-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Nez/WZsHjjog7yWxqDRt4ziN9aN0Pnu42wdPjWIkUuaKUyCxcs7/biXf41+o103f m5H5IVuiz+s/EHNZhZHKsw== 0001004440-99-000022.txt : 19990630 0001004440-99-000022.hdr.sgml : 19990630 ACCESSION NUMBER: 0001004440-99-000022 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19990629 ITEM INFORMATION: FILED AS OF DATE: 19990629 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CONSTELLATION ENERGY GROUP INC CENTRAL INDEX KEY: 0001004440 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 521964611 STATE OF INCORPORATION: MD FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 000-25931 FILM NUMBER: 99655630 BUSINESS ADDRESS: STREET 1: 39 WEST LEXINGTON ST CITY: BALTIMORE STATE: MD ZIP: 21201 BUSINESS PHONE: 4102345685 MAIL ADDRESS: STREET 1: 39 WEST LEXINGTON ST CITY: BALTIMORE STATE: MD ZIP: 21201 FORMER COMPANY: FORMER CONFORMED NAME: CONSTELLATION ENERGY CORP DATE OF NAME CHANGE: 19951220 FORMER COMPANY: FORMER CONFORMED NAME: RH ACQUISITION CORP DATE OF NAME CHANGE: 19951205 8-K 1 CURRENT REPORT 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. ------ ------------------------ ------------------ 1-12869 CONSTELLATION ENERGY GROUP, INC. 52-1964611 1-1910 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210 Maryland ----------------------------------- (State or other jurisdiction of incorporation for each registrant) 39 W. Lexington Street, Baltimore, Maryland 21201 --------------------------------------------------------------- ---------- (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) 1 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 2 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. --------------------------------------------- (Registrant) BALTIMORE GAS AND ELECTRIC COMPANY --------------------------------------------- (Registrant) Date: June 29, 1999 /s/ David A. Brune ---------------- -------------------------------------------- David A. Brune, Vice President on behalf of each Registrant and as Principal Financial Officer of each Registrant 3 EXHIBIT INDEX Exhibit Number Exhibit -------------- ------- 10 Stipulation and Settlement Agreement, without Appendices. 99 Letter to Investors and Analysts dated June 29, 1999. EX-10 2 STIPULATION AND SETTLEMENT AGREEMENT 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 EX-99 3 LETTER TO INVESTORS AND ANALYSTS 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. 1 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. 2 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. 3
Summary of Electric Customer CTC Options Distribution Generation Price Price Freeze Protection Annual Rate Customer Tariff CTC Period Period Period Cut - --------------- ---------- ------ ------ --- 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) 4 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
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