will be bound by the preceding
         provisions relating to the term of PFS.  Notwithstanding the foregoing,
         if a supplier defaults,  a residential  customer will return to PFS and
         may choose an  alternative  supplier at any time.  Notwithstanding  the
         foregoing,  if  a  supplier  defaults,  a  former  non-residential  PFS
         customer may return to PFS, if available,  for an initial  period of up
         to 90 days  during  which  time the PFS  customer  may  choose  another
         alternative  supplier.  At the end of 90 days, any such non-residential
         PFS customer that has not selected an alternative  supplier or signed a
         PFS contract  shall be deemed to be a PFS customer for the remainder of
         a one-year term or the remaining term on BGE's price freeze  obligation
         to other  customers  on the same PFS  schedule or option,  whichever is
         less. For purposes of this  Paragraph,  a supplier  default occurs when
         the Office of the  Interconnection  of the PJM  Interconnection  L.L.C.
         ("PJM") has notified  PJM members that the supplier is in default.  BGE
         agrees  to  notify  the  Commission  of  this  default  promptly  after
         receiving  such notice from PJM. The Settling  Parties  agree that


                                       12


         this  Paragraph  shall have no  precedential  impact in any  Commission
         proceeding except with regard to BGE.

15.      PFS rates are set forth in Appendix A.

16.      DS is  electric  supply  to be  provided  by BGE at  formula  prices as
         referenced in Paragraph 17, to those non-residential  customers who are
         not  PFS  customers  and,  after  the  initial  implementation  date of
         customer  choice:  (a) contract  for  electricity  with an  electricity
         supplier and it is not delivered;  (b) cannot  arrange for  electricity
         from an  electricity  supplier;  or (c) do not  choose  an  electricity
         supplier.  In addition,  DS is also  provided to those  non-residential
         customers  who  have  been  denied  service  or  referred  to SOS by an
         electricity supplier in accordance with Code Section 7-507(E)(6).

17.      DS rates shall be set in  accordance  with a tariff which will be filed
         for Commission approval prior to implementation of customer choice. The
         tariff  shall  contain  a  formula  that  reflects  only the  following
         components,  or their  functional  equivalents  in the future:  the PJM
         locational  marginal  price for energy for the BGE zone, the PJM posted
         and verifiable market capacity price, transmission, ancillary services,
         line losses, appropriate taxes, and a fixed retail adder of 7 mills per
         kWh.  DS rates may vary by  customer  class and  shall  reflect  actual
         costs.  The floor price for DS will be the applicable PFS rate, if such
         a rate


                                       13


         is available at the time.  The Settling  Parties  reserve all rights to
         protest the derivation and quantification of the formula's components.

18.      BGE shall have  discretion  in how it arranges  for  generation  supply
         service for its SOS customers  prior to July 1, 2003.  Consistent  with
         Code  Section  7-510(C)(4),  beginning  July 1, 2003,  BGE shall obtain
         electric  supply  for BGE's PFS and DS  through a  competitive  bidding
         process  open  to  all  suppliers,   including  any   subsidiaries   of
         Constellation  Energy Group, Inc.  ("Constellation").  At no time shall
         BGE  accept an SOS bid that  exceeds  any of its PFS  prices.  BGE also
         agrees that it will support the  initiation of a Commission  proceeding
         no later than July 1, 2003 to  consider  the issue of  bidding  for the
         retail  provision of SOS.  BGE agrees to support a schedule  that calls
         for a  Commission  decision  on this issue in  sufficient  time so that
         competitive  bidding  could  begin  by  July  1,  2004,  however,   the
         Commission   may  delay   implementation   pursuant  to  Code   Section
         7-510(C)(4).  BGE's affiliates shall be permitted to participate in any
         competitive bidding process. The Settling Parties reserve all rights to
         protest or take any position in any such proceeding.

19.      In addition to supply  services  offered by third party  suppliers,  an
         unregulated  Constellation  subsidiary shall offer a retail competitive
         supply  service  from  July  1,  2000  through  June  30,  2006  to all
         non-residential   customers.  In  no  event  shall  BGE  offer  such  a
         competitive   supply   service.   BGE  warrants  that  an   unregulated
         Constellation  subsidiary shall offer such a retail  competitive supply


                                       14


         service. In the event such supply service is not offered,  BGE shall be
         subject  to  appropriate  action at the  Commission  for breach of this
         warranty,  and neither BGE nor its parent or  affiliates  shall protest
         such action on any jurisdictional grounds.

                                       V.

                           Price Protection/Unbundling
                           ---------------------------

A.  All Customers
- --  -------------

20.      Subject to Article VII,  BGE shall freeze total rates  inclusive of all
         surcharges  and riders in effect on June 30, 1999 through June 30, 2000
         for all customers.  From June 30, 1999 through June 30, 2000, BGE shall
         not file to revise any rate,  surcharge or rider for any customer class
         and no Settling  Party  shall file  seeking a revision in any BGE rate,
         surcharge  or  rider.  The  Settling  Parties  shall  oppose or take no
         position  on any filing for any changes in any BGE rate,  surcharge  or
         rider initiated by any other entity during this time period.  BGE shall
         adjust its retail transmission rates for  non-residential  customers to
         reflect any increases or decreases in FERC-regulated transmission rates
         prior to July 1, 2004. Any such change in retail transmission rates for
         non-residential  customers  prior to July 1,  2004  shall  result in an
         equal and opposite  change in BGE's  non-residential  wires  portion of
         delivery  service  rates.  On July 1, 2004, the  non-residential  wires
         portion of delivery  service rates shall return to either the rates set
         forth  in  Appendix  A or  any  other  rates  later  determined  by the
         Commission.

                                       15


21.      a) Effective  July 1, 2000, BGE shall unbundle rates in effect June 30,
         1999 into separate components  consisting of generation,  transmission,
         CTC, universal service,  distribution wires, competitive billing, other
         billing and metering,  environmental  surcharge,  franchise tax and PSC
         assessment as set forth in Appendix A.

         b) Effective July 1, 2000,  BGE shall  unbundle and clarify  Schedule S
         (Standby  Services) as follows:  (1)  customers may purchase the energy
         and capacity  component  (including the level) of standby  service from
         third  party  suppliers;  (2) BGE may not  impose  any  requirement  to
         purchase  or have  available  a certain  level of standby  capacity  or
         energy as long as the customer is purchasing capacity or energy from an
         alternative  supplier;  and (3) if the third  party  suppliers  fail to
         deliver standby service, customers will pay the DS rate.

22.      Customer funding for  generation-related  regulatory assets and nuclear
         decommissioning  shall be included in BGE's unbundled  delivery service
         rates as set forth in Appendix A. The term "delivery  service rates" in
         this  Settlement  means charges for universal  service  consistent with
         this  Settlement,   generation-related   regulatory   assets,   nuclear
         decommissioning,   wires,   competitive  billing,   other  billing  and
         metering, PSC assessment, the 10% portion of the Conservation Surcharge
         described  in  Paragraph  23, and  appropriate  taxes.  A  schedule  of
         generation-related regulatory assets and related annual amortization is
         set forth in  Appendix  B. The  Settling  Parties  agree that  customer
         funding of nuclear  decommissioning  shall be treated as  follows:  (a)
         customer contributions for


                                       16


         nuclear  decommissioning  costs shall be made at a fixed annual rate of
         $18,661,980 until June 30, 2006; (b) the total contribution to the cost
         of nuclear  decommissioning  to be paid by  customers is frozen at $520
         million in 1993 dollars as  established  by the Commission in Order No.
         72240;   (c)  calculations  of  customer   contributions   for  nuclear
         decommissioning costs for years beginning after June 30, 2006 shall use
         the adjustment factor for inflation set forth in 10 CFR 50.75(c)(2), as
         it may be amended,  the actual  balance of the Nuclear  Decommissioning
         Trust Fund and a  reasonable  forecast  of  expected  future  after-tax
         earnings of the Nuclear  Decommissioning  Trust Fund and the  inflation
         factor; (d) BGE shall continue to report the performance of the fund to
         the  Commission  on an annual basis as specified in Order No. 66415 and
         shall  provide a copy of the report to the  Settling  Parties;  and (e)
         after June 30, 2006 any party, at any time, may petition the Commission
         to  initiate   proceedings  to  address  the  components  necessary  to
         determine funding level  requirements,  with the exception of the total
         amount to be funded in 1993  dollars,  as specified in Item (b) and the
         adjustment factor for inflation  referenced in Item (c). BGE shall file
         such a petition by April 1, 2006,  to be  effective  July 1, 2006.  BGE
         shall  refund to customers  any balance in the Nuclear  Decommissioning
         Trust Fund at the time of decommissioning in excess of the $520 million
         in 1993 dollars,  escalated per the NRC formula,  and shall be entitled
         to  recover  any   deficiency   between  the  balance  in  the  Nuclear
         Decommissioning  Trust  Fund  and the  $520  million  in 1993  dollars,


                                       17


         escalated  per the NRC  formula,  at the time of  decommissioning.  BGE
         shall be responsible for any actual  decommissioning costs in excess of
         the $520 million in 1993 dollars,  escalated  per the NRC formula,  and
         shall retain any cost savings if actual  decommissioning costs are less
         than the $520 million in 1993  dollars,  escalated per the NRC formula.
         The Settling Parties shall be forever barred from seeking any change to
         the total amount to be funded in 1993 dollars, as specified in Item (b)
         and the adjustment  factor for inflation  referenced in Item (c) in any
         future rate case or any other proceeding before the Commission.  If the
         NRC's formula for the adjustment  factor for inflation is amended,  the
         revised  formula  shall be applied to the $520 million in 1993 dollars.
         If the NRC (or its  successor)  ceases to publish a definition  for the
         decommissioning  adjustment factor for inflation,  the Settling Parties
         shall  negotiate  in good faith a  replacement  definition,  subject to
         Commission approval.

23.      The  Conservation  Surcharge  shall be allocated  by customer  class as
         follows:  90% to SOS and 10% to the wires portion of delivery  service.
         The  Settling  Parties  agree  that  this  allocation  shall  be  of no
         precedential value in any future rate proceeding.

B.  Residential Customers
- --  ---------------------

24.      Subject to Article VII,  effective July 1, 2000, BGE shall unbundle all
         rates paid by  Schedule  R/ES  customers  on June 30, 1999 to achieve a
         total  revenue  reduction of $50.2  million  annually  through June 30,
         2006.  The revenue  reduction  shall be  allocated  to PFS rates and to
         distribution  rates in proportion to their contribution to total rates.
         The distribution rate portion is defined as the sum


                                       18


         of wires,  billing, and metering charges divided by total rates, as set
         forth in Appendix  A. The PFS  portion is equal to one hundred  percent
         minus the  distribution  rate portion.  The Settling Parties agree that
         the foregoing  satisfies Code Section  7-505(D)(4)(I)(3).

         a) Beginning  July 1, 2000 through June 30, 2006,  subject to Paragraph
         18, BGE shall provide PFS to Schedule R/ES customers.

         b) A CTC shall apply to Schedule R/ES  customers for a 5-year  11-month
         period from July 1, 2000 to May 31, 2006.

         c)  Appendix  A sets  forth  the  applicable  rates for  Schedule  R/ES
         customers.

25.      Subject to Article VII,  effective July 1, 2000, BGE shall unbundle all
         rates paid by Schedule RL customers on June 30, 1999 to achieve a total
         revenue  reduction of $3.6 million  annually through June 30, 2004. The
         revenue  reduction  shall be allocated to PFS rates and to distribution
         rates  in  proportion  to  their   contribution  to  total  rates.  The
         distribution rate portion is defined as the sum of wires,  billing, and
         metering  charges  divided by total rates,  as set forth in Appendix A.
         The PFS portion is equal to one hundred percent minus the  distribution
         rate portion.  The Settling Parties agree that the foregoing  satisfies
         Code Section  7-505(D)(4)(I)(3).  Subject to Article VII,  from July 1,
         2004  through June 30, 2006,  the  unbundled  Schedule RL rates will be
         adjusted to achieve a total revenue  reduction of $1.8 million annually
         relative to total rates paid by Schedule RL customers on June 30, 1999.


                                       19


         a) Beginning  July 1, 2000 through June 30, 2006,  subject to Paragraph
         18, BGE shall  provide  PFS to Schedule  RL  customers.

         b) A CTC shall  apply to Schedule RL  customers  for a 5-year  11-month
         period from July 1, 2000 to May 31, 2006.

         c)  Appendix  A  sets  forth  the  applicable  rates  for  Schedule  RL
         customers.

         d) Effective  with the  Commission's  order  approving  the  Settlement
         without  modification  or  condition,  or  30  days  after  the  filing
         referenced in Paragraph 26, whichever  occurs later,  Schedule RL shall
         be closed to new  customers.  Customers  on Schedule RL may transfer to
         Schedule R at any time after the closure of Schedule RL.

C.  Residential Time-of-Use Rates
- --  -----------------------------

26.      By  November  1, 1999,  BGE shall file for  Commission  approval  of an
         optional  time-of-use  rate schedule for  residential  customers.  Such
         schedule  shall be  consistent  with  rates  paid by other  Schedule  R
         customers.  The  Settling  Parties  reserve  the right to  protest  the
         methodology and quantification of the appropriate rates.

D.  Non-residential Customers
- --  -------------------------

27.      Subject to Paragraph 20 and Article VII, effective July 1, 2000 through
         June  30,  2004,   BGE  shall  freeze   delivery   service   rates  for
         non-residential customers as set forth in Appendix A.

                                       20


28.      No later than 30 days prior to July 1, 2000,  non-residential customers
         must make a one-time,  irrevocable  election among the service  options
         available to the applicable rate schedule.  Each customer shall pay the
         CTC associated  with the customer's  election unless the CTC payment is
         accelerated in accordance with Paragraph 4.

29.      No later than 30 days prior to July 1, 2000,  Schedule  G/GS  customers
         must elect one of two options for service effective July 1, 2000 as set
         forth in Appendix A. New  customers  and customers who do not elect one
         of the options shall be deemed to have selected Option 1.

         a)       Under Option 1, effective July 1, 2000, BGE shall unbundle all
                  rates paid by  Schedule  G/GS  customers  on June 30,  1999 to
                  achieve, to the extent reasonably practicable,  bill and class
                  revenue  neutrality.  Beginning July 1, 2000 to June 30, 2004,
                  BGE shall provide PFS to Schedule G/GS customers.  A CTC shall
                  apply to Schedule  G/GS Option 1 customers for a 6-year period
                  from July 1, 2000 to June 30, 2006.  Appendix A sets forth the
                  applicable rates for this option.

         b)       Under Option 2, effective July 1, 2000, BGE shall unbundle all
                  rates paid by  Schedule  G/GS  customers  on June 30,  1999 to
                  achieve, to the extent reasonably practicable,  bill and class
                  revenue  neutrality.  Beginning July 1, 2000 to June 30, 2004,
                  BGE shall provide PFS to Schedule G/GS customers.  A CTC shall
                  apply to Schedule  G/GS Option 2 customers for a


                                       21


                  5-year  period from July 1, 2000 to June 30, 2005.  Appendix A
                  sets forth the applicable rates for this option.

30.      No later than 30 days prior to July 1, 2000, Schedule GL customers must
         elect one of three  options for service  effective  July 1, 2000 as set
         forth in Appendix A. New  customers  and customers who do not elect one
         of the  options  shall be  deemed to have  selected  Option 2.

         a)       Under Option 1, effective July 1, 2000, BGE shall unbundle all
                  rates  paid by  Schedule  GL  customers  on June  30,  1999 to
                  achieve, to the extent reasonably practicable,  bill and class
                  revenue  neutrality.  Beginning  July 1, 2000,  a customer may
                  choose  a  supplier  other  than  BGE.  A CTC  shall  apply to
                  Schedule GL Option 1 customers  for a 4-year  period from July
                  1, 2000 to June 30, 2004. Appendix A sets forth the applicable
                  rates for this option.

         b)       Under Option 2, effective July 1, 2000, BGE shall unbundle all
                  rates  paid by  Schedule  GL  customers  on June  30,  1999 to
                  achieve, to the extent reasonably practicable,  bill and class
                  revenue  neutrality.  Beginning July 1, 2000 to June 30, 2004,
                  BGE shall  provide PFS to Schedule GL  customers.  A CTC shall
                  apply to Schedule GL Option 2  customers  for a 5-year  period
                  from July 1, 2000 to June 30, 2005.  Appendix A sets forth the
                  applicable rates for this option.

         c)       Under Option 3, effective July 1, 2000, BGE shall unbundle all
                  rates  paid by  Schedule  GL  customers  on June  30,  1999 to
                  achieve, to the extent reasonably practicable,  bill and class
                  revenue  neutrality.  Beginning


                                       22


                  July 1, 2000, a customer may choose a supplier other than BGE.
                  A CTC shall  apply to  Schedule  GL Option 3  customers  for a
                  5-year  period from July 1, 2000 to June 30, 2005.  Appendix A
                  sets forth the applicable rates for this option.

         d)       No later  than 30 days  prior to July 1,  2000,  customers  on
                  Schedule GL with a maximum  annual kW demand of at least 500kW
                  may elect a lump sum payment,  in lieu of a CTC. A GL customer
                  with  multiple GL and P accounts may  aggregate  loads for the
                  purpose of measuring annual maximum demand.  Beginning July 1,
                  2000,  such a customer  may choose a supplier  other than BGE.
                  The  lump  sum  payment,  in lieu of a CTC,  shall  include  a
                  gross-up  for taxes and be  calculated  in a manner which will
                  provide the same  after-tax  present  value,  as of January 1,
                  2000, as the projected CTC cash flows.  The projected CTC cash
                  flows used in this computation will be based upon a projection
                  of electric  sales for the individual  customer,  the Option 1
                  CTC, and the 7.25 percent  after-tax  discount  rate stated in
                  Paragraph 5. The sales projection for the determination of the
                  lump sum  payment  for each  customer,  separately  by account
                  where  applicable,  will be calculated  based upon the monthly
                  sales over the preceding twenty-four month period. The average
                  sales for each individual  month for the customer will then be
                  forecast.  Projections will be developed using the same growth
                  rate used in the  calculation of the CTC for the GL class.  In
                  those cases where load data does not exist,  as in the case of
                  a new customer  account,  or where load is known or reasonably


                                       23


                  expected to be changing  for an  individual  customer,  then a
                  good  faith  effort  to  negotiate  the  appropriate  lump sum
                  payment  shall  be  made  by  BGE  and  the  customer.  At the
                  customer's election,  any supplier can participate in any such
                  negotiation.  In addition,  after July 1, 2000,  BGE agrees to
                  negotiate  in good faith with any customer on Schedule GL with
                  a  maximum  annual kW  demand  of at least  500kW,  a lump sum
                  payment in lieu of the  remaining  CTC  payment  stream.  A GL
                  customer with  multiple GL and P accounts may aggregate  loads
                  for the purpose of measuring  annual maximum demand.  The lump
                  sum payment in lieu of the remaining CTC payment  stream shall
                  include a  gross-up  for taxes and be  calculated  in a manner
                  which will provide the same after-tax present value, as of the
                  date of the lump sum payment,  as the projected  remaining CTC
                  cash flows.

         e)       Lump sum CTC payments shall be calculated for a customer based
                  only upon  facilities  and  buildings in operation at the time
                  the calculation is performed.  Any new facilities or buildings
                  that receive service subsequent to the calculation of the lump
                  sum  CTC  payment  shall  be  treated  as  separate   customer
                  accounts.  Non-residential  customers  subject  to  an  annual
                  true-up of the CTC shall be held  neutral  with respect to any
                  differences  between the actual  sales of a customer  paying a
                  lump sum CTC and the  sales  used in the lump sum  projection.
                  For those  non-residential  customer classes which are subject
                  to an annual  true-up  of CTC  payments,  total  CTC  revenues
                  collected  during  the year  shall  include  a


                                       24


                  provision  for imputing the CTC revenues  that would have been
                  attributable  to  customers  who  elected  a lump sum  payment
                  option, where such CTC revenues are calculated based on actual
                  sales to lump sum customers.  For purposes of calculating  the
                  CTC revenues  attributable to lump sum payment customers,  the
                  prevailing CTC rate for each applicable  customer option group
                  within a class  shall be  multiplied  by the actual  sales for
                  each lump sum  customer.  Any  difference  between  actual and
                  projected  CTC  collections  within  each  customer  class CTC
                  option,  resulting  from the annual  true-up set forth in this
                  paragraph  shall be assessed  or credited on a customer  class
                  CTC option basis.  For purposes of calculating the revised CTC
                  for the succeeding year which reflects this  difference,  both
                  lump sum and  non-lump  sum  customers'  projected  and actual
                  sales by  customer  class CTC  option,  for the  prior  annual
                  period   shall  be   included  in  the   calculation.   Stated
                  differently,  the revised CTC for the upcoming  annual  period
                  applicable to non-lump sum customers shall be calculated on an
                  individual  customer  class CTC option basis as if there is no
                  lump  sum  option  and  by  including   the  lump  sum  option
                  customers'  projected  and  actual  sales in the  calculation.
                  Notwithstanding  the  above,  a  customer  electing a lump sum
                  payment  option shall only be subject to an annual  true-up of
                  its  transition  cost  payment  when the actual  sales to that
                  customer  vary by 7% or more from the  projected  sales volume
                  used in the  original  calculation  of their lump sum payment.
                  The total amount of any  over-collection  or  under-collection
                  from lump sum  customers  subject to


                                       25


                  true-up  shall be refunded  to the  customer by BGE or paid by
                  the customer to BGE, respectively. These transactions will not
                  affect the CTC obligation of any other customer.  The Settling
                  Parties  reserve all rights to protest the  quantification  of
                  the true-up of payments in this  Paragraph.

31.      No later than 30 days prior to July 1, 2000,  Schedule P customers must
         elect one of four  options  for service  effective  July 1, 2000 as set
         forth in Appendix A. New  customers  and customers who do not elect one
         of the  options  shall be  deemed to have  selected  Option 3.

         a)       Under Option 1, effective July 1, 2000, BGE shall unbundle all
                  rates  paid  by  Schedule  P  customers  on June  30,  1999 to
                  achieve, to the extent reasonably practicable,  bill and class
                  revenue  neutrality.  Beginning  July 1, 2000,  a customer may
                  choose  a  supplier  other  than  BGE.  A CTC  shall  apply to
                  Schedule P Option 1 customers for a 4-year period from July 1,
                  2000 to June 30,  2004.  Appendix A sets forth the  applicable
                  rates for this option.

         b)       Under Option 2, effective July 1, 2000, BGE shall unbundle all
                  rates  paid  by  Schedule  P  customers  on June  30,  1999 to
                  achieve, to the extent reasonably practicable,  bill and class
                  revenue  neutrality.  Beginning July 1, 2000 to June 30, 2001,
                  BGE shall provide PFS to Schedule P Option 2 customers.  A CTC
                  shall  apply to  Schedule  P Option 2  customers  for a 5-year
                  period  from July 1, 2000 to June 30,  2005.  Appendix  A sets
                  forth the applicable rates for this option.

                                       26


         c)       Under Option 3, effective July 1, 2000, BGE shall unbundle all
                  rates  paid  by  Schedule  P  customers  on June  30,  1999 to
                  achieve, to the extent reasonably practicable,  bill and class
                  revenue  neutrality.  Beginning July 1, 2000 to June 30, 2002,
                  BGE shall provide PFS to Schedule P Option 3 customers.  A CTC
                  shall  apply to  Schedule  P Option 3  customers  for a 6-year
                  period  from July 1, 2000 to June 30,  2006.  Appendix  A sets
                  forth the applicable rates for this option.

         d)       Under Option 4, effective July 1, 2000, BGE shall unbundle all
                  rates  paid  by  Schedule  P  customers  on June  30,  1999 to
                  achieve, to the extent reasonably practicable,  bill and class
                  revenue  neutrality.  Beginning  July 1, 2000,  a customer may
                  choose  a  supplier  other  than  BGE.  A CTC  shall  apply to
                  Schedule P Option 4 customers for a 5-year period from July 1,
                  2000 to June 30,  2005.  Appendix A sets forth the  applicable
                  rates for this option.

         e)       No later  than 30 days  prior to July 1,  2000,  customers  on
                  Schedule  P may  elect a lump  sum  payment  in lieu of a CTC.
                  Beginning July 1, 2000,  such a customer may choose a supplier
                  other  than BGE.  The lump sum  payment in lieu of a CTC shall
                  include a  gross-up  for taxes and be  calculated  in a manner
                  which will provide the same  after-tax  present  value,  as of
                  January  1,  2000,  as  the  projected  CTC  cash  flows.  The
                  projected  CTC cash  flows  used in this  computation  will be
                  based upon a projection of electric  sales for the  individual
                  customer,  the Option 1 CTC,  and the 7.25  percent  after-tax
                  discount rate stated in Paragraph 5. The sales


                                       27


                  projection for the  determination  of the lump sum payment for
                  each customer, separately by account where applicable, will be
                  calculated  based upon the  monthly  sales over the  preceding
                  twenty-four   month   period.   The  average  sales  for  each
                  individual  month  for the  customer  will  then be  forecast.
                  Projections  will be developed  using the same growth rate for
                  the P class used in the calculation of the CTC. In those cases
                  where  load  data  does  not  exist,  as in the  case of a new
                  customer  account,  or  where  load  is  known  or  reasonably
                  expected to be changing  for an  individual  customer,  then a
                  good  faith  effort  to  negotiate  the  appropriate  lump sum
                  payment  shall  be  made  by  BGE  and  the  customer.  At the
                  customer's election,  any supplier can participate in any such
                  negotiation.  In addition,  after July 1, 2000,  BGE agrees to
                  negotiate in good faith with any customer on Schedule P a lump
                  sum payment in lieu of the remaining CTC payment  stream.  The
                  lump sum payment in lieu of the remaining  CTC payment  stream
                  shall  include a  gross-up  for taxes and be  calculated  in a
                  manner which will provide the same after-tax present value, as
                  of the  date  of  the  lump  sum  payment,  as  the  projected
                  remaining  CTC cash flows.

         f)       Lump sum CTC payments shall be calculated for a customer based
                  only upon  facilities  and  buildings in operation at the time
                  the calculation is performed.  Any new facilities or buildings
                  that receive service subsequent to the calculation of the lump
                  sum  CTC  payment  shall  be  treated  as  separate   customer
                  accounts.  Non-residential  customers  subject  to  an  annual
                  true-up of the CTC shall be held  neutral  with respect to any


                                       28


                  differences  between the actual  sales of a customer  paying a
                  lump sum CTC and the  sales  used in the lump sum  projection.
                  For those  non-residential  customer classes which are subject
                  to an annual  true-up  of CTC  payments,  total  CTC  revenues
                  collected  during  the year  shall  include  a  provision  for
                  imputing the CTC revenues that would have been attributable to
                  customers  who elected a lump sum payment  option,  where such
                  CTC revenues are calculated  based on actual sales to lump sum
                  customers.  For  purposes  of  calculating  the  CTC  revenues
                  attributable to lump sum payment customers, the prevailing CTC
                  rate for each applicable  customer option group within a class
                  shall be  multiplied  by the  actual  sales  for each lump sum
                  customer.  Any  difference  between  actual and  projected CTC
                  collections  within each customer class CTC option,  resulting
                  from the annual true-up set forth in this  paragraph  shall be
                  assessed or credited on a customer class CTC option basis. For
                  purposes of  calculating  the  revised CTC for the  succeeding
                  year  which  reflects  this  difference,  both  lump  sum  and
                  non-lump sum customers' projected and actual sales by customer
                  class  CTC  option,  for the  prior  annual  period  shall  be
                  included in the calculation.  Stated differently,  the revised
                  CTC for the upcoming annual period  applicable to non-lump sum
                  customers shall be calculated on an individual  customer class
                  CTC  option  basis as if there  is no lump sum  option  and by
                  including the lump sum option customers'  projected and actual
                  sales  in  the  calculation.   Notwithstanding  the  above,  a
                  customer  electing  a lump sum  payment  option  shall only be
                  subject to an annual


                                       29


                  true-up of its stranded  cost payment when the actual sales to
                  that  customer  vary by 7% or more  from the  projected  sales
                  volume  used in the  original  calculation  of their  lump sum
                  payment.   The  total   amount  of  any   over-collection   or
                  under-collection  from lump sum  customers  subject to true-up
                  shall  be  refunded  to the  customer  by BGE or  paid  by the
                  customer to BGE,  respectively.  These  transactions  will not
                  affect the CTC obligation of any other customer.  The Settling
                  Parties  reserve all rights to protest the  quantification  of
                  the true-up of payments in this Paragraph.

32.      Beginning July 1, 2000, BGE shall unbundle Schedule NRP as set forth in
         Appendix A. An individually negotiated CTC payment schedule shall apply
         to Schedule NRP.

33.      Beginning July 1, 2000, BGE shall unbundle  Schedule SL and a CTC shall
         apply to  Schedule  SL  customers  for a 6-year  period as set forth in
         Appendix A.

                                       VI.

                                   Rate Design
                                   -----------

34.      BGE agrees that it cannot file for any electric rate design  changes at
         the  Commission  prior to July 1, 2001.  BGE also agrees to file at the
         Commission a cost of service study showing equalized rates of return at
         the time of its next electric rate case.

                                       30


                                      VII.

                           Adjustments to Frozen Rates
                           ---------------------------

35.      The rates set forth in  Appendix A provide  for the  effects of the Tax
         Act,  including the  requirements of Section 2 of the Tax Act, and said
         rates shall not be adjusted further for changes pursuant to the Tax Act
         except as provided in Paragraph 36.

36.      Beginning July 1, 2000, the following items shall be separately  stated
         surcharges,  adjusted  periodically,  subject to Commission  review and
         approval,  to reflect actual costs:  (1) the Public Service  Commission
         assessment;   (2)  the  kWh   franchise   tax;  and  (3)  the  electric
         environmental surcharge. In addition,  non-residential CTC charges will
         be  adjusted  annually  to  reflect   differences  between  actual  and
         projected sales as set forth in Paragraph 3. This adjustment  shall not
         result in rates  above the frozen  total rate for each  non-residential
         PFS rate option. The Settling Parties reserve all rights to protest the
         methodology and quantification of the appropriate rates.

37.      The following  charges shall be additions  above the applicable  frozen
         rates:  (1)  deferred  fuel  balance  true-up  charge  as set  forth in
         Paragraph 38; (2) any  residential  public benefits charge as set forth
         in Paragraph 41; (3) any other  non-universal  service  related  public
         purpose  program  costs not  included  in rates on  January  1, 2000 as
         provided  for by the  Restructuring  Act;  (4) any  consumer  education
         program costs  established  by law,  regulation or order for the fiscal


                                       31


         years  ended June 30,  2001 and June 30,  2002 as  provided  for by the
         Restructuring Act; (5) for residential  customers,  BGE's allocation of
         universal  service  program  costs beyond its initial share of the $9.6
         million  allocation  authorized  by  the  Restructuring  Act;  (6)  for
         non-residential   customers,  BGE's  allocation  of  universal  service
         program costs beyond its initial share of the $24.4 million  authorized
         by the  Restructuring Act for the period beginning July 1, 2000 to June
         30, 2003;  (7) for  non-residential  customers,  BGE's  non-residential
         allocation of any universal  service program costs authorized  pursuant
         to the Restructuring Act for the period beginning July 1, 2003; and (8)
         any  extraordinary  costs  approved by the  Commission  as set forth in
         Paragraph  39. The Settling  Parties  reserve all rights to protest the
         quantification of the amount or that the Restructuring Act has not been
         properly implemented.

38.      The actual  deferred  fuel balance on June 30, 2000 shall be subject to
         Commission  review and  approval  and trued up on a one-time  basis (or
         spread  over  some  number  of  months  depending  on the  size  of the
         true-up).  BGE shall  provide  a copy of its  true-up  filing  with the
         Commission to each Settling  Party.  The Settling  Parties  reserve all
         rights to protest the quantification of the amount.

39.      BGE shall be permitted to file for  Commission  approval of recovery of
         extraordinary costs resulting from significant  increases in federal or
         state  taxes due to changes  in law or  regulation,  other  significant
         changes  in law or  regulation,  or a  natural  disaster,  which  taken
         individually,   constitute  a  material  impairment  of


                                       32


         the financial  condition of BGE's distribution  service and only if BGE
         has actually  incurred such costs.  Changes in nuclear  decommissioning
         costs and/or power supply costs are not extraordinary costs and are not
         recoverable  under this  Paragraph.  The Settling  Parties  reserve all
         rights to protest or take any position on any such filing.

40.      After the residential and  non-residential  funding costs for universal
         service have been  determined and  surcharged  separately in accordance
         with the Restructuring  Act, BGE shall make a revenue neutral reduction
         in SOS and  distribution  rates for each  class in  proportion  to each
         class' total  revenue  requirement.  The  distribution  rate portion is
         defined as the sum of wires,  billing,  and metering charges divided by
         total  rates,  as set forth in  Appendix A. The SOS portion is equal to
         one hundred percent minus the distribution  rate portion.  The Settling
         Parties agree that the foregoing satisfies Code Section  7-512.1(B)(5).
         Furthermore,  pursuant to Code Section 7-512.1(H)(5),  in any year when
         there  are  unexpended  funds,  those  funds  will be  returned  to the
         customer  classes  proportionate  to how the customer classes paid into
         the fund.  The  Settling  Parties  reserve  all rights to  protest  the
         quantification  and methodology for returning any such unexpended funds
         to customers.

41.      Subject to review and  approval by the  Commission,  effective  July 1,
         2000,  a  public  benefits  surcharge  may be  imposed  on  residential
         customers  to fund demand side  management,  renewable  resources,  and
         aggregation  technical



                                       33


         assistance.  The  surcharge  shall  not  exceed  1.0  mill  per kWh for
         residential  customers.  Any such  surcharge  has not been  included in
         Appendix A. The program  terminates  July 1, 2006. The surcharge  shall
         not apply to  non-residential  customers.  The Settling Parties reserve
         all rights to protest or take any position on any filing made  pursuant
         to this Paragraph.

42.      While rates shall be frozen in accordance  with this  Settlement,  this
         Settlement  does not preclude BGE from  petitioning  the Commission for
         authority to implement, to the extent that such costs are not reflected
         in current rates:  (a)  cost-based  charges or fees for new services or
         offerings,  including,  but not limited to,  charges for  extraordinary
         billing  history  data  and  supplier  settlement  and  load  profiling
         operating costs; (b) cost-based fees for customer-specific nonrecurring
         costs; or (c) revisions to service extension  provisions of its Tariff.
         BGE  shall  provide  a copy  of  any  such  petitions  filed  with  the
         Commission to each Settling  Party.  The Settling  Parties  reserve all
         rights to protest or take any position on any such filing.

43.      Subject  to  Article  VII,  BGE  agrees  that  it  shall  not  file  an
         application  for an increase in its residential  electric  distribution
         rates before December 1, 2005.  Subject to Article VII, BGE agrees that
         it shall not file an application for an increase in its non-residential
         electric  distribution  rates before  December 1, 2003. When filing any
         such  application,  BGE shall  include a cost of service  study for the
         most recent period  practicable.  The Settling  Parties agree that they
         shall  not


                                       34


         request  or  suggest  that  the  Commission  revise  BGE's  residential
         electric  distribution  rates to be  effective  before July 1, 2006 and
         will  oppose  or take no  position  with  respect  to any such  request
         initiated by some other  entity.  The Settling  Parties agree that they
         shall  not  request  or  suggest  that  the  Commission   revise  BGE's
         non-residential electric distribution rates to be effective before July
         1, 2004 and will  oppose or take no position  with  respect to any such
         request initiated by some other entity.

                                      VIII.

                                 Code of Conduct
                                 ---------------

44.      BGE agrees to  support  and the  remaining  Settling  Parties  agree to
         support  or  take no  position  before  the  Commission  regarding  the
         following principles related to a GENCO code of conduct:

         a)       While it  serves  as SOS  provider,  BGE  shall not be able to
                  market or promote its SOS. However,  this limitation shall not
                  preclude BGE from providing unbiased  information to customers
                  that SOS is available and the terms thereof.

         b)       Until  June  30,  2006,   the  BGE-GENCO  must  sell  all  the
                  generation  output  of  the  assets   transferred  under  this
                  settlement,  including  energy,  capacity  and other  products
                  (excluding  all output sold to BGE for SOS) into the wholesale
                  market.

                                       35


         c)       Until June 30, 2006, BGE-GENCO shall be a separate subsidiary
                  from BGE's unregulated retail marketing affiliate and separate
                  from BGE.

         d)       With  respect  to sales or any  other  transfer  to any of its
                  affiliates  for  resale  to  "retail  electric  customers"  as
                  defined in Code Section  1-101(AA)  (including but not limited
                  to BGE's  unregulated  retail marketing  affiliate) in the BGE
                  distribution  service  territory  until  June  30,  2003,  the
                  BGE-GENCO shall not offer power or ancillary services incident
                  to the  delivery  of power at prices and terms more  favorable
                  than those available to non-affiliated electric suppliers. The
                  Settling  Parties  reserve  all  rights to protest or take any
                  other  position on this issue for periods  after July 1, 2003.
                  Such  information  regarding  the above sales or  transfers of
                  power and ancillary services by the BGE-GENCO to its affiliate
                  shall  be  simultaneously  posted  with the  execution  of any
                  agreement  for the sale or  transfer  on a publicly  available
                  electronic  bulletin board.  This provision shall not apply to
                  sales by BGE-GENCO to BGE for SOS.

         e)       BGE shall not market or promote the competitive supply service
                  referenced in Paragraph 19.  Further,  BGE shall not (1) imply
                  or express that its affiliation with the unregulated affiliate
                  allows the  affiliate  to provide a service  superior  to that
                  available from other suppliers, or (2) promote the warranty of
                  this service reflected in Paragraph 19.

                                       36


         The BGE-GENCO  shall abide by the  provisions in this  Paragraph  until
         such time as the Commission  renders a decision  regarding a GENCO code
         of conduct,  however,  the Settling  Parties  shall not be permitted to
         take any position in any generic  proceeding on any issue  inconsistent
         with these principles.

                                       IX.

                              Competitive Metering
                              --------------------

45.      Notwithstanding  any other  provision  of this  Paragraph,  competitive
         metering  shall  commence on January 1, 2002 for customers  with hourly
         demand  meters  greater than 1500 kW and on April 1, 2002 for all other
         customers,  consistent with Code Section 7-511. BGE shall file with the
         Commission to unbundle its rates for metering services  sufficiently in
         advance to permit  implementation  of competitive  metering services on
         January 1, 2002. The term "net competitive  metering related transition
         costs"  when  used in this  Settlement  means any  prudently  incurred,
         verifiable  and   non-mitigable   net  competitive   metering   related
         transition costs,  which, as set forth in Paragraph 2, are not included
         in the transition cost recovery amount. BGE may petition the Commission
         to recover its net competitive  metering related  transition  costs, if
         any.  The  Settling  Parties  agree  that  prior  to  such  dates,  the
         Commission  should  establish  the  level of net  competitive  metering
         related  transition  costs,  if any,  and the method of recovery of any
         such  transition  costs.  The Settling  Parties  further agree that the
         Commission  should establish and adjust rates to permit recovery of the
         level of net  metering  related  transition  costs and the  method  for
         recovery of such transition costs in a separate


                                       37


         proceeding  that should be completed no later than October 1, 2001. The
         Settling  Parties reserve all rights to protest or take any position on
         any such filing.  Until April 1, 2002,  all  non-residential  customers
         with an annual maximum demand of 500 kW or more shall have the right to
         have advanced  metering  installed at their  facility.  The third party
         supplier or the customer will pay for any such meter and any associated
         telecommunication expense. The customer shall own any such meter unless
         the supplier and customer  agree  otherwise.  BGE will install any such
         meter at no cost on a one-time basis.  BGE shall maintain the meter per
         COMAR.  BGE shall  have  access to billing  data on a timely  basis and
         shall  provide  access  to such  billing  data  on a  timely  basis  to
         customers (or their designated supplier with prior customer approval.)

                                       X.

                            Miscellaneous Provisions
                            ------------------------

46.      BGE  shall  make  an  informational   filing  annually   regarding  its
         restructuring  costs  with the  Commission  and  provide  a copy to the
         Settling  Parties.  Restructuring  costs  are  costs,  liabilities,  or
         investments that arise as a result of electric  industry  restructuring
         and are related to the  creation of  customer  choice  pursuant to Code
         Section 7-501(P)(2).

47.      The rates set forth in this  Settlement  were agreed to by the Settling
         Parties in consideration of, among other things,  the factors set forth
         in Code  Section  7-505(D)(4)(II).  Upon  Commission  approval  without
         modification  or condition,


                                       38


         this Settlement  shall be deemed to be an alternative  price protection
         plan  and  settlement  that is  equally  protective  of  ratepayers  in
         accordance with Code Sections 7-505(D)(3) and (D)(5).

48.      BGE shall request and obtain Commission  approval prior to establishing
         any new regulatory  assets.  The Settling Parties reserve all rights to
         protest or take any other position on any such filing.

49.      The Settling  Parties agree that BGE shall not change its  depreciation
         rates  prior to its next  electric  rate  case.  The  Settling  Parties
         reserve  all rights to protest or take any other  position  on any such
         filing.

50.      Whenever  any rate  schedule  is  referred  to in this  Settlement,  it
         includes that schedule and any successor rate schedule.

51.      The  Settling   Parties  agree  that  the  market  power   adjudicatory
         proceeding  established  by Order  No.  74561  in Case No.  8738 is not
         needed at this time. However,  nothing in this Settlement precludes any
         party from  filing a  complaint  with the  Commission  with  respect to
         market power.  Furthermore,  nothing in this Settlement shall limit the
         rights or  remedies  provided  in Code  Section  7-514 or the rights or
         remedies that may exist under state or federal or common law.

                                       39


52.      Nothing in this  Settlement  shall  preclude  BGE from  filing with the
         Commission  for a  qualified  rate  order  or  taking  any  other  step
         necessary to  securitize  transition  costs to the extent  permitted by
         law.  Notwithstanding  Paragraph  3, if BGE  securitizes,  it agrees to
         return  75% of the  savings to  customers  by  reducing  the CTC (or as
         otherwise  determined  by the  Commission  if no CTC exists) which will
         have the  effect of  increasing  the  shopping  credit.  Securitization
         savings shall be  determined on a customer  class basis and the savings
         shall be allocated to those  customers  whose payment streams have been
         securitized. The Settling Parties reserve all rights to protest or take
         any  position  on any such  filing,  however,  BGE shall not propose to
         return less than 75% of the savings to customers.

53.      The various provisions of the Settlement are not severable. None of the
         provisions  shall  become  operative  unless  and until the  Commission
         issues  an order  approving  the  Settlement  without  modification  or
         condition. If any portion of this Settlement is modified,  conditioned,
         or rejected by the Commission,  the Settlement shall be considered null
         and void and each  Settling  Party  individually  reserves the right to
         proceed with the filing of testimony,  briefs and evidentiary  hearings
         as contemplated in the Commission's  orders in Case Nos. 8794 and 8804.
         If the  Settlement  is  rendered  null  and void by  operation  of this
         Paragraph,  the Settling  Parties agree to immediately  enter into good
         faith  negotiations  to reach a new  settlement.  If any  future law is
         enacted  which  any  Settling  Party  believes,  in good  faith,  has a
         material  impact on the  rights  and  obligations  arising  under  this


                                       40


         Settlement,  the Settling Parties shall meet to discuss what action, if
         any, should be taken.

54.      No party to this Settlement shall be deemed to have approved, accepted,
         agreed,  or  consented  to any  principle  underlying  or  supposed  to
         underlie any of the matters provided for in this Settlement,  nor shall
         it constitute in any respect a  determination  by the  Commission as to
         the merits of any of the contentions or allegations which might be made
         by any of the parties in the absence of settlement.

55.      The  discussions  that produced this  Settlement have been conducted on
         the  understanding  that  all  offers  of  settlement  and  discussions
         relating thereto are and shall be privileged and confidential, shall be
         without   prejudice  to  the  position  of  any  party  or  participant
         presenting any such offer or participating in any such discussions, and
         are not to be used in any manner in connection  with this proceeding or
         otherwise.  If the Commission does not approve this Settlement  without
         modification or





                                       41



         condition,  the  Settlement  shall be  deemed  withdrawn  and shall not
         constitute any part of the record in this proceeding or be used for any
         other purpose whatsoever.




                                       42




         IN WITNESS WHEREOF,  the Settling Parties respectfully request that the
Commission  approve this  Settlement  without  modification or condition and set
forth their respective signatures as of the 29th of June, 1999.

Baltimore Gas and Electric Company      Maryland Industrial Group and
                                        Millennium Inorganic Chemicals Inc.


By: __________________________________  By: __________________________________
Robert S. Fleishman                     Allan J. Malester
Vice President-Corporate Affairs and    Attorney for Maryland Industrial Group
General Counsel                         and Millennium Inorganic Chemicals Inc.
Baltimore Gas and Electric Company


Maryland Retailers Association          Building Owners and Managers Association
                                        of Metropolitan Baltimore, Inc.



By: __________________________________  By: __________________________________
Thomas C. Gorak                         Thomas C. Gorak
Attorney for Maryland Retailers         Attorney for Building Owners and
Association                             Managers Association of Metropolitan
                                        Baltimore, Inc.

Board of County Commissioners           The Power Plant Research Program of the
of Calvert County, Maryland             Maryland Department of Natural Resources



By: __________________________________  By: __________________________________
Terry L. Shannon                        M. Brent Hare
Director of Administration and Finance  Attorney for The Power Plant Research
                                        Program of the Maryland Department of
                                        Natural Resources
- -------------------------------------
Neal M. Janey
Counsel of Record for Calvert County



                                       43





Maryland Office of People's Counsel     Maryland Public Service Commission Staff



By: __________________________________  By: __________________________________
Michael J. Travieso                     Sarah R. Lazarus
Attorney for Maryland Office of         Attorney for Maryland Public Service
People's Counsel                        Commission Staff


Enron Energy Services, Inc              National Railroad Passenger Corporation



By: __________________________________  By:__________________________________
Lisa Yoho                               Marc D. Machlin
Director of Government Affairs          Attorney for National Railroad Passenger
Enron Energy Services, Inc.             Corporation



The Johns Hopkins University and        Department of Defense/Federal
The Johns Hopkins Health System         Executive Agencies
Corporation

By: __________________________________  By: __________________________________
Jill M. Barker                          David A. McCormick
Attorney for The Johns Hopkins          Attorney for Department of
University and The Johns Hopkins        Defense/Federal Executive Agencies
Health System Corporation

The Maryland Energy Administration


By:__________________________________
Frederick H. Hoover, Jr.
Director, Maryland Energy Administration



                                       44