4
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): June 29, 1999
Commission File Exact name of registrant as IRS Employer
Number specified in its charter Identification No.
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1-12869 CONSTELLATION ENERGY GROUP, INC. 52-1964611
1-1910 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210
Maryland
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(State or other jurisdiction of incorporation for each registrant)
39 W. Lexington Street, Baltimore, Maryland 21201
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(Address of principal executive offices) (Zip Code)
Registrants' telephone number, including area code: (410) 234-5000
Not Applicable
(Former name or former address, if changed since last report)
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Item 5. Other Events
As previously reported in our Quarterly Report on Form 10-Q for the quarter
ended March 31, 1999 (the "Form 10-Q"), we reached a tentative agreement in
principle with a majority of the active parties on the major issues in the
electric restructuring proceedings discussed in the Form 10-Q. As a result, the
Maryland Public Service Commission (Maryland PSC) suspended the procedural
schedule and instructed the settling parties to file a settlement agreement by
June 15, 1999. On June 11, 1999, the Maryland PSC granted the parties a 10-day
extension for filing the settlement agreement.
On June 29, 1999, the parties filed a Stipulation and Settlement Agreement
with the Maryland PSC signed by the settling parties ("Settlement Agreement").
Attached to this Current Report on Form 8-K is the Settlement Agreement without
Appendices (Exhibit 10) and a letter to Analysts from Constellation Energy Group
that discusses key provisions of the Agreement (Exhibit 99).
The next step is for the Maryland PSC to determine what type of proceedings
are necessary to render a decision regarding whether the settlement is in the
public interest. We expect that the Maryland PSC will issue a final order by
October 1, 1999.
When sufficient details of the transition plan ultimately approved by the
Maryland PSC become known, the generation portion of BGE's electric business
will no longer meet the provisions of SFAS No. 71. At that time, we would
implement SFAS No. 101, "Regulated Enterprises - Accounting for the
Discontinuation of FASB Statement No. 71."
A provision under SFAS No. 101 requires an evaluation of potential
impairments of plant assets under SFAS No. 121, Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets To Be Disposed Of. If any of our
generating plant assets are impaired under the provisions of SFAS No. 121, BGE
would be required to record a write-down. The amount of any such write-down
could materially affect BGE's financial position and results of operations.
However, we cannot estimate the amount of the potential impairment loss, if any,
at this time. We cannot predict what decision the Maryland PSC will ultimately
reach on the terms of the settlement agreement or the impact that decision will
have on BGE's financial position and results of operations, but such impact
could be material.
We make statements in this report that are considered forward looking
statements within the meaning of the Securities Act of 1933 and the Securities
Exchange Act of 1934. These statements are related to the effects of the
proposed deregulation settlement on Constellation Energy Group's and BGE's
future operating results. Sometimes these statements will contain words such as
"believes," "expects," "intends," "plans," and other similar words. These
statements are not guarantees of our future performance and are subject to
risks, uncertainties and other important
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factors that could cause our actual performance or achievements to be materially
different from those we project. These risks, uncertainties and factors include,
but are not limited to: general economic, business, and regulatory conditions;
energy supply and demand; competition; federal and state regulations;
availability, terms, and use of capital; nuclear and environmental issues;
weather; industry restructuring and cost recovery (including the potential
effect of stranded investments); commodity price risk; and year 2000 readiness.
Given these uncertainties, you should not place undue reliance on these
forward looking statements. Please see our other periodic reports filed with the
SEC for more information on these factors. These forward looking statements
represent our estimates and assumptions only as of the date of this report.
Item 7. Exhibits
See Exhibit Index.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each
registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
CONSTELLATION ENERGY GROUP, INC.
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(Registrant)
BALTIMORE GAS AND ELECTRIC COMPANY
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(Registrant)
Date: June 29, 1999 /s/ David A. Brune
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David A. Brune, Vice President on behalf of
each Registrant and as Principal Financial
Officer of each Registrant
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EXHIBIT INDEX
Exhibit Number Exhibit
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10 Stipulation and Settlement Agreement, without Appendices.
99 Letter to Investors and Analysts dated June 29, 1999.
EXHIBIT NO. 10
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BEFORE THE
PUBLIC SERVICE COMMISSION
OF MARYLAND
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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:
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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;
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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
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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
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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
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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,
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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
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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
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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
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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
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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
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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
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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
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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
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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
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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.
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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
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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,
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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
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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
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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.
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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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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.
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<PAGE>
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
<PAGE>
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
<PAGE>
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
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<PAGE>
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
<PAGE>
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.
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<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
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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
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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.
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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
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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
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EXHIBIT NO. 99
--------------
June 29, 1999
To Investors and Analysts:
On June 29, 1999, Baltimore Gas and Electric Company (BGE) and other interested
parties filed a comprehensive deregulation settlement document with the Maryland
Public Service Commission (PSC). The settlement agreement settles two cases
currently before the Public Service Commission - a petition by the Office of
People's Counsel to reduce BGE's electric rates by up to $141.7 million annually
effective July 1, 1999 and a comprehensive electric industry restructuring
proceeding that deals with transition costs, customer price protections and
unbundled rates for electric services.
Under the settlement, all Maryland electric customers (residential, commercial
and industrial) will be able to shop for electricity beginning July 1, 2000.
This accelerates the legislative timetable for customer choice. Under Maryland's
restructuring legislation, one-third of residential customers would be eligible
to choose alternate suppliers beginning July 1, 2000, with incremental one-third
blocks of residential customers on July 1, 2001 and July 1, 2002. Commercial and
industrial customers are able to choose alternate suppliers six months earlier
than the January 1, 2001 date contained in the legislation. Customers may choose
to buy their electric energy from BGE under a standard offer service or from
another supplier. In either case, BGE will continue to deliver the energy to all
customers within its existing service territory.
This settlement, which requires PSC approval, also provides:
o There will be no adjustment to electric rates at the present time.
o BGE will accelerate depreciation on its generation assets by $150
million (pre-tax) during the period July 1, 1999 - June 30, 2000 in
order to mitigate a portion of its potentially stranded costs.
o Starting on July 1, 2000, BGE will unbundle rates to show separate
components for delivery service, transition charges, standard offer
service (generation), transmission, universal service and taxes.
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o Residential customers' base rates will be cut by approximately $54
million on July 1, 2000, and residential rates will be frozen at these
levels for a period of six years (through June 30, 2006).
o While commercial and industrial rates will not be reduced, these
customers will have up to four service options which fix the electric
rates and transition charges for a period that generally ranges from
four to six years. Electric delivery service rates for commercial and
industrial customers will be frozen for a four-year period (through
June 30, 2004).
o BGE will be allowed to recover $528 million of its potentially
stranded costs through a competitive transition charge (CTC). This
amount represents a final determination of all stranded cost claims
related to its generation assets. BGE had requested recovery of $897
million. BGE has agreed to apply 75% of any future savings associated
with securitization to reduce the CTCs paid by its customers.
o Generation related regulatory assets and nuclear decommissioning costs
will be included in delivery service rates effective July 1, 2000 and
will be recovered under existing amortization schedules.
o On July 1, 2000, BGE will transfer, at book value, its 10
Maryland-based fossil and nuclear power plants and its partial
ownership interest in two coal plants and a hydroelectric plant in
Pennsylvania to an unregulated subsidiary of Constellation Energy
Group, BGE's parent company. Constellation Energy shall retain or
absorb 100% of any revenues or gains and losses associated with the
operation, transfer or subsequent sale of these generation assets.
This agreement settles the major issues related to deregulation, moving BGE and
Constellation Energy one step closer to competing in a deregulated electric
marketplace.
The settlement agreement includes Baltimore Gas and Electric Company and the
following parties: the Building Owners and Managers Association of Metropolitan
Baltimore, Inc., Board of County Commissioners of Calvert County, Maryland,
Department of Defense/Federal Executive Agencies, Enron Energy Services, Inc.,
The Johns Hopkins University and The Johns Hopkins Health System Corporation,
Maryland Energy Administration, Maryland Industrial Group and Millennium
Inorganic Chemicals Inc., Maryland Office of People's Counsel, Maryland
Retailers Association, National Railroad Passenger Corporation, Power Plant
Research Program of the Maryland Department of Natural Resources, and the
Maryland Public Service Commission Staff.
BGE expects to have a final decision on the proposed settlement no later than
October 1, 1999.
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Attached to this letter are summaries of the electric customer CTC options and
the electric CTC rates and Standard Offer Service (SOS) prices.
Please direct any inquiries to:
Kevin J. Miller David A. Brune
Manager - Financial Planning Vice President - Finance & Accounting,
Constellation Energy Group Chief Financial Officer and Secretary
410-234-5434 Constellation Energy Group
410-234-5511
We make statements in this letter that are considered forward-looking
statements within the meaning of the Securities Act of 1933 and the Securities
Exchange Act of 1934. These statements are related to the effects of the
proposed deregulation settlement on Constellation Energy Group's future
operating results.
Sometimes these statements contain words such as "believes," "expects,"
"intends," "plans," and other similar words . These statements are not
guarantees of our future performance and are subject to risks, uncertainties,
and other important factors that could cause our actual performance or
achievements to be materially different from those projected.
These risks, uncertainties and factors include, but are not limited to:
general economic, business, and regulatory conditions; energy supply and demand;
competition; federal and state regulations; availability, terms, and use of
capital; nuclear and environmental issues; weather; industry restructuring and
cost recovery (including the potential effect of stranded costs); commodity
price risk; and year 2000 readiness. Given these uncertainties, you should not
place undue reliance on these forward-looking statements.
Please see our filings with the Securities and Exchange Commission for
more information on these factors . These forward-looking statements represent
our estimates and assumptions only as of the date of this letter and we
undertake no duty to update any forward-looking statement to reflect the
occurrence of unanticipated events.
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<TABLE>
<CAPTION>
Summary of Electric Customer CTC Options
Distribution Generation Price
Price Freeze Protection Annual Rate
Customer Tariff CTC Period Period Period Cut
- --------------- ---------- ------ ------ ---
<S> <C> <C> <C> <C>
Residential 6 years 6 years 6 years $53.8M
(1998 Sales-11.0 million MWH)
Commercial & Industrial:
G/GS - <60kW demand:
(1998 Sales-2.9 million MWH)
Option 1 6 years 4 years 4 years None
Option 2 5 years 4 years 4 years None
GL - demand of 60kW or more:
(1998 Sales-6.3 million MWH)
Option 1 4 years 4 years None None
Option 2 5 years 4 years 4 years None
Option 3 5 years 4 years None None
(declining)
P - primary voltage - demand of 1,500 kW or more:
(1998 Sales-6.4 million MWH)
Option 1 4 years 4 years None None
Option 2 5 years 4 years 1 year None
Option 3 6 years 4 years 2 years None
Option 4 5 years 4 years None None
(declining)
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Summary of Electric Customer CTCs and
Standard Offer Service Rates (Shopping Credits) by Option
Initial Initial SOS
Customer CTC Subsequent Price Subsequent
Tariff (cents/kWh) Trend (cents/kWh) Trend
- ------ ----------- ----- ----------- -----
Residential:
R .800 Declining - 6 years 4.224 Increasing - 6 years
RL .800 Declining - 6 years 3.732 Increasing - 6 years
(Time of Use)
Commercial & Industrial:
G:
Option 1 .576 Flat - 6 years 4.766 Flat - 4 years
Option 2 .674 Flat - 5 years 4.668 Flat - 4 years
GS:
Option 1 .576 Flat - 6 years 4.478 Flat - 4 years
Option 2 .674 Flat - 5 years 4.380 Flat - 4 years
GL Secondary:
Option 1 .805 Flat - 4 years N/A N/A
Option 2 .661 Flat - 5 years 4.401 Flat - 4 years
Option 3 1.500 Declining - 5 years N/A N/A
GL Primary:
Option 1 .805 Flat - 4 years N/A N/A
Option 2 .661 Flat - 5 years 3.976 Flat - 4 years
Option 3 1.500 Declining - 5 years N/A N/A
P:
Option 1 .742 Flat - 4 years N/A N/A
Option 2 .610 Flat - 5 years 3.828 Flat - 1 year
Option 3 .522 Flat - 6 years 3.916 Flat - 2 years
Option 4 1.400 Declining - 5 years N/A N/A
</TABLE>
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