-----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, DMriqrCAH2O/lWyU52vpJ9b2+MVj0y9xQT52fkGBmQ6nyd+Uk+dw+ZWNFfbypDio 1673vvFeWGC9YWg2vix0wA== 0000893220-99-000830.txt : 19990723 0000893220-99-000830.hdr.sgml : 19990723 ACCESSION NUMBER: 0000893220-99-000830 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19990715 ITEM INFORMATION: ITEM INFORMATION: FILED AS OF DATE: 19990722 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CONECTIV INC CENTRAL INDEX KEY: 0001029590 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 510377417 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 001-13895 FILM NUMBER: 99668517 BUSINESS ADDRESS: STREET 1: 800 KING STREET P O BOX 231 CITY: WILMINGTON STATE: DE ZIP: 19899 BUSINESS PHONE: 3024293114 MAIL ADDRESS: STREET 1: 800 KING ST STREET 2: P O BOX 231 CITY: WILMINGTON STATE: DE ZIP: 19899 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ATLANTIC CITY ELECTRIC CO CENTRAL INDEX KEY: 0000008192 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 210398280 STATE OF INCORPORATION: NJ FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 001-03559 FILM NUMBER: 99668518 BUSINESS ADDRESS: STREET 1: 800 KING STREET STREET 2: PO BOX 231 CITY: WILMINGTON STATE: DE ZIP: 19899 BUSINESS PHONE: 6096454100 MAIL ADDRESS: STREET 1: 800 KING STREET STREET 2: PO BOX 231 CITY: WILMINGTON STATE: DE ZIP: 19899 8-K 1 8-K REPORT DATED 7/15/1999 1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 8-K CURRENT REPORT PURSUANT TO SECTIONS 13 OR 15(D) OF THE SECURITIES AND EXCHANGE ACT OF 1934 Date of Report (Date of earliest event reported): July 15, 1999
Commission Registrant, State of Incorporation I.R. S. Employer File Number Address and Telephone Number Identification Number - ----------- ---------------------------- --------------------- 1-13895 Conectiv (a Delaware Corporation) 51-0377417 800 King Street P.O. Box 231 Wilmington, Delaware 19899 Telephone (302) 429-3114 1-3559 Atlantic City Electric Company 21-0398280 (a New Jersey Corporation) 800 King Street P.O. Box 231 Wilmington, Delaware 19899 Telephone (302) 429-3114
2 Item 5. OTHER EVENTS On June 9, 1999, Conectiv's subsidiary, Atlantic City Electric Company ("Company"), entered into a Stipulation of Settlement ("Stipulation") with some of the parties to the Company's stranded costs, unbundled rates, and restructuring proceedings pending before the New Jersey Board of Public Utilities ("NJBPU") and filed the Stipulation with NJBPU. On July 15, 1999, the NJBPU approved, with modifications, the Company's Stipulation and issued a summary order ("Summary Order") detailing the modifications to the original Stipulation. The NJBPU stated that a more detailed order would be issued at a later date. In its Summary Order, the NJBPU directed the Company to implement a five percent aggregate rate reduction effective August 1, 1999. As part of the initial five percent aggregate rate reduction, the NJBPU set the Company's system average distribution rate at 2.1384 cents per kwh. The Company also must implement at least an additional two percent rate reduction by January 1, 2001, and by August 1, 2002 an additional rate reduction such that rates are reduced a total of ten percent, as compared to rates in effect as of April 30, 1997. The Company estimates that the initial rate reduction will result in about a $50 million reduction in revenues. However, the ultimate impact on the net income of the Company will depend upon the nature and extent of cost reductions that may be realized by the Company. The NJBPU Summary Order also established minimum initial shopping credits for customers who choose an alternative electric supplier, from a system average 5.27 cents per kilowatt hour, effective August 1, 1999, to a system average of 5.48 cents per kilowatt hour in 2003. These shopping credits, based on the charges for power supply and transmission, include charges by the Company for Basic Generation Service ("BGS") to be provided retail customers who do not have a competitive electric power supplier. The NJBPU Summary Order also approved the deferral mechanism contained in the Company's Stipulation, in order to enable the Company to meet and sustain the rate reductions ordered by the NJBPU. The deferral mechanism provides for the accumulated deferral of costs and application of certain over-recovery credits, for ultimate recovery of the resultant net deferred balance, during the four years after the initial four-year transition period ("Transition Period") commencing August 1, 1999. The NJBPU approved certain rates of return to be applied to the deferred balances. Also under the Stipulation, the Company will divest itself of its nuclear and fossil fuel baseload units and transfer the remaining generating units to a non-utility affiliated company at the net book value. As a condition to the transfer and for the duration of the Transition Period, the NJBPU Summary Order requires that if any transferred asset is sold to an unaffiliated company, the net after-tax gain over the adjusted book value would be shared equally between the Company and customers. The NJBPU Summary Order concurred with the Stipulation that the Company shall be permitted the opportunity to recover 100% of the net stranded costs related to the generation units to be divested. The Summary Order further concurred with the Stipulation that the Company may also 2 3 recover 100% of the stranded costs associated with power purchased from Non-Utility Generators ("NUG's"). The NJBPU Summary Order also provided for the securitization of amounts used to effect potential buyouts or buydowns of contracts with NUG's as well as limited incentives for the Company in the event of such contract restructuring. The NJBPU Summary Order does not provide for recovery of stranded costs associated with the Company's transfer of generating units to a non-utility affiliated company. As previously reported in the Company's 1999 first quarter Form 10-Q, the Company expects during 1999 an extraordinary charge to earnings of approximately $50 million to $75 million as a result of this transfer. Conectiv's related news release, the NJBPU Summary Order and Atlantic City Electric Company's Stipulation of Settlement are annexed as exhibits. Item 7. FINANCIAL STATEMENTS PRO FORMA FINANCIAL INFORMATION AND EXHIBITS (c) Exhibits 1. Conectiv News Release, dated July 15, 1999 2. NJBPU Summary Order, dated July 15, 1999 3. Atlantic City Electric Company Stipulation of Settlement as filed with the NJBPU, dated June 9, 1999 3 4 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. CONECTIV Atlantic City Electric Company Date: July 22, 1999 /s/Philip M. Reese Treasurer 5 EXHIBITS TO BE FILED BY EDGAR (c) Exhibits 1. Conectiv News Release, dated July 15, 1999 2. NJBPU Summary Order, dated July 15, 1999 3. Atlantic City Electric Company Stipulation of Settlement as filed with the NJBPU, dated June 9, 1999 EX-99.C1 2 CONNECTIV NEWS RELEASE DATED JULY 15 1999 1 EXHIBIT C-1 [CONECTIV LOGO] For immediate release July 15, 1999 For more information, call Betty Kennedy (609) 625-5567 CONECTIV RESTRUCTURING DECISION ANNOUNCED Mays Landing, N.J. - Conectiv Executive Vice President Tom Shaw said the decision made today by the Board of Public Utilities regarding the company's restructuring proposal benefits New Jersey customers with rate reductions beginning Aug. 1 and sets the stage for real competition to develop. "The announced Board ruling appears to balance the interests of our customers, shareholders and employees," said Shaw. "We realize that the mandated rate reductions and increase in the shopping credit allowance are a part of the series of challenges that our company must meet as our industry becomes fully competitive." "We believe the ruling gives us the framework to successfully meet those challenges," he added. The BPU decision includes a revamping of Conectiv's 10-percent rate reduction and an increase in the residential shopping credits. Both were previously negotiated with groups representing the interests of New Jersey business consumers, non-regulated generators and retail power suppliers. (more) 2 Page 2 /Conectiv Restructuring Decision Announced The Board mandated an initial 5-percent rate reduction effective August 1, at least an additional 2-percent rate reduction by Jan. 1, 2001, and 3 percent by August 1, 2002, totaling 10 percent within three years. The rate reductions must be sustained through July 31, 2003. Combined with the gross receipts and franchise tax reduction, customer rates will be reduced by approximately 15 percent within four years. It is estimated the initial rate reduction will result in about a $50 million reduction in revenues. "With this Board decision, the path of the electric utility industry restructuring is clearer. This clarity should help Conectiv go forward to implement its overall business strategy. We believe the successful implementation of that strategy and the continued effort of our management and workforce to look for ways to cut costs and increase productivity should enable us to overcome the loss of revenue," Shaw said. "We are committed to providing our customers these significant savings, while maintaining safe, reliable, quality service," he added. The BPU established shopping credits higher than those proposed in the settlement. The BPU ruling establishes average shopping credit "floors" of 5.27 cents per kilowatt hour effective Aug. 1, 1999, 5.31 cents in 2000, 5.37 cents in 2001, 5.42 in 2002 and 5.48 in 2003. These shopping credits will be the highest in New Jersey; in addition they may increase based on the market price of energy. "While customers will be able to shop for their energy suppliers, Conectiv will continue to deliver that energy, maintain the wires and poles, and provide emergency service," said Shaw. (more) 3 Page 3 /Conectiv Restructuring Decision Announced The ruling allows Conectiv to fully recover approximately $800 million of stranded costs associated with the non-utility generation contracts. Conectiv announced in May that it would divest its base-load generating facilities. The stranded cost associated with the generation stations to be sold, previously estimated to be about $400 million, will be determined through the sale and also will be fully recoverable. The company will transfer its remaining New Jersey generation to an unregulated subsidiary, and if those facilities are sold within the four-year transition period, net gains will be shared by customers and shareholders. In addition, the Board's decision supports full securitization of stranded costs associated with restructuring or buyout of non-utility generating contracts and the divested generation. Conectiv, formed through the merger involving Atlantic Energy, Inc. and Delmarva Power & Light Company, is the parent company for Conectiv Power Delivery, a regulated energy provider that provides electric service to almost 1 million customers, including 480,000 in southern New Jersey. FORWARD-LOOKING STATEMENTS The Private Securities Litigation Reform Act of 1995 (the "Litigation Reform Act") provides a "safe harbor" for forward-looking statements to encourage such disclosures without the threat of litigation, provided those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Forward-looking statements have been made in this Press Release. Such statements are based on beliefs of Conectiv's (the "Company's") management ("Management") as well as assumptions made by and information currently available to Management. When used herein, the words "will," "anticipate," "estimate," "expect," "objective," and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following: (more) 4 Page 4/ Conectiv Restructuring Decision Announced deregulation of energy supply and telecommunications; the unbundling of delivery services; and increasingly competitive energy and telecommunications marketplace; results of any asset dispositions; sales retention and growth; federal and state regulatory actions; future litigation results; cost of construction; operating restrictions; increased costs and construction delays attributable to environmental regulations; nuclear decommissioning and the availability of reprocessing and storage facilities for spent nuclear fuel; and credit market concerns. The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing list of factors pursuant to the Litigation Reform Act should not be construed as exhaustive or as admission regarding the adequacy of disclosures made prior to the effective date of the Litigation Reform Act. www.conectiv.com ### EX-99.C2 3 NJBPU SUMMARY ORDER DATED JULY 15 1999 1 EXHIBIT C-2 AGENDA DATE: 07/15/99 STATE OF NEW JERSEY BOARD OF PUBLIC UTILITIES TWO GATEWAY CENTER NEWARK NJ 07102 ENERGY IN THE MATTER OF ATLANTIC CITY ) SUMMARY ORDER ELECTRIC COMPANY'S RATE ) UNBUNDLING, STRANDED COSTS AND ) BPU DOCKET NOS. E097070455, RESTRUCTURING FILINGS ) EO97070456, AND EO97070457 (SERVICE LIST ATTACHED) BY THE BOARD: This Summary Order memorializes in summary fashion the action taken by the Board of Public Utilities ("Board") in these matters at its specially- scheduled July 15, 1999 public agenda meeting with respect to the rate unbundling, stranded costs and restructuring filings of Atlantic City Electric Company ("ACE", "Atlantic" or "Company"). The Board will issue a more detailed Decision and Order in these matters, which will provide a full discussion of the issues as well as the reasoning for the Board's determinations. These matters come before the Board on a record developed by Administrative Law Judge ("ALJ") William Gural, who issued an Initial Decision on August 17, 1998, and hearings conducted before Commissioner Carmen J. Armenti from April 27, 1998 through May 28, 1998. Subsequent to the ALJ's Initial Decision and the hearings before Commissioner Armenti, the Legislature passed and Governor Whitman signed into law on February 9, 1999, the Electric Discount and Energy Competition Act, P.L. 1999, c. 23 ("the Act"). Settlement negotiations were conducted among the parties during the latter part of April, through the early part of June 1999. A comprehensive settlement was not reached, but on June 9, 1999, a Stipulation was filed by ACE on behalf of a number of parties to the proceedings ("ACE Stipulation"). The Board determined to solicit and consider comments on the ACE Stipulation, and established a comment deadline of June 16, 1999 for comments addressing the ACE Stipulation, including any alternative settlement proposal(s), and a deadline of June 18, 1999 for comments addressing any alternative settlement proposal(s). On June 16, 1999 an alternative joint proposal was submitted by the Division of the Ratepayer Advocate on behalf of a number of other parties to these proceedings ("RPA Stipulation"). Based on our review of the extensive record in these proceedings, as well as the comments submitted, the Board is not fully satisfied that either proposal in its entirety represents an appropriate resolution of these proceedings. The Board finds the ACE 2 Stipulation to be overall more financially prudent and consistent with the Act's requirements and, with the modifications and clarifications set forth hereinbelow, provides the framework for a reasonable resolution of these matters based upon the record before us. However, the proponents of the RPA Stipulation and others have raised a number of legitimate concerns regarding the ACE Stipulation which merit serious consideration and which, where appropriate, are addressed by the modifications and clarifications set forth below. Accordingly, except as specifically noted below, and as will be further explained in a detailed order which shall be issued, we hereby incorporate by reference as if completely set forth herein as a fair resolution of the issues in these proceedings, the elements of the ACE Stipulation and, to the extent the Initial Decision is inconsistent herewith, it is modified to conform herewith. The modifications and clarifications to the ACE Stipulation which we HEREBY ORDER are summarized as follows: Paragraph 1: The initial aggregate rate reduction, inclusive of all unbundled rate components, to be implemented effective August 1, 1999 shall be 5% from current rates. The average distribution rate for the Company effective on August 1, 1999 shall be 2.1384 cents per kwh. The MTC shall be set as the residual amount necessary to achieve the rate reduction, after accounting for other unbundled rate components established pursuant to this Order, including the distribution rate, regulatory asset charge, state energy taxes including sales and use tax, corporate business tax and TEFA, societal benefits charge, NNC, and BGS charge. The DSM and LEAC overrecovery balances, including accrued interest, shall not be utilized to offset regulatory asset charges but shall instead be credited to, and become the starting balance of, the deferred balance established pursuant to paragraph 27. Effective no later than January 1, 2001 the Company shall implement a further aggregate rate reduction of at least 2% relative to current rates (bringing the total rate reduction to at least 7%). However, to the extent that the Company completes the divestiture of generating assets and securitization of net owned generation stranded costs, or successfully completes a NUG contract(s) restructuring, buyout or buydown and securitization of net NUG stranded costs prior to January 1, 2001, it shall implement a rate reduction reflecting the full resultant savings no later than the date of the establishment of the resultant TBC. To the extent that such savings result in the implementation of a further rate reduction of less than 2%, Atlantic shall in any event reduce rates effective January 1, 2001 to achieve the 7% total rate reduction as of that date. To the extent that the savings resulting from divestiture and securitization of net owned generation stranded costs, and/or NUG restructuring buyout or buydown and DOCKET NOS. EO97070455, EO97070456, EO97070457 2 3 securitization exceeds 2%, Atlantic shall implement a rate reduction beyond 7% to fully pass such savings on to customers, upon the date of the establishment of the resultant TBC. To the extent that the sum of the unbundled rate components as of July 31, 2002 exceeds the price cap resulting from the implementation of a 10% aggregate rate reduction relative to April 30, 1997 rates, which unbundled rate components are to reflect any savings which have resulted from the buyout, buydown, or restructuring and securitization of NUG contracts implemented pursuant to paragraph 1(c) of the Stipulation, the Company shall, consistent with the provisions of the Stipulation, achieve effective August 1, 2002 the mandated 10% aggregate rate reduction relative to April 30, 1997 rates. Paragraph 2: The initial 5% (August 1, 1999) and final 10% (August 1, 2002) rate reductions are required by the Act, and shall not be contingent upon divestiture and securitization of generation assets. Paragraphs 5 and 6: The floor residential service ("RS") shopping credits shall be increased by 0.50 cents per kwh for 1999 and 2000, and by 0.55 cents per kwh in 2001, 2002 and 2003. The floor shopping credits for commercial and industrial Secondary and Primary voltage tariff customers (MGS-Sec, MGS-Pri, AGS-Sec, AGS-Pri, AGT-Sec, AGT-Pri) shall be decreased in all years by 0.1 cents per kwh. Paragraph 7: Atlantic shall apply both NUG contract power and to-be-divested owned generation power (prior to the closure of the sale of the generation assets) towards the BGS supply requirement, which power shall be credited at the net BGS price (the floor shopping credit less transmission cost, sales and use tax, line losses, ancillary services and capacity reserve margin). Such credited prices shall be employed for purposes of establishing the level of the NNC and establishing the level of owned generation revenue requirement recovery (prior to the completion of divestiture), in accordance with this Order. Atlantic shall utilize and open competitive bidding process for BGS supply requirements net of NUG Power and Owned Generation (Pre-Divesture). Paragraph 8: The 12 month minimum BGS commitments requirement for customers returning to BGS supply shall not apply to residential customers who return to BGS for any reason. However, the Board will monitor this issue and request related reports from the Company, and may revisit this issue if gaming occurs, or if it is otherwise determined by the Board to be appropriate. DOCKET NOS. EO97070455, EO97070456, EO97070457 3 4 Paragraph 9: Modified in accordance with modifications to paragraph 7. Paragraph 11: We hereby clarify the language to indicate that the Board is not pre-judging the reasonableness and prudence of the actual parting contracts or financial instruments that the Company may procure in accordance with this paragraph, and that any such costs are subject to Board review and approval. Paragraph 12: We hereby modify the language as necessary to conform with the modifications to paragraph 7, and further clarify that Atlantic shall reserve the right to bid out the BGS obligation net of NUG power or to sell NUG power to the selected BGS supplier at the net BGS price. Paragraph 16: The Board concurs that the Company shall be permitted the opportunity to recover 100% of its net owned generation stranded costs (established definitively upon completion of the divsetiture) and NUG contract costs, however we modify the language only so far as is necessary to conform with the differing standards for recovery of net generation stranded costs and 100% recovery of NUG stranded costs provided in section 13 of the Act. Paragraph 17: We hereby clarify the language to indicate that the net book value shall reflect the net investment in each facility, reflective of the gross investment less depreciation reserve less accumulated deferred income tax, and investment tax credits if appropriate, as of the closing date(s), and to clarify that the tax impacts with respect to taxable gains and/or losses will be considered in calculating net stranded cost. Paragraph 18: We hereby modify the language to indicate that while the Board supports the Company's decision to auction its generation assets, we are not pre-judging the prudence of Atlantic in implementing the RFP and selecting a winner bidder(s), and that such final judgement will come at the conclusion of the separate divestiture proceeding. Paragraph 19: The Board recognizes the benefit of expediting its review and approval of divestiture standards, and will endeavor to accomplish same, but modifies the language to indicate that we cannot be bound at this time by a specific timetable. DOCKET NOS. EO97070455, EO97070456, EO97070457 4 5 Paragraph 20: The Board recognizes that parting contracts that make possible or enhance the sale of generating assets can be in the public interest, but clarify the language as necessary to indicate that the Board is not pre-judging prudence of actual parting contracts which may be entered into by Atlantic; such judgement will be rendered after Board review in the context of the separate divestiture proceeding. Paragraph 21: The transfer of Deepwater and the combustion turbines shall occur at a transfer value equal to the net book value of the assets at the time of the transfer. This amount is approximately $9 million higher than that provided in the Stipulation, is intended to reflect full and fair compensation for the assets, and will avert the need for Atlantic to take a write-off prior to the transfer. We further modify this paragraph such that if within the four year Transition Period any transferred asset is sold to an unaffiliated company, the net after tax gain over the adjusted book value will be shared equally between the Company and customers. Further, as a condition of the transfer during the transition period, Atlantic's affiliate shall offer capacity from the transferred units for sale within the PJM control area at market prices, and if the capacity is sold outside the PJM control area, the Company's affiliate shall make the capacity subject to recall by PJM during system emergencies. Paragraph 22: During the period between August 1, 1999 and completion of the divestiture of generation assets, MTC revenues shall be applied to owned generation revenue requirements, including continued depreciation of assets, and return on investment, operating and maintenance expenses and fuel expenses, and, between the time of divestiture closing and time of securitization closing, MTC revenues shall be applied to provide a return on the net owned generation stranded cost at 13.0% pre-tax. At time of the termination of the MTC (upon the establishment of the TBC), total MTC revenues and market revenues received from the crediting of owned generation power to BGS in accordance with paragraph 7 (as modified) will be reconciled to the amounts indicated, including a review of the prudence and reasonableness of the Company's operation of the units, and the deferred balance will be reconciled accordingly to reflect a resulting shortfall or excess. Paragraph 23: We modify the language to provide that, during the Transition Period, Atlantic will only retain a portion of savings from NUG contract buyouts, buydowns or restructurings once the 10% aggregate rate reduction relative to April 30, 1997 rates is achieved without the use of cost deferrals. We further clarify the language to indicate that NUG securitization approval is DOCKET NOS. EO97070455, EO97070456, EO97070457 5 6 contingent upon such NUG contract buyout, buydown or restructuring being approved by the Board and found to be consistent with the standards in sections 13 and 14 of the Act. Paragraph 24: The Board renders no determination at this time with respect to the securitization of restructuring-related costs of capital. The recovery of restructuring-related costs of a capital nature via the MTC shall be subject to a reasonableness and verification review by the Board, and shall be net of other sources of recovery towards such costs, including Third Party Supplier Agreement fees. The rate of return on unamortized restructuring-related costs collected via the MTC shall be 13.0% pre-tax. Paragraph 25: The recovery of restructuring-related costs of an operating nature other than consumer education costs, as listed in Schedule D, via the MTC shall be subject to reasonableness and verification review by the Board, and shall be net of other sources of recovery towards such costs, including Third Party Supplier Agreement fees. Paragraph 26: This is not appropriate language for a Board Order. AE may reserve all its legal rights, however the Board rejects this paragraph. Paragraphs 27, 28 and 29: The Board hereby modifies this paragraph to change references from "Deferred Revenues" to "Deferred Costs," and to provide, with respect to the rate of return on the Deferred Costs balance, that on any accrued underrecovery balance up to $50 million, interest will be accrued at a rate equal to the then-current cost of medium term debt. On any accrued deferred underrecovery balance amounts in excess of $50 million, such excess amounts shall accrue interest at a rate equal to the then-current cost of mid-term debt plus 350 basis points. The Board further modifies the language to indicate that, while the Company shall be provided the opportunity to fully recover Deferred Costs and related interest in accordance with the provisions of the Stipulation, as modified herein and consistent with the Act, the Board will not bestow on Atlantic an "absolute right" to such recovery. Finally, we hereby clarify the language to indicate that final approval of recoverability of the Deferred Cost balance is subject to Board review of the prudence and reasonableness of such costs. Paragraph 30: The Board hereby clarifies the language to indicate that the Company shall be provided with full and timely recovery of transition bond charges in conformance with the standards set forth in sections 14 through 27 of the Act, and that the Company shall be provided the opportunity for full DOCKET NOS. EO97070455, EO97070456, EO97070457 6 7 recovery of related and applicable taxes via a separate MTC charge with a term identical to the securitization financing pursuant to the standards set forth in sections 13 and 14 of the Act. Paragraph 31: With respect to the securitization of net NUG stranded costs related to a contract restructuring, buyout or buydown, we hereby clarify the language to conform with the clarifications rendered in paragraph 23. Paragraph 32: The Board will render no determination at this time with respect to the securitization of restructuring-related costs of capital. Paragraph 36: We hereby clarify the language to indicate that imputation of tax expenses or tax benefits on a utility stand-alone basis is for ratemaking purposes as it applies to the computation of divestiture proceeds, MTC revenues, divestiture and NUG buyouts as a result of these matters only, and that such treatment has no precedential value with regard to future rate cases pertaining to the regulated rates of Atlantic. Paragaph 38: While we recognize the desire for and potential benefit of expeditious review and approval of NUG contract restructuring, buyout or buydown proposals, and will make every effort to accomplish same, the Board cannot be bound at this time to a specific timetable. Paragraph 43: We clarify the language to indicate that recovery via the MTC of expenses to redeem or retire outstanding capital in connection with the recovery of stranded costs is subject to Board review that such costs have been reasonably and prudently incurred. We also note that reasonably and prudently incurred capital retirement and redemption expenses associated with a securitization financing are included within the definition of bondable stranded costs in the Act and may therefore be securitized and recovered via the TBC. Paragraph 44: The Board supports the need for an annual review of the indicated charges and related deferred costs accruals, and further notes that periodic true-ups of the TBC are required by the Act. We clarify, however, that to satisfy the rate reduction provisions of the Act, the Board may or may not actually adjust the indicated charges (other than the TBC, and the BGS price as provided in elsewhere in the Stipulation and in this Order) during the transition period. Paragraph 47: The Board acknowledges that the Company may reserve its rights, however we shall not adopt this paragraph. DOCKET NOS. EO97070455, EO97070456, EO97070457 7 8 In summary, subject to the conditions embodied herein, the rate discounts provided by Atlantic, all stated relative to current rates, shall be at a minimum as follows: August 1, 1999 5% January 1, 2001 7% August 1, 2002 10.2% The average shopping credits during the Transition Period shall be, at a minimum, as follows:
Rate Class 1999 2000 2001 2002 2003 ---------- ------- ------- ------- ------- ------- RS 5.65 5.70 5.75 5.80 5.85 RS-TOU 5.10 5.15 5.20 5.25 5.30 MGS-Sec 5.35 5.40 5.50 5.60 5.70 MGS-Pri 5.18 5.23 5.33 5.43 5.53 AGS-Sec 5.30 5.35 5.45 5.55 5.65 AGS-Pri 5.07 5.12 5.17 5.22 5.27 AGT-Sec 5.05 5.10 5.15 5.20 5.25 AGT-Pri 4.95 5.00 5.00 5.00 5.00 AGT-SubT 4.30 4.30 4.30 4.30 4.30 AGT-Trans 4.25 4.25 4.25 4.25 4.25 TGS 4.30 4.30 4.30 4.30 4.30 SPL/CSL 2.97 3.05 3.07 3.10 3.12 DDC 3.58 3.68 3.71 3.75 3.78 System Average 5.27 5.31 5.37 5.42 5.48
Within five (5) business days of the date of this Order, the Company is HEREBY DIRECTED to submit to the Board a tariff compliance filing addressing the provisions of this Summary Order, and to submit to the Board schedules that show all accounting entries that will be required with respect to the transfer of the combustion turbine and Deepwater generating facilities as a result of this Order, for both Atlantic and the unregulated affiliate. The Company shall consult with Staff to assure the adequacy of the required submissions DATED: 7/15/99 BOARD OF PUBLIC UTILITIES BY: /S/ Herbert H. Tate ------------------- HERBERT H. TATE PRESIDENT DOCKET NOS. EO97070455, EO97070456, EO97070457 8 9 /s/ Carmen J. Armenti --------------------- CARMEN J. ARMENTI COMMISSIONER /s/ Frederick F. Butler ------------------- FREDERICK F. BUTLER COMMISSIONER ATTEST: /s/ Mark W. Musser ------------------ MARK W. MUSSER SECRETARY DOCKET NOS. EO97070455, EO97070456, EO97070457 9 EX-99.C3 4 ATLANTIC CITY ELECTRIC STIPULATION OF SETTLEMENT 1 EXHIBIT C-3 STATE OF NEW JERSEY BOARD OF PUBLIC UTILITIES - ------------------------------------ : I/M/O of the Energy Master Plan : BPU Docket No. EO97070456 Phase II Proceeding to Investigate : OAL Docket No. PUC07311-97 the Future Structure of the : Electric Power Industry : (Atlantic City Electric Company) : Stranded Costs Filing : : I/M/O of the Energy Master Plan : BPU Docket No. EO97070455 Phase II Proceeding to Investigate : OAL Docket No. PUC07311-97 the Future Structure of the : Electric Power Industry : (Atlantic City Electric Company) : Unbundled Rates Filing : : I/M/O of the Energy Master Plan : BPU Docket No. EO97070457 Phase II Proceeding to Investigate : the Future Structure of the : Electric Power Industry : STIPULATION (Atlantic City Electric Company) : OF Restructuring Filing : SETTLEMENT : - ------------------------------------: INTRODUCTION On April 30, 1997, the New Jersey Board of Public Utilities ("BPU" or the "Board") issued a report entitled Restructuring the Electric Power Industry in New Jersey: Findings and Recommendations, Docket No. EX94120585Y, April 30, 1997 (hereinafter "Final Report"). The Board also directed the State's electric utilities to make comprehensive filings addressing three areas: rate unbundling, stranded costs, and industry restructuring. Atlantic City Electric Company ("Atlantic" or the "Company") submitted its filing on July 15, 1997. The Board retained the restructuring portion of the filing, but transmitted the rate unbundling and stranded costs aspects of the filing to the Office of Administrative Law for hearings. 2 The Hon. William Gural, Administrative Law Judge ("ALJ"), heard the rate unbundling and stranded costs matters over the course of nine days of evidentiary hearings held on February 17, 1998 through February 20, 1998, and February 23, 1998 through February 27, 1998. During these hearings Atlantic presented the following witnesses: Thomas Shaw, Dr. Philip O'Connor, Henry Levari, Wayne Camp, William Gibson, Patricia MacFarland Goelz, Louis Walters, Dr. Charles Moyer, Murray Stoltz, Carl Setterman and Paul Normand. Numerous other witnesses were also presented by the various parties to the proceedings. ALJ Gural rendered his Initial Decision in the rate unbundling and stranded costs matters on August 17, 1998. In an Order dated January 28, 1998, the Board identified eight generic restructuring issues and decided to hold one set of restructuring hearings for all parties. Following extensive discovery, 19 days of evidentiary hearings were held before Commissioner Armenti beginning April 27, 1998 and concluding May 28, 1998. Atlantic presented the following witnesses: Joseph Bartolone, Tsion Messick, Thomas Shaw, Henry Levari, Eileen Unger, Ashley Brown, and Rodney Frame. On February 9, 1999, the New Jersey Electric Discount and Energy Competition Act ( the "Act"), N.J.S.A. 48:3-49 et seq., was enacted. The Act provides that retail electric customers shall have the opportunity to select their electric suppliers on, or about, August 1, 1999. The Act also provides for reduced retail electric rates. The Board has encouraged the parties to attempt to negotiate a settlement of these proceedings. As a result, the Company commenced detailed settlement discussions with the parties on April 23, 1999. As a result of these negotiations and settlement discussions, it is hereby agreed 3 among the undersigned parties that this Stipulation of Settlement ("Stipulation") accurately states the terms of such resolution with regard to issues in Atlantic's stranded costs and rate unbundling proceedings, as well as certain restructuring issues specific to Atlantic. STIPULATION OF SETTLEMENT It is hereby stipulated and agreed, as of this 9th day of June, 1999, by and among Atlantic City Electric Company, Enron Capital and Trade Resources, PP&L EnergyPlus Co. (successor in interest to Pennsylvania Power & Light Company, d/b/a PP&L EnergyPlus, for purposes of this case), New Jersey Retail Merchants Association and New Jersey Food Council, who have jointly intervened in these proceedings as the New Jersey Commercial Users, and the Independent Energy Producers of New Jersey (collectively the "Parties") that: RATE REDUCTIONS, TRANSITION PERIOD & UNBUNDLED RATES 1. The Parties agree that electric rate reductions shall be implemented as follows to comply with the provisions of Section 4(d) of the Act: a. The Parties acknowledge that the Company's rates are already lower by a total of 1.3%, as a result of specific actions taken by the BPU in recognition of the pending restructuring proceedings. In January, 1998, the Company lowered rates by 1.2%, representing the net amount of savings due to the merger of its parent company with Delmarva Power & Light Company and expenses due to post-retirement benefits other than pensions. In its Order approving the merger, the Board specifically recognized that such net savings would be included as part of any restructuring-related rate reductions. In June, 1998, rates were lowered an additional 0.1% as a result of the Board's decision to remove base rate 4 expense items from the Company's rates during the 1997 LEAC proceeding. Again, such Board action was based upon pending restructuring-related rate changes. b. An additional reduction from current rates shall be provided by the Company for service rendered on and after August 1, 1999. This reduction will be achieved, in part, by offsetting $36 million of current regulatory asset charges with projected DSM and LEAC credits, as set forth in Schedule A, reducing charges for electric power to market levels, and setting the Market Transition Charge ("MTC") in a manner that yields a net 3.9% reduction. To the extent that LEAC credits exceed the amount necessary to offset these charges, such excess credits will be applied to offset the outstanding balances of other regulatory assets. c. Subsequent to August 1, 1999, the Company will implement additional rate reductions to give effect to any and all net savings achieved by virtue of the buyout or buydown of contracts with Non-Utility Generators (hereinafter "NUGs"), and the securitization of stranded costs and/or the securitization of the cost of NUG buyouts or buydowns. Reductions due to NUG buyouts or buydowns shall be given effect through a revision to the NNC (as described in paragraph 23), as approved by the Board. Reductions due to securitization shall be given effect upon the implementation of a securitization bond recovery charge in rates, as approved by the Board. The Company will implement such reductions as soon as practicable after BPU approval, and to that end will include a request to set such charges in any request for approval of a buyout, buydown or securitization. 5 d. To the extent the rate reductions provided for in paragraphs 1(a), (b), and (c) above, do not provide an aggregate 10% reduction from April 30, 1997 Rates (hereinafter "10% Reduction") for all customers, the Company will implement a rate credit for service rendered on and after August 1, 2002 through July 31, 2003 which, together with the rate reductions provided for in paragraphs 1(a), 1(b) and 1(c), results in the 10% Reduction. The rate credit implemented pursuant to this paragraph will be sustained until July 31, 2003. e. The Parties acknowledge that in order to fund and sustain the rate reductions and the rate credit set forth in paragraphs 1(a) through 1(d) above, it may be necessary for the Company to defer the recovery of revenues associated with basic generation service ("BGS"), NUG costs, or other costs. No portion of the costs for BGS shall be deferred prior to the deferral of any other deferrable cost, as more specifically set forth in paragraph 27. Such deferral and recovery is set forth more fully below in paragraph 27 through paragraph 29. 2. The Parties acknowledge that the Company's agreement to the foregoing rate reductions and rate credit is based on the Board's approval of the divestiture of certain of the Company's generating assets, as described more fully below, and securitization of 100% of the net stranded costs associated with those assets. 3. The four-year period commencing August 1, 1999, and terminating July 31, 2003, shall be hereinafter referred to as the "Transition Period." 4. The unbundled rates to be effective August 1, 1999, for each rate class in Atlantic's Tariff for Electric Service have been developed using the Company's 1996 Cost of Service Study. 6 See Appendix A (rates/tariffs). The Parties acknowledge that the Company's transmission rates are subject to revision by the Federal Energy Regulatory Commission ("FERC"), and may increase or decrease. Accordingly, the transmission and distribution rates are subject to revision, after the final determination of FERC is rendered, in order to produce the same revenues as the rates set forth in Appendix A. BASIC GENERATION SERVICE AND SHOPPING CREDIT 5. The Parties have agreed to the following provisions with respect to the "shopping credit", in accordance with Section 4(b) of the Act. a. For the four years of the Transition Period, up to and including July 31, 2003, the average "shopping credit" shall be the greater of the amounts determined in accordance with paragraph 6, inclusive of BGS rates and transmission rates, or the amounts set forth below:
RATE CLASS 1999 2000 2001 2002 2003 ---- ---- ---- ---- ---- Annual Annual Annual Annual Annual ------ ------ ------ ------ ------ RS 5.15 5.20 5.20 5.25 5.30 RS-TOU 5.10 5.15 5.20 5.25 5.30 On Peak 6.59 6.65 - - - Off Peak 4.67 4.72 - - - MGS Secondary 5.45 5.50 5.60 5.70 5.80 MGS Primary 5.28 5.33 5.43 5.53 5.63 AGS Secondary 5.40 5.45 5.55 5.65 5.75 AGS Primary 5.17 5.22 5.27 5.32 5.37 AGS TOU Secondary 5.15 5.20 5.25 5.30 5.35 On Peak 6.11 6.17 6.23 6.29 6.35 Off Peak 4.25 4.29 4.33 4.38 4.42
7 AGS TOU Primary 5.05 5.10 5.10 5.10 5.10 On Peak 5.98 6.04 6.04 6.04 6.04 Off Peak 4.18 4.22 4.22 4.22 4.22 AGS TOU 4.30 4.30 4.30 4.30 4.30 Sub-Transmission On Peak 5.08 5.08 5.08 5.08 5.08 Off Peak 3.57 3.57 3.57 3.57 3.57 AGS-TOU 4.25 4.25 4.25 4.25 4.25 Transmission On Peak 5.00 5.00 5.00 5.00 5.00 Off Peak 3.54 3.54 3.54 3.54 3.54 TGS 4.30 4.30 4.30 4.30 4.30 SPL/CSL 2.97 3.05 3.07 3.10 3.12 DDC 3.58 3.68 3.71 3.75 3.78 SYSTEM AVERAGE 5.09 5.14 5.17 5.23 5.28 Shopping Credits include the following: Basic Generation Service Supply, Transmission, Ancillary Services, Administrative Costs and Taxes
The shopping credits set forth above are rate schedule averages. The actual BGS rates to be charged to customers, and the corresponding shopping credits resulting from those rates, will differ by blocks and load factors for those customers with rates which contain demand and energy components. b. The shopping credits set forth in paragraph 5(a) include a transmission rate component based on the average rate for transmission for each rate class; the actual shopping credit for each customer will be determined based on each customer's actual billing determinants and the transmission rates in the Company's unbundled retail tariff. c. In calculating the BGS rates pursuant to paragraph 6 below, the BGS rates shall be set so that the resulting BGS rate for each rate class remains in proportion to the system 8 average BGS rate, as the BGS rates set forth in Appendix A have with respect to the system average BGS rate for the BGS rates in Appendix A. d. The Parties acknowledge that the Company's agreement to the minimum shopping credits set forth in paragraph 5(a) is conditioned upon the Board's approval of this Stipulation in its entirety, and in particular is expressly conditioned upon the Board's approval of the specific rate reduction provisions contained in paragraph 1. 6. The Parties agree that Atlantic shall provide BGS, in the following manner: a. The BGS rates shall be inclusive of the costs provided for in section 9(a) of the Act, inclusive of losses and taxes. b. Customers who choose to purchase electricity from electric power suppliers ("EPSs") will not pay the BGS rates, and in addition will not be billed for transmission charges by Atlantic (if such charges are included in their charges from the EPS), which will be based on each customer's billing determinants and the transmission rates in the Company's unbundled retail tariff. See paragraph 4. c. The sum of the BGS and transmission charges shall be the "shopping credit", subject to the provisions of paragraphs 5 and 6(b). If the "shopping credit" for any rate class is the amount set forth in the chart in paragraph 5(a), then the average BGS rate for the class shall be set as the "shopping credit" less the transmission charge. To the extent the rate for BGS as calculated in the first sentence of this paragraph, added to the average rate for transmission, produces a shopping credit in excess of the shopping credit levels in the chart in paragraph 5(a), then such BGS rate and the resulting shopping credit shall be utilized. The 9 Parties agree that the shopping credit mechanism set forth in paragraphs 5 and 6 satisfies the requirements of Section 4(b) of the Act. d. The rates as determined pursuant to paragraph 6(a) may be limited to the extent any portion of such BGS costs need to be deferred pursuant to paragraph 1(e) above. The shopping credit calculated from the BGS rate would similarly be limited. e. The Parties further recognize and agree that additional shopping-related savings, resulting from customers receiving electric generation service from an EPS at a price less than the shopping credit, are above and beyond the rate reductions set forth in paragraph 1 of this Stipulation. 7. The Parties agree that Atlantic shall procure power for BGS through an open, competitive bidding process. During the first three years of the Transition Period, up to and including July 31, 2002, Atlantic plans to solicit proposals (the "RFP Process") for the provision of wholesale supply for BGS in twelve month pricing cycles, or such other cycles as Atlantic deems necessary or prudent. Atlantic will submit its plans for the RFP Process to the BPU by September 15, 1999. Atlantic intends to commence the RFP Process as soon as practicable after such date and approval of the Plan by the BPU, with the goal of concluding such process and entering into a contract for BGS supply by December 15, 1999. Any agreements for the provision of BGS shall be presented to, and subject to the approval of, the BPU. The Parties further agree that to the extent the Company has supply resources available from its NUG sources, the Company will apply such resources toward the BGS supply requirements and conduct the bidding process for the net BGS supply requirements resulting therefrom. 10 8. In recognition of Atlantic's large seasonal customer base, which results in increased costs for energy and capacity to serve customers from June through September, the Parties agree that customers switching into BGS from an EPS shall be required to remain on BGS for a minimum 12 month period; however, any customer, while switching service from one EPS to another, in accordance with Board-authorized switch rules, may return to BGS for thirty (30) days without being required to remain on BGS; provided, however, that this exception shall not be available to any customer who returned to BGS and then switched to an EPS within the previous twelve (12) months. However, any residential customer who returns to BGS due to the refusal or the inability of the customer's EPS to continue to provide service to that customer shall not be required to remain on BGS for a minimum 12 month period. The Company will have the option of reviewing, with the Parties, the BPU and Staff, the residential seasonal BGS customer base to determine whether a filing for approval of a separate residential billing tariff, to avoid subsidies within the residential class between seasonal and year-round customers, is necessary for the summer season in 2000 and beyond. 9. The Parties support the fact that in order to establish BGS commencing August 1, 1999, until supply arrangements are made in accordance with paragraph 7, Atlantic may have to secure supply through the Pennsylvania - New Jersey - Maryland Interconnection ("PJM") for BGS, and that for purposes thereof, the BGS pricing shall be based upon the capacity prices and the applicable locational marginal prices of energy as reported by the Pennsylvania-New Jersey-Maryland Office of Interconnection ("PJM OI"). Such capacity and energy prices shall also be used as the market value of the NUG resources which may be employed for BGS, with all NUG costs above that recovered pursuant to paragraph 23. 11 10. The Parties agree that the Company may at its option utilize its affiliated service company to make arrangements for the BGS supply pursuant to paragraphs seven through fourteen, and that such arrangements shall be conducted on behalf of the Company as a regulated service. Neither the Company nor the affiliated service company shall provide information relevant to the provision of BGS and the bidding process to any competitive affiliate of the Company, either directly or indirectly through the medium of another affiliate of the Company, unless that information is provided contemporaneously to all others bidding to provide BGS to Atlantic. The Company and the affiliated service company shall receive and maintain all BGS bids, and discussions related thereto, in a confidential manner, and not disclose such information, unless said information is otherwise made public pursuant to law, regulatory act, or agreement with the provider of the information. Employees of the affiliated service company who transfer to any competitive affiliate of the Company shall be kept separate from, and shall not participate in, any proposal by the competitive affiliate to provide BGS to Atlantic. 11. The Parties agree that the Company may, at its option, use energy and capacity obtained through one or more "parting contracts," as described in paragraph 20 below, for the provision of BGS. The Parties further agree that the Company may utilize certain financial instruments to decrease ratepayer exposure to price spikes and price volatility, for example, hedging. It is recognized by the Parties that the use of some of these products could result in costs which exceed the spot market. The Parties agree that the cost of such parting contracts and financial instruments, as well as all other reasonably and prudently incurred costs associated with the procurement and provision of BGS, shall be recoverable in rates for BGS pursuant to Section 9(e) of the Act. 12 12. The Parties acknowledge that pursuant to Section 9(a) of the Act the Company has a minimum obligation to provide BGS through July 31, 2002 to those retail customers who choose to remain with the utility. The responsibility for BGS for the fourth year of the Transition Period, after July 31, 2002, shall be bid out during the third year of the Transition Period. Bidders shall bid for the right to provide BGS during the year commencing August 1, 2002. The bids shall be based on the minimum shopping credits for the applicable time periods, as set forth in paragraph 5(a). Depending on the bidders' perceived value at the time of the right to provide BGS, the bids shall provide for either: (i) a payment from the bidder to the Company, to provide BGS at a price based on the minimum shopping credit, as described in paragraph 6; (ii) the provision of BGS at a rate which results in shopping credits for the applicable time period, as set forth in paragraph 6; or (iii) a payment from the Company to the bidder, if the BGS rate proposed by the winning bidder is such that some portion of the BGS revenues must be deferred, in accordance with paragraph 1(e), such payment to be equal to the portion of the BGS rate which can not be charged to the customers, but which must be deferred. If the winning bid results in a net payment to the Company, such payment shall be applied to reduce the balance of the Deferred Revenues pursuant to paragraph 27, or any other under-recovered balance. If the winning bid for BGS results in a net payment by the Company, such payment shall be subject to deferral and subsequent recovery, as part of the Deferred Revenues as set forth in paragraphs 27-29. At the conclusion of the Transition Period, BGS will no longer be offered by the Company. The Parties hereto further agree that the Board should establish a structure and procedures for the provision of BGS after the Transition Period. 13. The Parties agree that a competitive affiliate of the Company may be permitted to bid to provide wholesale supply for BGS service, and bid to provide BGS pursuant to paragraph 12, 13 during the Transition Period, subject to the affiliate relations standards to be adopted by the Board. If a competitive affiliate of the Company participates in any such bid, the Company and its affiliated service company shall utilize the services of an independent consultant to review the bids, pursuant to criteria to be set in developing the RFP process, and present the results to the Company so as to not reveal which bid is from a competitive affiliate. 14. The Parties agree that the bidding procedures to be conducted for the BGS supply during the Transition Period as described above shall be conducted on behalf of the regulated utility, and that all competitive information relating to bids which may be tendered shall be treated as proprietary and confidential, and shall not be made available to a competitive affiliate of the Company. 15. The Company agrees that it will not promote BGS as a competitive alternative. STRANDED COSTS 16. The Company shall be permitted to recover 100% of its net stranded costs, including 100% of the stranded costs associated with the Company's non-utility generator power contracts. 17. The Company has agreed, subject to the terms of this settlement, to divest its interests in the B.L. England, Keystone, Conemaugh, Peach Bottom, Salem and Hope Creek generating stations. The net divestiture proceeds will be used to determine the Company's generation related stranded costs. Generation related stranded costs shall mean the excess of net book value as of the closing date(s) of the sale(s) over net divestiture proceeds. Net divestiture proceeds are defined as the excess of the selling price(s) of the generating assets over the transaction costs incurred by the Company. The transaction costs shall be reasonable, verifiable and necessary, and shall include (but not necessarily be limited to) sales and transfer taxes, state, federal and local taxes, consultants fees, 14 broker commissions, legal fees, investment banking fees, title transfer fees, real estate transfer and related costs, mortgage and financing costs, real estate taxes, transportation and system-separation costs (including outside contractor, engineering, purchased materials and labor costs) associated with the divestiture activities, paid overtime and out-of-pocket expenses for Company employees associated with the divestiture activities, and any arrangements to address direct and indirect employee impacts from the divestiture including retirement, severance and any other employee-related benefit costs. 18. Final determination of the net divestiture proceeds shall be undertaken only upon the completion of the transfer of all of the generation assets listed in paragraph 17 to each purchaser thereof, as set forth herein. a. Such final determination shall be made within a separate divestiture proceeding, to be filed by Atlantic pursuant to standards to be set by the Board, subject to the terms of this Stipulation as approved by the Board in its final decision or Order herein. The final determination of the net divestiture proceeds shall constitute only a true-up of actual selling price(s), book value(s) and transaction costs, and not a further review on the merits of the transaction. b. Subject to the true-up proceeding referenced in paragraph 18(a), the Board Order approving this Stipulation shall constitute a Board determination that the transfer of the Company's generation and related assets to third parties, in accordance with the standards to be adopted pursuant to paragraph 19, as described in the Company's future divestiture filings, will be approved by the Board in the future divestiture dockets without condition, addition or modification, at the agreed upon selling price(s), which shall be considered the "full 15 market value" of the assets being transferred for the purposes of Section 11(c)(1) of the Act, and on the terms, specified in the future divestiture petitions. The Parties acknowledge that such transfers require various regulatory approvals or waivers, including, without limitation, the Board, the Federal Energy Regulatory Commission ("FERC"), the Nuclear Regulatory Commission and other agencies. Provided the Company files a proposal for divestiture in accordance with the standards to be set as referenced in paragraph 19, the Parties will neither oppose, nor support any opposition to, any proceeding seeking the approval of such sales or the terms thereof, or seeking any other order or approval as may be required in order to consummate such sales, before the Board or any other adjudicatory or regulatory body, nor will the Parties seek to intervene in any such proceeding without the consent of the Company, except as to matters not addressed in this Stipulation. c. With respect to the proceedings referenced in paragraph 18(b), the IEPNJ and its current members state that, while they support the concept of the divestiture of assets as set forth in paragraph 17, they reserve the right to move before the BPU to seek the review of any specific transfer of any generation asset listed in paragraph 17. d. Any party who participates as a bidder in any sale conducted as part of such divestiture shall have the same rights as any other bidders in any BPU proceeding concerning such sale. e. Nothing herein shall prevent a party from intervening in any such proceeding solely for monitoring purposes. 19. In order to effectuate a timely divestiture of the Company's generation assets, the Parties recognize that the Board must take certain steps. Therefore, within thirty (30) days of a 16 submission by the Company, the Board will finalize divestiture standards applicable to Atlantic's generating assets. Nothing contained in this Stipulation shall foreclose any Party from participating fully before the BPU in formulating divestiture standards. 20. The Parties agree that the use of "parting contracts" entered into by the Company with purchasers of its generation assets, as part of the sale of such assets to those purchasers, to the extent they make possible or enhance the sale of such assets, and are approved by the Board, are in the public interest, and in accordance with applicable law. The Parties agree that the term of any "parting contract" will not exceed four (4) years. Further, the Parties agree the rates and costs contained therein are an integral aspect of the sale of the generating assets. Therefore, the Company may flow-through, and fully and timely recover, the rates specified in the "parting contracts," and the resulting costs, from its customers. Should the "parting contract" rates and/or costs be at levels which are above market cost, then the Company will fully and timely recover such costs through a mechanism similar to the NNC described in paragraph 23. 21. The Company agrees to forego recovery of $9 million in net stranded costs associated with its Deepwater Station and its Combustion Turbines, as set forth in Schedule B ("Transferred Units"), and as set forth herein. a. Pursuant to Section 7(d) of the Act, the Parties will not object to the Board approving the transfer of the Transferred Units to an unregulated affiliate of the Company. The Parties agree that the transfer value of the Transferred Units shall be the net book value of the assets at the time of the transfer, adjusted for the application of Financial Accounting Standards Board ("FASB") Statement No. 121 ("Adjusted Book Value"). Such transfer prices will, and are intended to, ensure that the Company receives full and fair compensation for the 17 Transferred Units and that Atlantic will not retain any liabilities associated with the Transferred Units. The Company shall not bear any expenses of the Transferred Units after the transfer to an unregulated affiliate. The Company shall have auditable accounting protocols in place no later than the effective date of the transfer to assure that all expenses and capital expenditures related to the Transferred Units will not be borne by the Company. If, within three (3) years of the date of this Stipulation, any Transferred Unit is sold to a non-affiliate of Atlantic, the net after-tax gain over the Adjusted Book Value shall be shared equally between the Company and the customers, in a manner to be determined by the Board. b. It is the position of Enron that if the transfer outlined in paragraph 21(a) takes place, the Transferred Units should be maintained as a capacity resource within the PJM system for the Transition Period. c. With respect to affiliate issues, the parties, with the exception of Enron and IEPNJ, recognize that the Board has released draft affiliate relationship standards for comment, and will be adopting affiliate relationship standards pursuant to the Act prior to the completion of the transfer of the Transferred Units to any affiliate, and that such standards will be applied to the relationship between Atlantic and its affiliates. Enron and IEPNJ contend that the Affiliate Standard of Conduct that should apply is as follows: "The competitive generation affiliate shall not offer power or other services to any of its affiliates which are not made generally available to non-affiliated companies, nor shall it offer such power or other services to affiliates at prices more favorable than those generally 18 available in the competitive marketplace and/or to those offered to non-affiliated companies." 22. The Parties agree that there shall be no amortization of stranded costs associated with generating assets during the period between August 1, 1999 and the divestiture of the generating assets. Once divestiture has been completed, and the actual stranded costs thereof have been determined, amortization of such stranded costs shall commence. 23. The Parties acknowledge that the Company is entitled to full and timely recovery of 100% of the costs associated with its NUG purchased power contracts. The Parties recognize that each of these non-utility generator contracts have been previously reviewed and approved for full and timely recovery by the Board. Therefore, consistent with Section 13(a)(3) of the Act and other applicable law, the Parties agree that the Company shall be permitted to fully recover, dollar-for-dollar, the costs associated with its NUG contracts, over the life of each such contract. The Parties agree that the Company shall utilize a Net Non-Utility Generator Charge ("NNC") as a component of the MTC to recover the stranded costs associated with the purchase of power from NUGs. The NNC shall be equal to the difference between the cost of the NUG-contract purchased power and either (a) the proceeds realized by the Company from the sale of that NUG-contract power in the competitive wholesale market, (b) the pricing set forth in paragraph 7, to the extent NUG resources are utilized as set forth in paragraph 7, or (c) the pricing set forth in paragraph 9, to the extent NUG resources are utilized as set forth in paragraph 9. Such proceeds will be adjusted to reflect a deduction for the reasonable marketing and administrative costs associated with the sale of the NUG-contract power into the wholesale market. The NNC shall also include swap breakage costs incurred in connection with a previous amendment to one of its NUG contracts, which costs have been 19 recovered to date through the Energy Adjustment (EA) clause charge. The NNC shall continue over the actual term of each of the Company's NUG contracts, and shall be applied as a non-bypassable wires charge to retail customers. In the event, of a NUG-contract buyout, buydown or restructuring, the Company will be provided with an incentive for restructuring amounting to ten (10) percent of the net savings, except for the Pedricktown Project for which the incentive will be five (5) percent, and the NNC shall be adjusted accordingly. As set forth below, the Parties agree to 100% securitization, over the remaining contract term, of the costs associated with any buyout, buydown or restructuring of the Company's NUG power contracts. In the event of such buyout, buydown, or restructuring, and prior to the securitization of the costs for same, the Company shall include such costs in its MTC recovery. 24. The Parties agree that the Company will incur additional stranded costs for restructuring-related items that are capital in nature, the estimated costs of which are set forth in Schedule C. Therefore, the Parties agree that the Company may recover these costs through securitization of up to 75% of total capital expenses for terms up to 15 years. Capitalized costs not recovered through securitization will be recovered, with a full rate of return on the unamortized balance, over a period of up to 8 years through a component of the Market Transition Charge ("MTC"). 25. The Parties agree that net stranded costs for restructuring related items of an operating nature, other than consumer education costs, shall be recoverable on a full and timely basis through a component of the MTC. A listing of these costs, and the estimates thereof, are attached as Schedule D. 20 26. This Stipulation constitutes a balancing of the interests of the various Parties, and the Company's agreements as to rate reductions and stranded cost recovery reflect such balance. A determination by the Board contrary to this agreement of the Parties, as to the treatment of the Company's future divestiture petition(s) and the quantification of stranded costs as a result thereof, would upset such balance. Thus, if the Company would be required to write off certain amounts as a result of the Board orders issued in the future divestiture dockets, or otherwise required in the divestiture dockets to absorb stranded costs with respect to the assets being divested in excess of the amounts contemplated in this Stipulation, this Stipulation, and the Board Order issued in respect hereof, shall be deemed modified to the extent necessary to permit the Company to recover such amounts that would otherwise be required to be written off, or such excess stranded costs, through the MTC. DEFERRALS AND RECOVERY OF DEFERRALS 27. As described in paragraph 1(e) above, the Parties recognize that the Company may have to defer recovery of some portion of its revenues in order to achieve and/or sustain rate reductions or the rate credit through the end of the Transition Period. The revenues which may be so deferred (the "Deferred Revenues") are those incurred during the Transition Period to meet the costs of BGS (as set pursuant to paragraph 6), the NNC (as set pursuant to paragraph 23), and the costs recoverable through the MTC (set forth in paragraph 25). Therefore, during the Transition Period, the Company will utilize a deferred accounting mechanism to provide for full recovery of any Deferred Revenues. Revenues for BGS will only be deferred to the extent necessary to fund and sustain the rate reductions and the rate credit set forth in paragraphs 1(a) through 1(d), and then only after the deferral of any other item of Deferred Revenues, as set forth in this paragraph. Any Deferred Revenues, together with a full rate of return on the unrecovered balance, will be recovered by the Company no later than August 1, 2007. The Parties agree that the Company has an absolute right to recover the Deferred Revenues, along with the Company's authorized rate of return, from the Company's ratepayers in a full and timely manner. The Parties acknowledge that this deferral and recovery schedule represent a balancing of the Company's financial requirements and a desire to mitigate the rate impact on customers. Therefore, the Board Order approving this Stipulation shall constitute final approval of the recovery of the Deferred Revenues, which is an integral part of this Stipulation. Further, the Parties agree that any repayment of the Deferred Revenues by ratepayers will not be included within operating income in any ratemaking proceeding, and it will not be considered when determining the Company's authorized rate of return in future ratemaking proceedings. Moreover, the Parties will neither oppose, nor support any opposition to, any proceeding relating to the recovery of the balance of Deferred Revenues. The Parties hereto 21 specifically reserve the right to intervene in any such proceeding in order to support such full and timely recovery. 28. The balance of the Deferred Revenues shall be recovered after the Transition Period through a charge to be included in post-Transition Period regulated rates, which shall generate a post-Transition Period regulated cash flow stream for that purpose, and the balance of the Deferred Revenues shall thereupon be reversed from the Company's balance sheet as it is recovered. This assurance of recovery, which the Board's Order approving this Stipulation will provide, is intended in all respects to comport with and satisfy the standards of the FASB, including those FASB standards under which the Company is permitted to maintain the Deferred Revenues as a regulatory asset rather than being required to record the balance as a current expense. 29. In recognition of the requirement in Section 13(h) of the Act that rate reductions not impair an electric public utility's financial integrity such that access to the capital markets for the continued provision of safe, adequate and proper utility service is impaired, in the event, at any point in the Transition Period, either (a) the balance of the Deferred Revenues exceeds $50 million, or (b) the Company's senior secured debt is downgraded or the Company is placed by a rating agency on credit watch, the Company may petition the Board for appropriate relief. The Parties agree that, in their view, under the Act the Board would have the discretion and authority, in response to such a petition, to, among other things, take ratemaking action to preserve the Company's financial integrity. Nothing herein shall be deemed to limit the Company's right otherwise to petition the Board for any relief deemed necessary by the Company at any time. 22 SECURITIZATION 30. The Parties agree that the Company shall be permitted to securitize 100% of the net stranded costs associated with its divested generation assets. This figure shall be calculated in accordance with paragraph 17 above. The term of such securitization financing associated with the divested generation assets shall not exceed 15 years. The Parties further agree that taxes related to securitization, reflecting the grossed-up revenue requirement number associated with the level of stranded costs as determined in paragraph 17 above, are legitimate recoverable stranded costs, and are to be recovered through a separate component of the MTC with a term identical to the term of the securitization financing. The Parties further agree that the Company is entitled to the full and timely recovery of all transition bond charges ("TBC"), along with applicable taxes. 31. The Parties agree that the Company shall be permitted to securitize 100% of the net stranded costs associated with the restructuring, buyout or buydown of it NUG power contracts. The term(s) of the related securitization financing shall be no longer than the remaining terms of the respective NUG contracts which have been restructured or terminated. The Parties further agree that the Company is entitled to the full recovery of all transition bond charges, along with applicable taxes. 32. The Parties agree that the Company shall be permitted to securitize 75% of all restructuring-related net stranded costs that are capital in nature, as set forth in paragraph 24. The term of the related securitization shall not exceed 15 years. 33. It is expected that third parties may be authorized to provide billing and collection services in the future as a result of the statutorily required billing and metering proceeding. Even if third party billing and collection has not been so authorized by the time the Company seeks to effect a securitization transaction, the Parties recognize and agree that appropriate creditworthiness 23 standards applicable to any third parties that may ultimately provide billing and collection services would have to be in place by the time of any securitization transaction in order to satisfy credit rating agencies and the financial community so that securitization may proceed. Therefore, the Board Order approving this Stipulation shall constitute a Board determination that, if such creditworthiness standards are not in place before the Company undertakes securitization of any of its assets, such standards will be incorporated in the applicable bondable stranded costs rate order. SOCIETAL BENEFITS CHARGE 34. The Parties agree that consistent with Section 12 of the Act, the Company will establish a Societal Benefits Charge ("SBC"). The SBC will include costs related to: (1) social programs, (2) nuclear plant decommissioning costs, (3) Demand Side Management ("DSM") programs, and (4) consumer education. 35. The SBC will be set at the level of costs for the above items already in rates as of the date of this Stipulation. During the Transition Period, the funding of SBC initiatives may vary from the level of funding currently in rates. The Parties reserve the right to assert their respective positions in proceedings related to the Comprehensive Resource Analysis to be performed by the Company. An annual true-up process will be established to provide for the full and timely recovery of SBCs. To the extent that full and timely recovery of the SBC costs prevents the Company from achieving the rate reductions described in paragraphs 1(b) and 1(d) above, the Company agrees to defer a portion of the SBC cost recovery subject to the same terms and conditions as described in paragraph 27. 24 OTHER ISSUES 36. All tax expenses shall be determined on a utility stand-alone basis, and not by imputing the tax effects of a consolidated return. The Company is entitled to full and timely recovery of all taxes in connection with restructuring and with the divestiture of the Company's generating assets. 37. The Company shall be authorized to continue to provide service under its existing Off-Tariff Rate Agreements ("OTRAs"). The Company agrees not to transfer any OTRA to an unregulated affiliate, on the condition that the Company may utilize the services of an affiliated energy trading segment to procure the supply to serve under the OTRA. In addition, the Company agrees that any OTRA customer may choose to end its contract, shop for and receive generation from an EPS or go on BGS, and be provided unbundled service under the Company's tariffs. The Company will provide notice of this provision to the OTRA customers. 38. With regard to the presentation by the Company of a NUG contract restructuring proposal, the Parties acknowledge the importance of the prompt resolution of such proposal, in order that the benefits of such restructuring to the Company and its customers may commence. Accordingly, the Board shall review and render a decision within 45 days of the Company filing such restructuring proposal with the Board. 39. The Board shall order that the existing regulatory asset associated with the application of FASB Statement No. 109 to the transmission and distribution assets of the Company shall be preserved and shall be addressed by the Board in a future regulatory proceeding. 40. The Parties agree that experimental Residential Time-of-Use rates shall be discontinued as of August 1, 2000. The Parties further agree that the AGS Time-of-Use rates will 25 be closed to any new customers on August 1, 1999, and the rate will continue through the Transition Period, unless the number of customers taking service under that rate schedule drops below 25. Customers currently being served under these rate classes shall be provided with at least 90 days' notice of the discontinuation, and shall be advised that service provided by EPSs may provide electric power supply with time-differentiated pricing. 41. The Parties agree that the Interruptible Rider shall be discontinued as of December 31, 1999. Customers currently being served under this rate will be advised that service provided by EPSs may provide electric power supply with interruptible pricing. 42. The Parties agree that the Standby and Large Standby Riders contained in the present utility tariff shall reflect reductions and credits to be made in accordance with this Stipulation and shall be modified to provide for fixed, unbundled charges for transmission, distribution and customer services, and shall be modified further to provide that standby power supply shall be provided from time to time, as required by the customer, at the BGS rate. 43. The Parties agree that expenses to redeem and retire outstanding capital in connection with the recovery of stranded costs shall be recognized as stranded costs, and shall be included in the MTC. 44. In setting the annual level of charges for BGS during the Transition Period, for any MTC that continues beyond the Transition Period, and for the SBC, NNC and the TBC, the Company will utilize a methodology similar to that currently used for setting its Energy Adjustment (EA) clause charges. The BGS, SBC, NNC, MTC and TBC components will be set annually, based upon projections of costs and of sales. Actual costs will be accounted for on a deferred accounting basis, and when the BGS, SBC, NNC, MTC and TBC are set in the following year, each of those 26 rate components will be set to recover any underrecovery in the deferred balance, as well as the projected costs for the upcoming year. The setting of the BGS, SBC, NNC and MTC shall be subject to providing the rate reductions as set forth in paragraph 1, and the Deferred Revenues provisions of paragraphs 27-29. Any overrecoveries in the deferred balances for the BGS, SBC, NNC or MTC will be applied as a credit to the respective rate components in the same manner. The same procedure will be followed for each year in which the BGS, SBC, NNC, MTC and TBC charges are to be set. 45. With regard to actions within the Company's control, the Company agrees it will make a good faith effort to handle electronic data interchange in relation to the delivery of electricity from EPSs to retail customers by October 1, 1999. BILLING AND METERING 46. The Parties agree to work cooperatively to conclude the statutorily required billing and metering proceeding in an expedited fashion, which proceeding the Parties request that the Board conclude by May 1, 2000. NO WAIVER OF RIGHTS 47. Under the Act, statutory limitations are imposed on the regulated rates that the Company may charge to customers. At the same time, the Company remains statutorily obligated to procure capacity and energy for those customers who receive BGS, at unpredictable and uncontrollable market prices. The Parties acknowledge that the Company is concerned that these statutory limitations and obligations may ultimately impair the Company's access to capital, may become confiscatory as against the Company, or may otherwise prove to be unconstitutional in application. The Parties hereby acknowledge that the Company is not waiving its absolute right to assert that the 27 effect of the legislation, or the Board Order approving this Stipulation, as applied, is or may become confiscatory or otherwise unconstitutional, and to seek any and all legal redress or remedy for the situation. Participation by the Company in settlement negotiations and this Stipulation shall not be deemed a waiver of those rights. 28 CONCLUSION The undersigned agree that this Stipulation contains mutually balancing and interdependent provisions and is intended to be accepted and approved in its entirety and the Parties agree to be bound by its terms. In the event any particular aspect of this Stipulation is not accepted and approved by the Board, or is modified by the Board, any party hereto may deem this Stipulation to be null and void, and upon such declaration, the Parties shall be placed in the same position that they were in immediately prior to the execution of this Stipulation. Atlantic City Electric Company New Jersey Retail Merchants Association By:/s/ Stephen B. Genzer, Esquire By:/s/ Melanie Willoughby - --------------------------------- ------------------------- LeBoeuf, Lamb, Greene & Macrae, LLP Attorneys for Atlantic City Electric Company New Jersey Commercial Users Independent Energy Producers of New Jersey By: /s/ William Harla By:/s/ James E. McGuire - --------------------- ----------------------- Enron Capital and Trade Resources PP&L EnergyPlus, Co. By: /s/ Murray E. Bevan By:/s/ Howard O. Thompson - ----------------------- ------------------------- Morgan and Landis Attorneys for PP&L New Jersey Food Council EnergyPlus, Co. By: /s/ James M. - ----------------- 29 ATLANTIC CITY ELECTRIC APPENDIX A STIPULATION OF SETTLEMENT AUGUST 1, 1999 UNBUNDLED RATE SUMMARY
TARIFF BLOCKS CUST BGS MTC NNC TRANS DISTR DSM DECOM RS CUSTOMER $2.48 SUM 'First 750 KWh 0.045737 0.013504 0.019109 0.005934 0.036511 0.000455 0.000855 WIN' First 500 KWh 0.045737 0.013512 0.019109 0.005934 0.038503 0.000455 0.000855 SUM '> 750 KWh 0.045737 0.023897 0.019109 0.005934 0.041083 0.000580 0.000855 WIN > 500 KWh 0.045737 0.001891 0.019109 0.005934 0.029923 0.000286 0.000855 RS TOU CUSTOMER 3.62 DEMAND CHARGE PERIOD 1 (SUMMER ON) - 5.41 PERIOD 2 (WINTER ON) - 1.82 ENERGY CHARGE PERIOD 1 (SUMMER ON) 0.060136 0.200905 0.019109 0.005892 0.057520 0.000511 0.000855 PERIOD 2 (SUMMER OFF) 0.041015 0.049910 0.019109 0.005892 0.020074 0.000511 0.000855 PERIOD 3 (WINTER ON) 0.060136 0.160506 0.019109 0.005892 0.048626 0.000511 0.000855 PERIOD 4 (WINTER OFF) 0.041015 0.048321 0.019109 0.005892 0.019724 0.000511 0.000855 RS TOU-E CUSTOMER 3.62 ENERGY CHARGE PERIOD 1 (SUMMER ON) 0.060136 0.009291 0.019109 0.005892 0.119057 0.000494 0.000855 PERIOD 2 (SUMMER OFF) 0.041015 0.000006 0.019109 0.005892 0.010881 0.000494 0.000855 PERIOD 3 (WINTER ON) 0.060136 0.009897 0.019109 0.005892 0.081936 0.000494 0.000855 PERIOD 4 (WINTER OFF) 0.041015 0.000002 0.019109 0.005892 0.007216 0.000494 0.000855
TARIFF BLOCKS LC-904 REG TOTAL UNCOLL. ASSETS RATE RS CUSTOMER 2.48 SUM 'First 750 KWh 0.001473 0.000384 0.123963 WIN' First 500 KWh 0.001473 0.000384 0.125963 SUM '> 750 KWh 0.001473 0.000384 0.139053 WIN > 500 KWh 0.001473 0.000384 0.105593 RS TOU CUSTOMER 3.62 DEMAND CHARGE PERIOD 1 (SUMMER ON) 5.41 PERIOD 2 (WINTER ON) 1.82 ENERGY CHARGE PERIOD 1 (SUMMER ON) - 0.000384 0.345311 PERIOD 2 (SUMMER OFF) - 0.000384 0.137750 PERIOD 3 (WINTER ON) - 0.000384 0.296019 PERIOD 4 (WINTER OFF) - 0.000384 0.135811 RS TOU-E CUSTOMER 3.62 ENERGY CHARGE PERIOD 1 (SUMMER ON) - 0.000384 0.215217 PERIOD 2 (SUMMER OFF) - 0.000384 0.076636 PERIOD 3 (WINTER ON) - 0.000384 0.178701 PERIOD 4 (WINTER OFF) - 0.000384 0.074969
Page 1 of 8 30 ATLANTIC CITY ELECTRIC APPENDIX A STIPULATION OF SETTLEMENT AUGUST 1, 1998 UNBUNDLED RATE SUMMARY
TARIFF BLOCKS CUST BGS MTC NNC TRANS MGS-SECONDARY CUSTOMER - 1 PHASE 4.76 CUSTOMER - 3 PHASE 5.94 DEMAND CHARGE SUM > 3 KW 2.46 WIN > 3 KW 2.02 REACTIVE DEMAND 0.06 ENERGY CHARGE SUM < 300KWh 0.048583 0.056981 0.019109 - WIN < 300 KWh 0.048583 0.057159 0.019109 - SUM NEXT 900 KWH 0.048583 0.013645 0.019109 - WIN NEXT 900 KWh 0.048583 0.000557 0.019109 - SUM > 1200 KWh 0.048583 0.006214 0.019109 - WIN > 1200 KWh 0.048583 0.000557 0.019109 - CEILING LIMIT 0.048583 0.068677 0.019109 - MGS-PRIMARY CUSTOMER - 1 PHASE 4.76 CUSTOMER - 3 PHASE 5.94 DEMAND CHARGE SUM > 3 KW 4.35 WIN > 3 KW 3.56 REACTIVE DEMAND 0.05 ENERGY CHARGE SUM < 300KWh 0.043008 0.070353 0.018546 - WIN < 300 KWh 0.043008 0.070547 0.018546 - SUM NEXT 900 KWH 0.043008 0.024288 0.018546 - WIN NEXT 900 KWh 0.043008 0.002649 0.018546 - SUM > 1200 KWh 0.043008 0.016387 0.018546 - WIN > 1200 KWh 0.043008 0.010373 0.018546 - CEILING LIMIT 0.043008 0.082839 0.018546 -
TARIFF BLOCKS DISTR DSM DECOM LC-904 REG TOTAL UNCOLL. ASSETS RATE MGS-SECONDARY CUSTOMER - 1 PHASE 4.76 CUSTOMER - 3 PHASE 5.94 DEMAND CHARGE SUM > 3 KW 4.23 6.69 WIN > 3 KW 3.46 5.48 REACTIVE DEMAND 0.32 0.37 ENERGY CHARGE SUM < 300KWh 0.044974 0.000606 0.000855 (0.000179) 0.000384 0.171314 WIN < 300 KWh 0.045052 0.000606 0.000855 (0.000179) 0.000384 0.171569 SUM NEXT 900 KWH 0.027654 0.000606 0.000855 (0.000179) 0.000384 0.110657 WIN NEXT 900 KWh 0.022459 0.000606 0.000855 (0.000179) 0.000384 0.092374 SUM > 1200 KWh 0.024717 0.000606 0.000855 (0.000179) 0.000384 0.100289 WIN > 1200 KWh 0.022459 0.000606 0.000855 (0.000179) 0.000384 0.092374 CEILING LIMIT 0.050413 0.000700 0.000855 (0.000179) 0.000384 0.188542 MGS-PRIMARY CUSTOMER - 1 PHASE 4.76 CUSTOMER - 3 PHASE 5.94 DEMAND CHARGE SUM > 3 KW 2.34 6.69 WIN > 3 KW 1.92 5.48 REACTIVE DEMAND 0.32 0.37 ENERGY CHARGE SUM < 300KWh 0.035587 0.000422 0.000855 (0.000007) 0.000384 0.169149 WIN < 300 KWh 0.035643 0.000422 0.000855 (0.000007) 0.000384 0.169400 SUM NEXT 900 KWH 0.009245 0.000422 0.000855 (0.000007) 0.000384 0.096742 WIN NEXT 900 KWh 0.025964 0.000422 0.000855 (0.000007) 0.000384 0.091821 SUM > 1200 KWh 0.019979 0.000422 0.000855 (0.000007) 0.000384 0.099575 WIN > 1200 KWh 0.016240 0.000422 0.000855 (0.000007) 0.000384 0.089821 CEILING LIMIT 0.039858 0.000542 0.000855 (0.000007) 0.000384 0.186025
Page 2 of 8 31 ATLANTIC CITY ELECTRIC APPENDIX A STIPULATION OF SETTLEMENT AUGUST 1, 1999 UNBUNDLED RATE SUMMARY
TARIFF BLOCKS CUST BGS MTC NNC TRANS DISTR DSM AGS-SECONDARY CUST 92.46 DEMAND CHARGE Including 25 KW 1.13 5.43 26-900 KW 1.13 5.43 901-10000 KW 1.12 5.39 Excess Demand 1.11 5.30 Winter Demand 0.64 3.07 Reactive Demand 0.07 0.35 ENERGY CHARGE First 82500 KWh 0.050681 0.005792 0.019109 - 0.004532 0.000638 > 82500 KWh 0.050681 0.004042 0.019109 - 0.004384 0.000638 > 330 KW demand 0.050681 0.004042 0.019109 - 0.004384 0.000638 AGS-PRIMARY CUST 92.46 DEMAND CHARGE Including 25 KW 1.74 4.81 26-900 KW 1.74 4.81 901-10000 KW 1.73 4.78 Excess Demand 1.70 4.71 Winter Demand 0.99 2.72 Reactive Demand 0.10 0.33 ENERGY CHARGE First 82500 KWh 0.047292 0.009444 0.018546 - 0.005807 0.000404 > 82500 KWh 0.047292 0.007713 0.018546 - 0.005648 0.000404 > 330 KW demand 0.047292 0.007713 0.018546 - 0.005648 0.000404
TARIFF BLOCKS DECOM LC-904 REG TOTAL UNCOLL. ASSETS RATE AGS-SECONDARY CUST 92.46 DEMAND CHARGE Including 25 KW 6.56 26-900 KW 6.56 901-10000 KW 6.52 Excess Demand 6.41 Winter Demand 3.71 Reactive Demand 0.43 ENERGY CHARGE First 82500 KWh 0.000855 (0.000244) 0.000384 0.081746 > 82500 KWh 0.000855 (0.000244) 0.000384 0.079849 > 330 KW demand 0.000855 (0.000244) 0.000384 0.079849 AGS-PRIMARY CUST 92.46 DEMAND CHARGE Including 25 KW 6.56 26-900 KW 6.56 901-10000 KW 6.52 Excess Demand 6.41 Winter Demand 3.71 Reactive Demand 0.43 ENERGY CHARGE First 82500 KWh 0.000855 0.000047 0.000384 0.082779 > 82500 KWh 0.000855 0.000047 0.000384 0.080889 > 330 KW demand 0.000855 0.000047 0.000384 0.080889
Page 3 of 8 32 ATLANTIC CITY ELECTRIC APPENDIX A STIPULATION OF SETTLEMENT AUGUST 1, 1999 UNBUNDLED RATE SUMMARY
TARIFF BLOCKS CUST BGS MTC NNC TRANS DISTR AGT-SECONDARY CUST 268.65 DEMAND CHARGE PERIOD 1 (SUMMER ON) 1.87 2.25 PERIOD 2 (SUMMER OFF) - 1.42 PERIOD 3 (WINTER ON) 1.42 1.71 PERIOD 4 (WINTER OFF) - 1.22 REACTIVE DEMAND 0.07 0.29 ENERGY CHARGE PERIOD 1 (SUMMER ON) 0.058683 0.020928 0.019109 - 0.012737 PERIOD 2 (SUMMER OFF) 0.040135 0.000002 0.019109 - 0.005491 PERIOD 3 (WINTER ON) 0.058683 0.009161 0.019109 - 0.011764 PERIOD 4 (WINTER OFF) 0.040135 0.000012 0.019109 - 0.005099 AGT-PRIMARY CUST 268.65 DEMAND CHARGE PERIOD 1 (SUMMER ON) 1.94 2.18 PERIOD 2 (SUMMER OFF) - 1.42 PERIOD 3 (WINTER ON) 1.48 1.66 PERIOD 4 (WINTER OFF) - 1.22 REACTIVE DEMAND 0.08 0.28 ENERGY CHARGE PERIOD 1 (SUMMER ON) 0.056936 0.010217 0.018546 - 0.021967 PERIOD 2 (SUMMER OFF) 0.038942 0.001775 0.018546 - 0.006007 PERIOD 3 (WINTER ON) 0.056936 0.008037 0.018546 - 0.015295 PERIOD 4 (WINTER OFF) 0.038942 0.000010 0.018546 - 0.008636
TARIFF BLOCKS DSM DECOM LC-904 REG TOTAL UNCOLL. ASSETS RATE AGT-SECONDARY CUST 268.65 DEMAND CHARGE PERIOD 1 (SUMMER ON) 4.12 PERIOD 2 (SUMMER OFF) 1.42 PERIOD 3 (WINTER ON) 3.14 PERIOD 4 (WINTER OFF) 1.22 REACTIVE DEMAND 0.36 ENERGY CHARGE PERIOD 1 (SUMMER ON) 0.000475 0.000855 (0.000001) 0.000384 0.113169 PERIOD 2 (SUMMER OFF) 0.000475 0.000855 (0.000001) 0.000384 0.066450 PERIOD 3 (WINTER ON) 0.000475 0.000855 (0.000001) 0.000384 0.100430 PERIOD 4 (WINTER OFF) 0.000475 0.000855 (0.000001) 0.000384 0.066068 AGT-PRIMARY CUST 268.65 DEMAND CHARGE PERIOD 1 (SUMMER ON) 4.12 PERIOD 2 (SUMMER OFF) 1.42 PERIOD 3 (WINTER ON) 3.14 PERIOD 4 (WINTER OFF) 1.22 REACTIVE DEMAND 0.36 ENERGY CHARGE PERIOD 1 (SUMMER ON) 0.000430 0.000855 - 0.000384 0.109335 PERIOD 2 (SUMMER OFF) 0.000430 0.000855 - 0.000384 0.066939 PERIOD 3 (WINTER ON) 0.000430 0.000855 - 0.000384 0.100483 PERIOD 4 (WINTER OFF) 0.000430 0.000855 - 0.000384 0.067803
Page 4 of 8 33 ATLANTIC CITY ELECTRIC APPENDIX A STIPULATION OF SETTLEMENT AUGUST 1, 1999 UNBUNDLED RATE SUMMARY
TARIFF BLOCKS CUST BGS MTC NNC TRANS DISTR AGT-SUBTRANSMISSION CUST 268.65 DEMAND CHARGE PERIOD 1 (SUMMER ON) 1.99 2.13 PERIOD 2 (SUMMER OFF) - 1.42 PERIOD 3 (WINTER ON) 1.52 1.62 PERIOD 4 (WINTER OFF) - 1.22 REACTIVE DEMAND 0.10 0.26 ENERGY CHARGE PERIOD 1 (SUMMER ON) 0.047660 0.042172 0.018200 - 0.006319 PERIOD 2 (SUMMER OFF) 0.032606 0.009079 0.018200 - 0.003898 PERIOD 3 (WINTER ON) 0.047660 0.027827 0.018200 - 0.005597 PERIOD 4 (WINTER OFF) 0.032606 0.008122 0.018200 - 0.003851 AGT-TRANSMISSION CUST 268.65 DEMAND CHARGE PERIOD 1 (SUMMER ON) 2.88 1.24 PERIOD 2 (SUMMER OFF) - 1.42 PERIOD 3 (WINTER ON) 2.19 0.94 PERIOD 4 (WINTER OFF) - 1.22 REACTIVE DEMAND 0.09 0.26 ENERGY CHARGE PERIOD 1 (SUMMER ON) 0.046303 0.041904 0.018124 - 0.007689 PERIOD 2 (SUMMER OFF) 0.031679 0.009181 0.018124 - 0.004618 PERIOD 3 (WINTER ON) 0.046303 0.027792 0.018124 - 0.006773 PERIOD 4 (WINTER OFF) 0.031679 0.008220 0.018124 - 0.004559
TARIFF BLOCKS DSM DECOM LC-904 REG TOTAL UNCOLL. ASSETS RATE AGT-SUBTRANSMISSION CUST 268.65 DEMAND CHARGE PERIOD 1 (SUMMER ON) 4.12 PERIOD 2 (SUMMER OFF) 1.42 PERIOD 3 (WINTER ON) 3.14 PERIOD 4 (WINTER OFF) 1.22 REACTIVE DEMAND 0.36 ENERGY CHARGE PERIOD 1 (SUMMER ON) 0.000376 0.000855 - 0.000384 0.115967 PERIOD 2 (SUMMER OFF) 0.000377 0.000855 - 0.000384 0.065399 PERIOD 3 (WINTER ON) 0.000376 0.000855 - 0.000384 0.100900 PERIOD 4 (WINTER OFF) 0.000377 0.000855 - 0.000384 0.064395 AGT-TRANSMISSION CUST 268.65 DEMAND CHARGE PERIOD 1 (SUMMER ON) 4.12 PERIOD 2 (SUMMER OFF) 1.42 PERIOD 3 (WINTER ON) 3.14 PERIOD 4 (WINTER OFF) 1.22 REACTIVE DEMAND 0.36 ENERGY CHARGE PERIOD 1 (SUMMER ON) (0.000787) 0.000855 - 0.000384 0.114473 PERIOD 2 (SUMMER OFF) (0.000226) 0.000855 - 0.000384 0.064597 PERIOD 3 (WINTER ON) (0.000620) 0.000855 - 0.000384 0.099612 PERIOD 4 (WINTER OFF) (0.000215) 0.000855 - 0.000384 0.063606
Page 5 of 8 34 ATLANTIC CITY ELECTRIC APPENDIX A STIPULATION OF SETTLEMENT AUGUST 1, 1999 UNBUNDLED RATE SUMMARY
TARIFF BLOCKS CUST BGS MTC NNC TRANS DISTR DSM TGS CUST 88.43 DEMAND CHARGE Including 25 KW 2.50 2.99 26-900 KW 2.50 2.99 901-10000 KW 2.49 2.98 Excess Demand 2.45 2.93 Winter Demand 1.42 1.69 Reactive Demand 0.11 0.25 ENERGY CHARGE First 82500 KWh 0.039889 0.016119 0.018124 - 0.006425 (0.001338) > 82500 KWh 0.039889 0.014257 0.018124 - 0.006251 (0.001289) > 330 KW demand 0.039889 0.012952 0.018124 - 0.006251 0.000016
TARIFF BLOCKS DECOM LC-904 REG TOTAL UNCOLL. ASSETS RATE TGS CUST 88.43 DEMAND CHARGE Including 25 KW 5.50 26-900 KW 5.50 901-10000 KW 5.47 Excess Demand 5.38 Winter Demand 3.11 Reactive Demand 0.36 ENERGY CHARGE First 82500 KWh 0.000855 - 0.000384 $0.080459 > 82500 KWh 0.000855 - 0.000384 $0.078472 > 330 KW demand 0.000855 - 0.000384 $0.078472
Page 6 of 8 35 APPENDIX A ATLANTIC CITY ELECTRIC COMPANY STIPULATION OF SETTLEMENT 1999 UNBUNDLED RATE SUMMARY
TARIFF BLOCKS BGS MTC NNC TRANS DISTR DSM DECOM $ - EQUIP/CUST ENERGY SPL 1000 LUMENS-INC 1.038480 0.223430 0.689518 0.107433 3.41 1.2292 0.023 0.031 2500 LUMENS-INC 2.033791 0.437572 1.350373 0.214866 5.90 2.4043 0.045 0.060 4000 LUMENS-INC 3.292919 0.708475 2.186394 0.354529 8.14 3.8852 0.072 0.098 6000 LUMENS-INC 4.511274 0.970606 2.995344 0.483448 10.88 5.3212 0.099 0.134 3500 LUMENS-MV 1.278314 0.275031 0.848760 0.139663 5.81 1.5169 0.028 0.038 6800 LUMENS-MV 2.045783 0.440153 1.358335 0.214866 7.71 2.4246 0.045 0.061 11000 LUMENS-MV 2.870811 0.617658 1.906128 0.300812 9.76 3.3987 0.063 0.085 20000 LUMENS-MV 4.573631 0.984022 3.036747 0.483448 13.99 5.4094 0.101 0.136 35000 LUMENS-MV 7.897728 1.699205 5.243843 0.837977 22.23 9.3322 0.174 0.235 55000 LUMENS-MV 11.099510 2.388073 7.369725 1.181762 30.18 13.1104 0.244 0.330 11000 LUMENS-HPS 1.793957 0.385972 1.191131 0.193379 7.10 2.1266 0.039 0.053 30000 LUMENS-HPS 4.209084 0.905589 2.794699 0.451218 13.10 4.9791 0.092 0.125 50 WATT-HPS-COBRAHD-OVHD 0.623568 0.134161 0.414029 0.064460 6.45 0.7433 0.014 0.018 70 WATT-HPS-COBRAHD-OVHD 0.846613 0.182150 0.562125 0.085946 6.67 1.0083 0.019 0.025 100 WATT-HPS-COBRAHD-OVHD 1.177584 0.253359 0.781879 0.128919 6.96 1.3997 0.026 0.035 150 WATT-HPS-COBRAHD-OVHD 1.693227 0.364300 1.124249 0.182636 7.52 2.0091 0.037 0.050 250 WATT-HPS-COBRAHD-OVHD 2.971541 0.639331 1.973010 0.311555 10.60 3.5202 0.065 0.088 400 WATT-HPS-COBRAHD-OVHD 4.633590 0.996922 3.076558 0.494191 12.09 5.4714 0.102 0.138 150 WATT-HPS-SHOEBOX-OVHD 1.693227 0.364300 1.124249 0.182636 9.25 2.0120 0.037 0.050 250 WATT-HPS-SHOEBOX-OVHD 2.971541 0.639331 1.973010 0.311555 11.88 3.5235 0.065 0.088 400 WATT-HPS-SHOEBOX-OVHD 4.633590 0.996922 3.076558 0.494191 13.55 5.4777 0.102 0.138 50 WATT-HPS-POSTTOP-OVHD 0.623568 0.134161 0.414029 0.064460 7.17 0.7437 0.014 0.018 100 WATT-HPS-POSTTOP-OVHD 1.177584 0.253359 0.781879 0.128919 7.73 1.4006 0.026 0.035 150 WATT-HPS-POSTTOP-OVHD 1.693227 0.364300 1.124249 0.182636 9.08 2.0117 0.037 0.050 150 WATT-HPS-FLOOD-OVHD 1.693227 0.364300 1.124249 0.182636 7.35 2.0087 0.037 0.050 250 WATT-HPS-FLOOD-OVHD 2.971541 0.639331 1.973010 0.311555 9.20 3.5157 0.065 0.088 400 WATT-HPS-FLOOD-OVHD 4.633590 0.996922 3.076558 0.494191 11.65 5.4689 0.102 0.138 400 WATT-MH-FLOOD-OVHD 4.633590 0.996922 3.076558 0.494191 14.46 5.4815 0.102 0.138 1000 WATT-MH-FLOOD-OVHD 10.878863 2.340600 7.223222 1.160275 24.25 12.8193 0.239 0.323 50 WATT-HPS-COBRAHD-UGRD 0.623568 0.134161 0.414029 0.064460 9.99 0.7443 0.014 0.018 70 WATT-HPS-COBRAHD-UGRD 0.846613 0.182150 0.562125 0.085946 10.21 1.0099 0.019 0.025 100 WATT-HPS-COBRAHD-UGRD 1.177584 0.253359 0.781879 0.128919 10.49 1.4028 0.026 0.035 150 WATT-HPS-COBRAHD-UGRD 1.693227 0.364300 1.124249 0.182636 11.06 2.0142 0.037 0.050 250 WATT-HPS-COBRAHD-UGRD 2.971541 0.639331 1.973010 0.311555 13.26 3.5265 0.065 0.088 400 WATT-HPS-COBRAHD-UGRD 4.633590 0.996922 3.076558 0.494191 14.74 5.4824 0.102 0.138 150 WATT-HPS-SHOEBOX-UGRD 1.693227 0.364300 1.124249 0.182636 12.79 2.0158 0.037 0.050 250 WATT-HPS-SHOEBOX-UGRD 2.971541 0.639331 1.973010 0.311555 15.42 3.5304 0.065 0.088 400 WATT-HPS-SHOEBOX-UGRD 4.633590 0.996922 3.076558 0.494191 17.09 5.4901 0.102 0.138 50 WATT-HPS-POSTTOP-UGRD 0.623568 0.134161 0.414029 0.064460 8.84 0.7441 0.014 0.018 100 WATT-HPS-POSTTOP-UGRD 1.177584 0.253359 0.781879 0.128919 9.40 1.4021 0.026 0.035 150 WATT-HPS-POSTTOP-UGRD 1.693227 0.364300 1.124249 0.182636 12.82 2.0158 0.037 0.050 150 WATT-HPS-FLOOD-UGRD 1.693227 0.364300 1.124249 0.182636 11.68 2.0148 0.037 0.050 250 WATT-HPS-FLOOD-UGRD 2.971541 0.639331 1.973010 0.311555 13.51 3.5271 0.065 0.088 400 WATT-HPS-FLOOD-UGRD 4.633590 0.996922 3.076558 0.494191 15.18 5.4840 0.102 0.138 400 WATT-MH-FLOOD-UGRD 4.633590 0.996922 3.076558 0.494191 18.08 5.4927 0.102 0.138 1000 WATT-MH-FLOOD-UGRD 10.878863 2.340600 7.223222 1.160275 27.85 12.8414 0.239 0.323 ORN STANDARDS-BEFORE 1-17-86 - - - - 0.57 - - (0.000) NON-ORN STANDARDS-AFTER 1-17-86 - - - - 0.83 - - (0.000)
TARIFF BLOCKS UNCOLL. REG TOTAL ACCTS. ASSETS RATE SPL 1000 LUMENS-INC - 0.011 6.77 2500 LUMENS-INC - 0.032 12.48 4000 LUMENS-INC - 0.043 18.78 6000 LUMENS-INC - 0.064 25.46 3500 LUMENS-MV - 0.021 9.95 6800 LUMENS-MV - 0.032 14.33 11000 LUMENS-MV - 0.043 19.04 20000 LUMENS-MV - 0.064 28.78 35000 LUMENS-MV - 0.107 47.75 55000 LUMENS-MV - 0.150 66.06 11000 LUMENS-HPS - 0.021 12.90 30000 LUMENS-HPS - 0.054 26.71 50 WATT-HPS-COBRAHD-OVHD - 0.011 8.48 70 WATT-HPS-COBRAHD-OVHD - 0.011 9.41 100 WATT-HPS-COBRAHD-OVHD - 0.011 10.77 150 WATT-HPS-COBRAHD-OVHD - 0.021 13.00 250 WATT-HPS-COBRAHD-OVHD - 0.043 20.21 400 WATT-HPS-COBRAHD-OVHD - 0.064 27.07 150 WATT-HPS-SHOEBOX-OVHD - 0.021 14.73 250 WATT-HPS-SHOEBOX-OVHD - 0.043 21.50 400 WATT-HPS-SHOEBOX-OVHD - 0.064 28.54 50 WATT-HPS-POSTTOP-OVHD - 0.011 9.19 100 WATT-HPS-POSTTOP-OVHD - 0.011 11.55 150 WATT-HPS-POSTTOP-OVHD - 0.021 14.57 150 WATT-HPS-FLOOD-OVHD - 0.021 12.83 250 WATT-HPS-FLOOD-OVHD - 0.043 18.80 400 WATT-HPS-FLOOD-OVHD - 0.064 26.62 400 WATT-MH-FLOOD-OVHD - 0.064 29.44 1000 WATT-MH-FLOOD-OVHD - 0.150 59.39 50 WATT-HPS-COBRAHD-UGRD - 0.011 12.02 70 WATT-HPS-COBRAHD-UGRD - 0.011 12.95 100 WATT-HPS-COBRAHD-UGRD - 0.011 14.30 150 WATT-HPS-COBRAHD-UGRD - 0.021 16.55 250 WATT-HPS-COBRAHD-UGRD - 0.043 22.88 400 WATT-HPS-COBRAHD-UGRD - 0.064 29.73 150 WATT-HPS-SHOEBOX-UGRD - 0.021 18.28 250 WATT-HPS-SHOEBOX-UGRD - 0.043 25.04 400 WATT-HPS-SHOEBOX-UGRD - 0.064 32.08 50 WATT-HPS-POSTTOP-UGRD - 0.011 10.87 100 WATT-HPS-POSTTOP-UGRD - 0.011 13.22 150 WATT-HPS-POSTTOP-UGRD - 0.021 18.31 150 WATT-HPS-FLOOD-UGRD - 0.021 17.17 250 WATT-HPS-FLOOD-UGRD - 0.043 23.13 400 WATT-HPS-FLOOD-UGRD - 0.064 30.17 400 WATT-MH-FLOOD-UGRD - 0.064 33.08 1000 WATT-MH-FLOOD-UGRD - 0.150 63.01 ORN STANDARDS-BEFORE 1-17-86 - - 0.57 NON-ORN STANDARDS-AFTER 1-17-86 - - 0.83
Page 7 of 8 36
TARIFF BLOCKS BGS MTC NNC TRANS DISTR DSM DECOM $ - EQUIP/CUST ENERGY POSTS - - - - 0.20 - - (0.000) CSL HPS50 0.623568 (0.263325) 0.414029 0.064460 2.65 0.7397 0.014 0.019 HPS70 0.846613 (0.357515) 0.562125 0.085946 2.87 1.0029 0.019 0.025 HPS100 1.177584 (0.497280) 0.781879 0.128919 3.17 1.3903 0.026 0.035 HPS150 1.693227 (0.715029) 1.124249 0.182636 3.74 1.9953 0.037 0.050 HPS250 2.971541 (1.254846) 1.973010 0.311555 5.00 3.4881 0.065 0.088 HPS400 4.633590 (1.956710) 3.076558 0.494191 6.50 5.4215 0.102 0.138 STANDARDS - - - - (0.01) 5.8908 - (0.000) DDC Service and Demand - 0.099679 - 0.000838 0.223678 - 0.000173 0.000234 Energy 0.009976 0.585386 0.005235 0.000838 1.576590 - 0.0002 0.0002 TARIFF BLOCKS UNCOLL. REG TOTAL ACCTS. ASSETS RATE POSTS - - 0.20 CSL HPS50 - 0.011 4.27 HPS70 - 0.011 5.07 HPS100 - 0.011 6.22 HPS150 - 0.021 8.13 HPS250 - 0.043 12.68 HPS400 - 0.064 18.48 STANDARDS - (0.000) 5.89 DDC Service and Demand - 0.00011 0.324710 Energy - 0.00011 2.178539
Page 8 of 8 37 SCHEDULE A ATLANTIC CITY ELECTRIC COMPANY STIPULATION OF SETTLEMENT
ESTIMATED AMOUNTS $ (000) --------- REGULATORY CREDITS: ANTICIPATED LEAC OVER RECOVERY @ 7/31/99 $ 44,409 ANTICIPATED DSM UNDER SPENDING @ 7/31/99 $ 6,949 -------- TOTAL DOLLARS AVAILABLE $ 51,358 ======== REGULATORY ASSETS: ESTIMATED GRFT BALANCE @ 7/31/99 $ 30,017 ESTIMATED SUSQUEHANNA BALANCE @ 7/31/99 $ 20,008 -------- TOTAL UNAMORTIZED BALANCE $ 50,025 ======== CORRESPONDING REDUCTION IN REGULATORY ASSET CHARGES: REMOVE GRFT FROM BASE RATES $ 13,546 REMOVE SUSQUEHANNA FROM BASE RATES $ 22,389 -------- TOTAL RATE REDUCTION $ 35,935 ========
38 SCHEDULE B ATLANTIC CITY ELECTRIC COMPANY STIPULATION OF SETTLEMENT Transferred Units
STATION / UNITS FUEL UNIT CAPACITY (MW) Missouri Ave. CT's Unit B Oil 20 Unit C Oil 20 Unit D Oil 20 --- SUBTOTAL M/A CT'S 60 Carl's Corner CT's Unit 1 Gas/Oil 37 Unit 2 37 --- SUBTOTAL CC CT'S 74 Cedar CT's Unit 1 Oil 46 Unit 2 Oil 22 --- SUBTOTAL CEDAR CT'S 68 Middle CT's Unit 1 Oil 20 Unit 2 Oil 20 Unit 3 Oil 37 --- SUBTOTAL MIDDLE CT'S 77 Cumberland CT Gas/Oil 84 Sherman Ave. CT Gas/Oil 81 Mickleton CT Gas/Oil 59 Deepwater CT Gas/Oil 20 --- SUBTOTAL CT'S 523 === Deepwater Steam Units Unit 1 Unit 4 Oil 86 Unit 6/8 Oil 54 Coal 80 --- SUBTOTAL STEAM UNITS 220 === TOTAL TRANSFERRED UNITS CAPACITY 743 ===
39 SCHEDULE C ATLANTIC CITY ELECTRIC COMPANY STIPULTION OF SETTLEMENT
RESTRUCTURING - RELATED ESTIMATED CAPITAL EXPENDITURES: COSTS $(000) ------ CUSTOMER CARE SYSTEM ENHANCEMENTS $4,323 BALANCING & SETTLING SYSTEM $ 260 LOAD STUDY PROJECT FOR LOAD PROFILES $ 860 ------ TOTAL CAPITAL EXPENDITURES $5,443 ======
40 SCHEDULE D ATLANTIC CITY ELECTRIC COMPANY STIPULATION OF SETTLEMENT
RESTRUCTURING - RELATED ESTIMATED O&M EXPENDITURES: COSTS $000 ---- REGULATORY PROCEEDINGS $ 6,566 CONTINUING OPERATIONS RELATED TO RETAIL CHOICE: CUSTOMER CARE $ 9,198 BALANCING & SETTLEMENT $ 520 LOAD PROFILING $ 250 ------- TOTAL O & M EXPENDITURES $16,534 =======
-----END PRIVACY-ENHANCED MESSAGE-----