4901:1-20-03 Filing and contents of transition plans.

(A) Each electric utility supplying retail electric service in this state shall file a proposed transition plan. Such proposed plans shall be filed with the commission in the form of an application for approval of an electric transition plan (xx-xxx-EL-ETP). Twenty-six copies plus an original of the application shall be filed.

For the following other documents filed in an "ETP" proceeding, twenty-six copies plus an original shall also be filed: amendments to transition plans; preliminary objections; utility supplemental direct expert testimony; intervenor direct; expert testimony; and rebuttal testimony. For all other documents filed in an "ETP" proceeding not listed above, ten copies plus an original must be filed.

(B) Pursuant to section 4928.31 of the Revised Code, all proposed plans shall include:

(1) A rate unbundling plan designated as part A. The rate unbundling plan shall be consistent with the requirements of appendix A to this rule.

(2) A corporate separation plan designated as part B. The corporate separation plan shall be consistent with the requirements of rule 4901:1-20-16 of the Administrative Code.

(3) An operational support plan designated as part C. The operational support plan shall be consistent with the requirements of appendix B to this rule.

(4) An employee assistance plan designated as part D. The employee assistance plan shall be consistent with the requirements of appendix C to this rule.

(5) A consumer education plan designated as part E, which shall comply with the commission's finding and order of November 30, 1999, in In the Matter of the Commission's Promulgation of Rules for Electric Transition Plans and of a Consumer Education Plan Pursuant to Chapter 4928, Revised Code , Case No. 99-1141-EL-ORD (attachment II).

(C) In addition, all proposed plans shall comply with the following format:

(1) If an electric utility seeks to recover transition revenues, it shall submit an application for such as part of the company's transition plan and designate it as part F. Any application for receipt of transition revenues shall be consistent with the requirements of appendix D to this rule.

(2) If an electric utility, as part of its transition plan, proposes a plan for independent operation of transmission facilities, it shall submit that proposed plan as part of the company's transition plan and designate it as part G. Any plan for independent operation of transmission facilities shall be consistent with the requirements of rule 4901:1-20-17 of the Administrative Code. If an electric utility does not propose a plan for independent operation of transmission facilities, it shall include an explanation in its transition plan filing(designated as part G) that indicates how the electric utility's operation of transmission facilities will comply with Chapter 4928. of the Revised Code.

(3) Each electric utility shall submit a plan for a shopping incentive and designate it as part H. Any application that includes a shopping incentive proposal shall be consistent with the requirements of appendix E to this rule.

(4) If the commission has issued a ruling in which it deferred an issue or matter to the utility's transition plan case, the utility shall also address such issue/matter in its transition plan filing and designate it as part I.

(D) A complete set of work papers must be filed with a transition plan application. Work papers must include, but are not limited to, any and all supporting work papers prepared by the electric utility for the application and a narrative or other support of assumptions made of working paper schedule amounts. Work papers shall be marked, organized, and indexed according to schedules to which they relate and must identify the witness that will sponsor it. Data contained in the work papers shall be footnoted so as to identify any source document used.

(E) All schedules, testimonies, and work papers included in a transition plan application must be available in spreadsheet, word processing, or an electronic form compatible with personal computers.

(F) A transition plan application must include a complete set of testimony of utility personnel or other expert witnesses. This testimony shall be in question and answer format and shall be in support of the utility's proposed transition plan recommendations. This testimony shall fully and completely address and support all schedules and significant issues identified by the utility.

Appendix A Unbundling Plan

(A) Purpose and scope

Division (A) (1) of section 4828.31 of the Revised Code, prescribes that each electric utility file a rate unbundling plan that is consistent with division (A) (1) to (A)(7) of section 4928.34 of the Revised Code, and any rules adopted by the commission under division (A) of section 4928.06 of the Revised Code. The plan is to be filed no later than ninety days after October 5, 1999. The rules as prescribed herein are designed to provide the commission with the necessary information and material to perform a thorough and expeditious review of the unbundling plan.

(B) Definitions

(1) "Current Rates" are those rates reflected in an electric utility's schedule of rates and charges in effect on October 5, 1999.

(2) "Unbundled Rates" are the current rates unbundled, prior to any adjustments as required by Chapter 4928. of the Revised Code.

(3) "Adjusted Unbundled Rates" are the current rates unbundled and adjusted as required by Chapter 4928. of the Revised Code.

(4) "Universal Service Fund" is the fund of the state treasury established under section 4928.51 of the Revised Code, for the exclusive purpose of providing funding for low-income customer assistance programs and the consumer education program authorized under section 4928.56 of the Revised Code and for paying the administrative costs of those programs.

(5) "Energy Efficiency Fund" is the fund of the state treasury established under section 4928.61 of the Revised Code, for the exclusive purposes of funding the energy efficiency revolving loan program created under section 4928.62 of the Revised Code, and for paying the program's administrative costs.

(6) "Regulatory Assets" is the unamortized net regulatory assets that are capitalized or deferred on the regulatory books of the utility, pursuant to an order or practice of the commission or pursuant to generally accepted accounting principles as a result of a prior commission rate-making decision, and that would otherwise have been charged to expense as incurred or would not have been capitalized or otherwise deferred for future regulatory consideration absent commission action. For the purposes of unbundling, the regulatory assets are those that are included in the applicant's current rates as approved by this commission in the electric utility's last rate case.

(C) Transition plan content requirements for the unbundling plan

The filing requirements contain the minimum information that utilities are required to submit with their unbundling plans. If the electric utility believes additional information is necessary to support its case, it should supplement the minimum requirements with additional information as necessary. In addition, the commission may require utilities to supply information to supplement these requirements during the course of the commission's staff investigation.

The rates for all schedules shall be unbundled consistent with division (A) (1) to (A)(7) of section 4928.34 of the Revised Code, and shall include the unbundled components for electric generation, transmission, distribution, and such other unbundled components as the commission requires. Pursuant to division (A) of section 4928.34 of the Revised Code, the commission shall not approve or prescribe a transition plan unless the following conditions concerning the unbundling plan are met:

(1) Generation component

(a) The unbundled generation component shall reflect the production-related portion of rates and shall reflect all adjustments mandated by law. The generation component shall be further unbundled to provide separate rates for the following two items:

(i) Transition charge

For those electric utilities that request approval to collect transition charges, the generation component shall be further unbundled to include a transition charge. This rate should be consistent with the valuation of the electric utility's transition revenues as further discussed in paragraph (C)(2) of appendix D to this rule.

(ii) Regulatory asset component

Although regulatory assets are a part of the total transition costs, in its filed schedules, the electric utility shall include a separate rate for the recovery of regulatory assets as defined by Chapter 4928. of the Revised Code, and commission rules concerning regulatory assets.

(b) Electric fuel component (EFC)

The EFC shall be a part of the unbundled generation rate and not a separate rate as currently provided for in the utilities' filed tariffs. Based on division (A)(3) of section 4928.34 and division (A)(26) of section 4928.01 of the Revised Code, the fuel cost of the unbundled generation component shall equal the costs attributable to the electric utility's EFC rate in effect on October 5, 1999, less any costs in the EFC rate that are to be recovered as regulatory assets under the electric utility's transition cost filing.

(c) The residential tariff schedules shall reflect that the generation component shall be or is reduced by five per cent for all residential customers, unless otherwise determined by the commission.

(2) Transmission component

The unbundled transmission component of retail electric service shall equal the network service tariff rates determined by the federal energy regulatory commission (FERC) that are in effect on the date of the approval of the transition plan. The FERC rate shall be applicable to each particular customer class and rate schedule.

(a) The unbundled transmission component shall include, at a minimum, the following ancillary services that are currently included in the utility's generation or transmission functions. Such services need to be separated from their functions and included as separate charges in the utility's filed schedules:

(i) Scheduling, system control, and dispatch service;

(ii) Reactive supply and voltage control from generation sources service;

(iii) Regulation and frequency response service;

(iv) Energy imbalance service;

(v) Operating reserve - spinning reserve service; and

(vi) Operating reserve - supplemental reserve service.

(b) For the above listed services, the following definitions apply:

(i) "Ancillary Services" are the interconnected operations services identified by FERC Order No. 888 as necessary to effect a transfer of electricity between purchasing and selling entities and which a transmission provider must include in an open access transmission tariff (OATT).

(ii) "Energy Imbalance Service" provides energy correction for an hourly mismatch between a transmission customer's energy supply and the demand served. If energy imbalance service is not currently in bundled rates and, therefore, will not be one of the unbundled ancillary service charges, it should be addressed in a separate tariff provision related to certified suppliers of retail electric generation service.

(iii) "Operating Reserve, Spinning Reserve Service" provides additional capacity from electricity generators that are on-line, loaded to less than their maximum output, and available to serve customer demand immediately should a contingency occur.

(iv) "Operating Reserve, Supplemental Reserve Service" provides additional capacity from electricity generators that can be used to respond to a contingency within a short period, usually ten minutes.

(v) "Reactive Supply and Voltage Control From Generating Sources Service" provides reactive supply through changes to generator reactive output to maintain transmission line voltage and facilitate electricity transfers.

(vi) "Regulation and Frequency Response Service" provides for following the moment-to-moment variations in the demand or supply in a control area and maintaining scheduled interconnection frequency.

(vii) "Scheduling, System Control, and Dispatch Service" provides for: scheduling; confirming and implementing an interchange schedule with other control areas, including intermediary control areas providing transmission service; and ensuring operational security during the interchange transaction.

(c) The applicant shall:

(i) Provide a copy of its current FERC OATT;

(ii) Identify what portions of the FERC OATT in effect are or may be subject to refund;

(iii) Identify rules and regulations that need to be modified to facilitate retail access and aggregation;

(iv) Provide a plan on how it intends to alter its FERC OATT, if it intends to do so, to facilitate retail access and aggregation, including a complete set of marked-up revisions to its OATT and a timeline that it intends to follow to secure approval of such revisions;

(v) Provide verification that its unbundled transmission rates for each tariff schedule and contract are equal to the OATT rates; and

(vi) Indicate how it will address any refunds ordered by the FERC or any rate changes, including ancillary services, in its filed tariffs.

(3) Distribution component

The distribution component shall be equal to the difference between the sum of the transmission and distribution rates in effect on October 5, 1999, which were based on the most recent rate proceeding of the utility for which the schedules were established, and the tariff rates for the transmission component as discussed above and approved by the FERC. This methodology will result in the difference between the FERC transmission rate and the transmission rate currently in the bundled rates being reflected in the distribution component.

(4) Other unbundled components

The following are riders that are to be included in the electric utility's filed unbundled plan:

(a) KWh tax rider - This rider provides for recovery of the gross receipts tax, which continues until April 30, 2001, and for the recovery of the kWh tax starting on May 1, 2001. This two-part rider should be included in the filed tariffs of the electric utility and at a minimum should be referenced in each filed schedule of the applicant. The rate and structure of the rider should be consistent with section 5727.81 of the Revised Code.

The first part of the rider shall call for the application to each rate or charge in the utility's rate schedules of a factor based upon the effective gross receipts tax rate in the utility's last rate case, which factor shall be intended to provide the utility with sufficient funds to satisfy its obligations for payment of gross receipts tax on revenues from bills rendered from January 1, 2000 through April 30, 2000. Application of this part of the rider is premised on the electric utility's unbundled rates excluding any provision for gross receipts taxes.

The second part of the rider shall call for the application of the tax rates in section 5727.81 of the Revised Code, and shall be effective starting with bills rendered on May 1, 2001.

(b) Energy efficiency fund rider - This rider should be included in the filed tariffs of the electric utility and at a minimum shall be referenced in each of the electric utility's proposed, filed schedules. The rider will be established by the commission as a uniform statewide amount to implement the provisions of section 4928.61 of the Revised Code.

(c) Universal service fund rider - This rider should be included in the filed tariffs of the electric utility and at a minimum shall be referenced in each of the applicant's proposed, filed schedules.

(d) Emission fee rider if applicable.

(5) Additional requirements

(a) With its proposed unbundled schedules, the electric utility must provide unbundled schedules adjusted to reflect any base rate reductions on file with the commission and scheduled to be in effect by December 31, 2005, under rate settlements in effect on the effective date of Chapter 4928. of the Revised Code.

(b) The total of all unbundled components in the rate unbundling plan, during the market development period, are capped and shall be equal to the total of all rates and charges in effect under the applicable bundled schedule of the electric utility pursuant to section 4905.30 of the Revised Code, in effect on October 5, 1999, including the transition charge determined, adjusted for any changes in the taxation of electric utilities, the universal service rider, and the temporary rider authorized by section 4928.61 of the Revised Code.

(D) Contract customers

Rates and charges for contract customers must be unbundled in a manner identical to the rules set forth for the unbundling of rate schedules approved under section 4905.30 of the Revised Code. A rate cap is applicable to all customers receiving electric service pursuant to an arrangement approved by the commission under section 4905.31 of the Revised Code, equal to the total of all rates and charges in effect under the arrangement during the term of the agreement, adjusted for any changes in the taxation of electric utilities, the universal service rider, and the temporary rider authorized by section 4928.61 of the Revised Code.

(E) Tariff items

(1) Listed below are items that need to be addressed for electric restructuring, either in each utility's transition plan or at a later time as prescribed by the Revised Code. For each item, indicate how, when, and where (tariff or other) the electric utility will address each item. The list is not exhaustive, therefore, include other items that need to be addressed.

(a) Designation of competitive and non-competitive services

(b) Distribution service requirements of the electric utility

(c) Transmission and ancillary service of the electric utility

(d) Energy imbalance service

(e) Supplier certification*

(f) Consent to service of process*

(g) Minimum service requirements for competitive services of certified suppliers*

(h) Minimum service requirements for non-competitive services of an electric utility*

(i) Universal service*

(j) Low-income customer assistance

(k) Energy efficiency revolving loan program

(l) Net metering*

(m) Back-up supply for self-generators

(n) Dispute resolution*

(o) Procedures for switching suppliers*

(p) Terms and conditions of pricing and services*

(q) Procedures for supplier contract rescission*

(r) Ownership of meters*

(s) Access to meter pulses*

(t) Methods of dealing with aggregation*

(u) Conjunctive billing*

(v) Standard service offer*

* For these items, at the current time, complete tariff terms and conditions are not expected, but a placeholder for future use is required.

(F) Schedules to be filed

(1) At a minimum, the following schedules shall be filed with the unbundling plan:

Schedule

Number Description

UNB-1 Scored copy of proposed tariffs

UNB-2 Scored copy of current tariffs

UNB-3 Revenue summary of current rates

UNB- 3.1 Detailed schedule-by-schedule summary of current rates and revenues

UNB- 3.1 ADJ List of adjustments made to current schedules since last rate case

UNB- 3.2 Detailed schedule-by-schedule summary of new rates

UNB-4 Cost of service study

UNB-5 Revenue summary of current unbundled rates

UNB- 5.1 Detailed schedule-by-schedule summary of unbundled current rates and revenues

UNB- 5.2 Detailed schedule-by schedule summary of unbundled new rates

UNB-6 Summary of UNB- 6.1 schedules

UNB- 6.1 Schedule-by-schedule adjustments to current revenues

UNB- 6.2 Schedule-by schedule adjustments to tariff schedules and contracts that became effective after the electric utility's last rate case.

UNB-7 Revenue summary of proposed adjusted unbundled rates

UNB- 7.1 Detailed schedule-by-schedule summary of proposed adjusted unbundled rates and revenues

UNB- 7.2 Detailed schedule-by-schedule summary of proposed adjusted unbundled new rates

UNB-8 Typical bill comparison

Any of the above schedules that require individual contract information can be filed as confidential information, if accompanied by a request for protective treatment.

(2) A description of the above schedules is as follows:

(a) UNB-1 - Scored copy of proposed tariffs

The electric utility shall provide a copy of its proposed unbundled schedules, with all changes underlined. Designate in the margin the type of proposed change by using the following designations: (C) To signify changed regulations (D) To signify discontinued rate or regulation (N) To signify new rate or regulation (T) To signify a change in text

The electric utility shall include a complete set of tariffs even if certain rules, regulations, and rates are not changed.

The utility must provide narrative rationale underlying the proposed changes to the tariff as scored in the UNB-1 schedules.

(b) UNB-2 - Scored copy of current tariffs

The electric utility shall provide a copy of its current schedules, with all changes underlined. Designate in the margin the type of proposed change by using the following designations: (C) To signify changed regulations (D) To signify discontinued rate or regulation (N) To signify new rate or regulation (T) To signify a change in text

The electric utility shall include a complete set of current tariffs even if certain rules, regulations, and rates are not changed.

The utility must provide narrative rationale underlying the proposed changes to the tariff as scored in the UNB-2 schedules.

(c) UNB-3 - Revenue summary

The electric utility shall provide a schedule that summarizes on an individual schedule and contract basis, the information provided in schedule UNB- 3.1. (See appendix A-1 for the form the schedule should take.)

(d) UNB- 3.1 - Revenue summary of bundled rates

The electric utility shall provide a breakdown of billing determinants and a description of charges, rates, and revenues for each schedule and contract. The current billing determinants, rates, and revenues shall be those that are identical to the determinants, rates, and revenues as filed for revenue verification purposes following the opinion and order of the last rate case proceeding. (See appendix A-2 for the form the schedule should take.)

(e) UNB- 3.1 ADJ

If adjustments were made to any schedules that existed as of the last rate case, the electric utility shall provide a detailed explanation of those adjustments. For example, "the residential customer charge was reduced from $5/month to $4/month on December 1, 1997, approved in Case No. 97-XXX-EL-XXX."

(f) UNB- 3.2 - Revisions since last rate case

If new schedules or contracts have been added since the last rate case, a separate schedule for each new schedule and contract shall be provided and include the most current twelve months of billing determinants, and description of charges, rates, and revenues for each of the new schedules and contracts. If customers were previously served under another schedule prior to the new schedule, it is understood that these customers' billing determinants will also be included in the UNB- 3.1 schedules. (See appendix A-2.)

(g) UNB-4 - Cost of service study

The electric utility must provide a copy of the cost of service study (COSS) that was filed in its last rate case filing to support its proposed rates, adjusted to support the rates that were ultimately approved in the last rate case pursuant to a commission opinion and order. This COSS is to be utilized for the purpose of unbundling the current tariff and contract rates. The COSS provided must demonstrate the derivation of the generation, transmission, and distribution components for each rate schedule to be utilized in schedule UNB- 5.1.

Tariff schedules and contracts filed under section 4905.31 of the Revised Code, filed subsequent to the last rate case, will not be included in the COSS. Therefore, for all new schedules and contracts, indicate how generation, transmission, and distribution allocations were made. If allocations were based on a similarly structured tariff schedule, indicate why such allocations would be reasonable for the new schedule.

The electric utility shall demonstrate that the facilities included for cost recovery in the transmission component are consistent with the FERC seven-factor test. To the extent the seven-factor test is not met, a justification/demonstration of such deviation must be provided. The seven-factor test as contained in FERC Order No. 888 is as follows:

(i) Local distribution facilities are normally in close proximity to retail customers.

(ii) Local distribution facilities are primarily radial in character.

(iii) Power flows into local distribution systems - it rarely, if ever, flows out.

(iv) When power enters a local distribution system, it is not recognized or transported onto some other market.

(v) Power entering a local distribution system is consumed in a comparatively restricted geographical area.

(vi) Meters are based at the transmission/local distribution interface to measure flows into the local distribution system.

(vii) Local distribution systems will be of reduced voltage.

(h) UNB-5 - Revenue summary of current unbundled rates

The electric utility shall provide a schedule that summarizes on an individual schedule and contract basis the information provided in schedule UNB- 5.1. (See appendix A-3 for the form the schedule should be in.)

(i) UNB- 5.1 -Detailed summary of unbundled current rates and revenues

The electric utility shall provide a breakdown of billing determinants, the description of charges, unbundled rates, and revenues for each schedule and contract. The current billing determinants shall be identical to those used in schedule UNB- 3.1. The rates shall be the current rates unbundled into generation, transmission and distribution, prior to any adjustments as prescribed in Chapter 4928. of the Revised Code. The schedule must demonstrate how the unbundled components were derived from the COSS provided in schedule UNB-4. The revenues shall be the product of the billing determinants and the unbundled rates. The total revenue for each schedule should be equal to the total revenue for each schedule as contained in schedule UNB- 3.1. (See appendix A-4.)

(j) UNB- 5.2 - Revisions since last rate case

If new schedules or contracts have been added, a separate schedule for each new schedule and contract shall be provided which should include the most current twelve months of billing determinants, and description of charges, unbundled rates, and revenues for each of the new schedules or contracts. The rates shall be the current rates unbundled into generation, transmission and distribution, prior to any adjustments as called for under Chapter 4928. of the Revised Code. The revenue figure shall be the product of the billing determinants and the unbundled rates. The total revenue for each schedule should be equal to the total revenue for each schedule as contained in schedule UNB- 3.2. If customers were previously served under another schedule prior to the new schedule, it is understood that these customers' billing determinants will also be included in the UNB- 5.1 schedules. (See appendix A-4.)

(k) UNB- 6.0 - Summary schedule of UNB- 6.1 schedules

The electric utility shall provide a summary schedule that provides the total of all of the schedules included in UNB- 6.1. (See appendix A-5.)

(l) UNB- 6.1 - Adjustments to current revenues

The electric utility shall provide a separate schedule for each tariff schedule and contract, as well as a schedule that summarizes all tariff schedules and contracts, that provides the revenue adjustments resulting from Chapter 4928. of the Revised Code. Schedules included in UNB- 6.1 shall be those schedules that were included in the utility's last rate case. A detailed explanation shall be provided with supporting data, for each schedule, indicating the dollar amount of the difference between the revenues collected from the current rates and the revenues collected from the adjusted current rates, and the reason for the difference. (See appendix A- 5.1.)

(m) UNB- 6.2 - Schedule-by-schedule revenue adjustments for new schedules

The electric utility shall provide schedules in the same format as UNB- 6.1 for all new tariff schedules and contracts that became effective after the utility's last rate case. (See appendix A- 5.1.)

(n) UNB-7 - Revenue summary of proposed adjusted unbundled rates

The electric utility shall provide a schedule that summarizes, on an individual schedule and contract basis, the information provided in schedule UNB- 7.1. (See appendix A-6.)

(o) UNB- 7.1 - Detailed revenue summary of proposed adjusted unbundled rates

The electric utility shall provide a breakdown of billing determinants, the description of charges, adjusted unbundled rates, and revenues for each schedule and contract. The current billing determinants shall be identical to those used in schedule UNB- 3.1. The rates shall be the adjusted current rates unbundled into generation, transmission, distribution, and other unbundled components as required by Chapter 4928. of the Revised Code. The revenues shall be the products of the billing determinants and the unbundled rates. (See appendix A-7.)

(p) UNB- 7.2 - Revisions since last rate case

If new schedules or contracts have been added, a separate schedule for each new schedule and contract shall be provided which should include the most current twelve months of billing determinants, and description of charges, unbundled rates and revenues for each of the new schedules or contracts. The rates shall be the adjusted current rates unbundled into generation, transmission and distribution, and other unbundled components as required by Chapter 4928. of the Revised Code. The revenues shall be the product of the billing determinants and the unbundled rates. If customers were previously served under another schedule prior to the new schedule, it is understood that these customers' billing determinants will also be included in the UNB- 7.1 schedules. (See appendix A-7.)

(q) UNB-8 - Typical bill comparison

The electric utility shall provide with its unbundling plan a set of schedules that computes typical bills for each schedule of user. The consumption levels used for the computation should, as a minimum, include: (i) levels of consumption at both the present and proposed block ends (tail block "end" is at greatest level of consumption expected) and (ii) levels of consumption that accurately represent customer consumption patterns.

(G) Additional filings

(1) If the electric utility is proposing changes to the COSS consistent with section 4928.34 of the Revised Code, a scored copy of the revised COSS should be provided with detailed support and rationale for all proposed changes. If the electric utility proposes to alter its COSS, it must also provide additional affected UNB schedules.

(1) For rate reductions that are to become effective prior to January 1, 2005, pursuant to a commission-approved rate plan, the electric utility shall propose a set of unbundled schedules that would become effective on the dates approved in the rate plan. The rate reductions could be accomplished by means of a rider, clearly referenced in each rate schedule. The utility shall provide a detailed explanation and support for all the rate reductions pursuant to the rate plans.

(3) The electric utility shall identify and provide details of how demand side management and energy efficiency funding that is already in rates is being addressed. If the utility has collected funds, but has not expended them, provide details of the intentions of such funds.

(4) The electric utility shall identify and provide details of specific costs that will be avoided by customers that shop and explain if and how such costs are being addressed in the transition plan filing.

Appendix B Operational Support Plan

(A) Purpose and scope

Operational support is the overall management and operations performed by the electric utility to provide electric service to its customers. The electric utility's transition plan is required, by division (A) of section 4928.31 of the Revised Code, to address how its current operational support system and any other technical implementation issues pertaining to competitive retail electric service will be used or changed to ensure a successful implementation of the customer's ability to choose its generation supplier.

(B) Form of the filing

The operational support plan shall be filed in the form of an electronic project management program. The program is to provide graphical diagramming and description(s) of the utility's activities, events, and their timing which are necessary to be performed or necessary to occur to assure continuity in the transition to customer choice. An active (interactive) disc and a read-only (range valued) disc are to be provided. The program is to be sufficiently sophisticated to depict the management and operational requirements during the whole of the utility's transition. An example of such a presentation is attached as appendix B-1 to this rule. The graphical diagramming is to be supported by separate textual descriptions of the activities, events, and their timing if the project management program cannot provide sufficient descriptive textual support. The plan or sections of it are to be updated when there are changes to significant milestone markers, due dates, test dates, or implementation dates.

(C) Transition plan content requirements for the operational support plan

(1) The operational support plan will identify the electric utility personnel that are responsible for the overall management and operations of the transition to customer choice (name, position, and responsibilities). The operational support plan will describe how the electric utility is effecting improved communications across its functions and disciplines in order to ensure a successful transition to customer choice. The plan must describe where and how the company will provide compatible electronic interfaces for nondiscriminatory access and real-time electronic data and message and information interchange in each of the categories of operational support.

(2) Categories of operational support

The operational support plan must also address, but not be limited to, the electric utility's ability to perform the requirements presented in each of the following categories of operational support.

(a) Pre-ordering of the service

(i) Inform customers and suppliers of comparable and nondiscriminatory access to noncompetitive services, including all unbundled and ancillary services, their rates, terms and conditions, and make such information available.

(ii) Provide generic customer data in the form of load profiles, e.g., customer groups and customer class.

(iii) Provide customer specific consumption and load history (twelve months) and meter reading dates.

(iv) Provide lists of commission certified providers of service.

(v) Provide confirmation of the authenticity of commission certified marketers or electric service companies or other suppliers.

(vi) Provide information on contracts, the contracting process, and contract disclosure.

(b) Ordering of the service (customer conversion)

(i) Provide verification of customer's choices (requests for conversion) and order status information.

(ii) Provide customer conversions (customer switching) among their choices of providers.

(c) Provisioning of the service

(i) Provide day-ahead weather and load forecasting.

(ii) Establish and provide unbundled rates, terms, and conditions of service for noncompetitive services (e.g., electric distribution service rates, terms, and conditions of service and a market-based standard).

(iii) Meet transmission ownership and/or operator requirements.

(iv) Provide reconciliation of supply and consumption "imbalances".

(v) Provide notice to customers of their default to the standard tariff offer.

(vi) Provide a description of how the utility will respond to requests for aggregation service for municipal, township, and county authorities and other governmental entities, including the confirmation that those authorities can accomplish all necessary steps and preparations.

(d) Billing services

Provide a description of what and how unbundled billing could be accomplished.

(e) Other services

Provide a discussion of the status, by class of customer or service, for alternative supplier metering, alternative supplier meter reading, or other ancillary services for alternative suppliers.

(f) Other requirements

(i) Meet decommissioning requirements.

(ii) Meet the requirements for the per cent income payment plan transition.

(iii) Establish a bidding process for competitive retail electric service.

(iv) Satisfy customer inquiry and complaint requirements (dispute resolution).

Appendix C Employee Assistance Plan

(A) Purpose and scope

To assist the electric utility employees adversely and directly affected by staffing changes resulting from restructuring, an electric utility pursuant to division (A)(4) of section 4928.31 of the Revised Code is required to show how it would mitigate any necessary reductions in the electric utility workforce. To that end, an electric utility must develop as part of a transition plan, an employee assistance (EA) plan outlining the means (e.g., voluntary severance programs, retraining, early retirement, outplacement, and educational opportunities, etc.) by which the electric utility intends to mitigate the impact of any changes on its staff and service reliability.

(B) Definitions

(1) "Electric Utilities" are as defined in division (A)(11) of section 4928.01 of the Revised Code.

(2) "Employees" are persons employed by electric utilities that meet minimum threshold requirements set forth in Chapter 4928. of the Revised Code.

(3) "Employee affected by restructuring" is an employee of an electric utility who is directly and adversely affected by electric restructuring during the market development period as set forth in Chapter 4928. of the Revised Code,

(4) "Employers" are the same as electric utilities.

(5) "Employee Assistance Plan" shall include at a minimum those provisions identified in division (A)(4) of section 4928.31 and division (A)(10) of section 4928.34 of the Revised Code.

(6) "Severance" means a lump sum or periodic payment(s) made to an employee upon separation from the employer.

(C) Transition plan content requirements for employee assistance plans

The EA plan will contain information about employment-related programs, rights, benefits, services, procedures, and rules that will assist and inform union and nonunion electric utility employees whose employment is adversely and directly affected by electric utility industry restructuring. Specifically, the plan must show how the electric utility will provide assistance for all levels of utility employees who are adversely and directly affected by electric restructuring. The electric utility must provide in its EA plan an easy to read and understandable description of, but not limited to, the following components:

(1) Notification of participant eligibility for benefits and services

In this section of the EA plan, the electric utility shall state what its eligibility requirements are and how it will inform its employees about any employment services or programs it will offer during the electric restructuring transition period.

(2) Outplacement assistance

Identify the eligible employees and describe services (e.g., resume preparation, career assessment, job placement, etc.), terms, and/or conditions being offered to each eligible employee including services to be derived from federal, state, or local assistance agencies (e.g., Ohio bureau of employment services, Ohio department of development, private, industry councils, etc.).

(3) Relocation assistance

Identify the eligible employees and describe the services, terms, and/or conditions being offered.

(4) Employee assistance program services

During the transition period, employees, to the extent their positions are adversely and directly affected by electric restructuring, and their families may need access to other support services so they can make the legal, financial, psychological, and emotional adjustments required. Many of these services (e.g., family counseling, legal services, credit/debt counseling, psychological, etc.) may be offered as part of a company's existing employee assistance programs. Identify the eligible employees and describe the benefits, services, terms, and/or conditions being offered.

(5) Early retirement programs

Identify the eligible employees and describe the services, terms, and/or conditions being offered.

(6) Severance packages

Identify the eligible employees and describe the type of benefits, services, terms, and conditions being offered.

(7) Other assistance

In this section, identify the eligible employees and describe any other programs, services, and/or benefits that might be offered to employees. For example, information about relocation assistance, education, medical assistance, etc. might be included.

(8) Disparate/Adverse Impact Statement

In this section, explain the disparate/adverse impact the proposed staffing changes will have on service delivery (i.e., will there be enough qualified and trained line persons available to handle routine and emergency situations), including any related transition costs as required in section 4928.39 , Revised Code (See appendix D of this rule).

Appendix D Transition Charges

(A) Purpose and scope

Appendix D to rule 4901:1-20-03 of the Administrative Code, outlines the filing requirements for those companies electing to request transition revenues pursuant to sections 4928.37 to 4928.40 of the Revised Code. These requirements are in addition to a fully supported analysis and justification for transition revenues, according to the utility's proposal. To the extent possible, the information requested below should be provided in a format similar to that outlined in appendix A to rule 4901-7-01 of the Administrative Code.

(B) Transition plan content requirements for transition costs

(1) Regulatory asset

The following should be provided for the electric utility's valuation of transition costs as applied to jurisdictional generation-related regulatory assets as defined in division (A)(26) of section 4928.01 and section 4928.39 of the Revised Code.

(a) Traditional regulatory assets (excludes nuclear decommissioning and disposal costs, safety and radiation control equipment, and deferred fuel.)

(i) Cite case number in which each deferral was granted, or, if no specific case authorized the deferral, the most recent case number in which the deferral and amortization was included in the determination of rates and the amortization treatment thereof.

(ii) Provide balances and related offsets, such as deferred taxes, for each regulatory asset as of December 31, 1998; and provide a calculation to show the balance as included in current rates and the annual expense amortization.

(iii) Provide a projected balance and related offsets, such as deferred taxes, of each regulatory asset as of December 31, 1999 and December 31, 2000.

(b) Other regulatory assets (safety and radiation control equipment, nuclear decommissioning and disposal costs, and deferred fuel.)

(i) Safety and radiation control equipment

(a) For jurisdictional plant and depreciation reserve balances, list the information as requested below in the same format as chapter II, schedules B- 2.1, B- 2.3, B-3, and B- 3.3 of rule 4901-7-01 of the Administrative Code:

(i) Date certain balances from the most recent rate case filed with this commission, by account, and with each item precisely identified.

(ii) Additions, retirements, and transfers occurring from the date certain of the most recent rate case filed with this commission to December 31, 1998. Also, provide a projection of same for the period of January 1, 1999 to December 31, 2000.

(b) Provide the definition of "Safety and Radiation Control Equipment" that was used to identify the plant noted above.

(ii) Nuclear decommissioning costs

(a) Provide a copy of the study used to estimate decommissioning costs, as used for internal modeling purposes, as of December 31, 1998. If a later estimate of decommissioning costs has been prepared, this study shall also be provided.

(b) Provide the accumulated balance in the depreciation reserve associated with nuclear decommissioning accruals prior to December 31, 1987.

(c) Provide balances in qualified and nonqualified external funds, by unit and account, as of December 31, 1998, and projected balances as of December 31, 1999 and December 31, 2000.

(d) Provide current annualized expense accrual for each plant and each fund.

(iii) Nuclear fuel disposal costs

Provide expected kWh generation from nuclear units, by unit, by year, for the period January 1, 2001 to December 31, 2010.

(iv) Deferred fuel costs

(a) Provide the positive or negative balance as of December 31, 1998, in accordance with rule 4901:1-11-09 of the Administrative Code. Also, provide a projection of same for December 31, 1999 and December 31, 2000. If a company does not maintain a deferred fuel balance, provide the last date on which such a balance was maintained and the balance at that time, as well as the net amount of over- or underrecoveries of fuel costs that have occurred since the cessation of maintaining such a balance, as of the above specified dates. If records of the net amount do not exist and cannot be derived with reasonable effort, provide a good faith estimate of the net amount.

(b) Provide the reconciliation adjustment component of the electric fuel component (EFC), effective October 5, 1999, that compensates for over- and underrecoveries, as well as any other portions of the current EFC that compensate for such recoveries pursuant to a settlement. If a company's EFC rate on that date did not have a reconciliation adjustment as one of its components, or if the reconciliation adjustment component was set at zero, state the reason(s) for this condition.

(c) Provide an explanation of proposed accounting for regulatory assets in the event that related production facilities are sold or transferred.

(d) Provide any accumulated ("banked") emission allowances as of December 31, 1998, and projected allowances as of December 31, 1999 and December 31, 2000.

(2) Other transition costs

(a) Generation net plant in service

The following should provide for the valuation of transition costs as defined in section 4928.39 of the Revised Code, as it applies to jurisdictional net plant in service by generating unit. List the information as requested below in the same format as chapter II, schedules B- 2.1, B- 2.3, B-3, and B- 3.3 of rule 4901-7-01 of the Administrative Code.

(i) Gross plant in service

(a) Provide for each plant property account, the plant balances at December 31, 1998, by generating unit, for all generating units.

(b) Provide for each plant property account, by generating unit or station, the plant balances, gross additions, retirements, and transfers that occurred in the interim period from the date certain of the last rate case filed with this commission to December 31, 1998. Also, the electric utility shall provide a projection of same as of December 31, 1999, and December 31, 2000.

If, in a particular account, transfers are a normal course of events, only a general description of the nature of the transfers is required.

(ii) Depreciation reserve

(a) Provide for each depreciation reserve account, the balances at December 31, 1998.

An electric utility that does not maintain reserve balances by account may use theoretical reserve studies to allocate actual reserve balances among the accounts. An electric utility shall indicate that the reserve was allocated using a theoretical reserve study.

(b) Provide in the level of detail maintained by the utility the balances, depreciation/amortization expense accruals, salvage, cost of removal and transfers that occurred from the date certain of the last rate case to December 31, 1998. Also, the electric utility shall provide a projection of same as of December 31, 1999 and December 31, 2000.

If transfers are a normal course of events in a particular account, only a general description of the nature of the transfer is required.

(c) If the depreciation reserve was allocated to accounts based on a theoretical reserve study, provide a copy of such study. If the study is the same as that contained in the electric utility's latest depreciation study, reference to such study is sufficient.

(b) Costs recoverable in a competitive market

(i) For each generation unit in (a) above, provide either: (a) an estimate of the net present value, calculated as of December 31, 2000, of those costs which would be recoverable in a competitive market for electricity and related services, or (b) an estimate of the current value of those costs which would be recoverable in a competitive market for generation assets. (In cases where units are economically similar in terms of fuel, size, type, and operation, the analysis may be conducted on a multi-unit basis and then allocated down to the individual units.)

(ii) Identify any other generation-related assets that have costs that may be recovered in a competitive market. Provide a current estimate of the recoverable costs.

(iii) Provide the complete basis and assumptions for the estimates in (i) and (ii), above, including copies of all engineering or economic studies or other studies or memoranda supporting or producing these estimates, together with an explanation of the methodology and assumptions used.

To the extent applicable to the methodology used by the applicant, the assumptions made as to the following items should be identified:

(a) The geographic size of the market and expected number of suppliers;

(b) The transmission costs and transmission capacity available for customers to access competitive generation;

(c) The expected participation in any part of the competitive market by any affiliate of the electric utility;

(d) Expected standard offer revenues;

(e) Expected revenue from customers who remain with the incumbent utility;

(f) Load growth;

(g) Merger, acquisition or corporate restructuring savings;

(h) Regional transmission entity operational date and membership;

(i) Sales erosion that would have occurred regardless of the effects of Amended Substitute Senate Bill Number 3 (e.g., municipalization, self generation, energy substitution, etc.); and

(j) Cost savings expected to be realized as a result of Amended Substitute Senate Bill Number 3 or the subsequent reduction in generation sales or customers.

(iv) To the extent not provided in response to (iii) above, provide the following for each generation unit:

(a) Anticipated or currently planned retirement date;

(b) Heat rate data for the utility's generating units and those used in the dispatch model for those units;

(c) Net dependable capacity, by seasons, together with any anticipated changes in capacity over the life of the unit;

(d) Operational constraints that restrict unit operations, such as minimum loadings, must-run or voltage support requirements, and/or any contractual arrangement or condition that restricts the use of a generating unit;

(e) Anticipated average equivalent forced outage rates and annual maintenance requirements for the remaining life of the unit;

(f) Projected kWh generation for each year of the remaining life of the unit;

(g) Projected annual cost of fuel delivered to the plant by contract;

(h) An annual forecast of capital addition expenditures anticipated through the remaining life of the unit;

(i) Five years of historic capital addition expenditures;

(j) A description of all ancillary services by type, amount, and cost by each generator for each of the last five years;

(k) Forecast of variable non-fuel operation and maintenance expense;

(l) Annual cost of nonfuel consumables;

(m) Five years of historic fixed operation and maintenance expense information and forecasted fixed operating and maintenance expense information for the remaining life of the unit;

(n) Allocated emission allowances and annual forecast of emission rates;

(o) Annual forecast of property tax payments over the life of the unit;

(p) Annual forecast of expected revenues by unit in a competitive market for electricity and related services. If the projections are based on separate energy and capacity payments, provide each category separately;

(q) Any current sales or purchases of generation facilities within the applicant's operating territory of which the applicant is aware;

(r) Information on sales or purchases of generation assets comparable to those owned and/or operated by the applicant; and

(s) All bids, offers to sell, or offers to buy generation units by or to the applicant, and the timing of any anticipated purchases or sales of generation assets. This information can be filed as confidential information, if accompanied by a request for protective treatment.

(v) To the extent not provided in response to (iii) above, provide the following system information or parameters:

(a) Wholesale market price forecasts to 2010, which take account of seasonal and time-of-day considerations;

(b) Projected overall cost of capital and cost rates of debt and equity applicable to the competitive generation function;

(c) Appropriate discount rate;

(d) Expected administrative or overhead expenses to be allocated to the generation function;

(e) Forecasts of emissions markets; and

(f) Forecasts or descriptions of projected transmission system capability affecting the utilization of the generation assets.

(c) Employee assistance

If the electric utility's transition costs include the costs of employee assistance in excess of those costs contained in its current labor contracts, provide the calculation that supports these excess costs. Also, the electric utility shall provide the following supporting documentation:

(i) Demonstrate that the employee displacement resulted from the effects of the transition plan filed pursuant to section 4928.31 of the Revised Code.

(ii) Labor contract(s) and indicate which portions are applicable to employee assistance.

(C) Transition plan content requirements for transition charges

(1) Market price

(a) Provide a projection of the average, annual retail market prices relating to each competitive charge or rate to be offered by the applicant.

(i) The projection should cover each year for the period January 1, 2001 to December 31, 2005.

(ii) The projection should be based on the same body of information as provided subject to other transition costs, paragraph (B)(2)(b)(i) of this appendix.

(b) If the company is providing market-priced retail generation services in other jurisdictions, provide information on rates, terms and conditions, and current and anticipated annual sales. This information can be filed as confidential information, if accompanied by a request for protective treatment.

(2) Transition revenues

Provide the proposed transition revenue from customers not seeking alternate sources of generation service and

(a) Identify the transition charge, per kWh, for each customer class and rate schedule from part A of the transition plan application; and

(b) Identify the quantity of kWh deliveries anticipated per year for the period January 1, 2001 to December 31, 2005, for each customer class and rate schedule.

(D) Accounting adjustments for mergers, acquisitions, and other transfers of ownership

For any mergers, exchanges, transfers, or other acquisitions of assets occurring since the applicant's most recent rate case proceeding, provide a listing and explanation of all accounting adjustments affecting the electric utility.

(E) Detail on refunctionalization of assets Identify and provide support and explanation for any refunctionalization of the assets of the electric utility since the company's most recent rate case proceeding.

(F) Transition plan content requirements for supplemental information

(1) Allocation factors

The following should provide for the determination of jurisdictional allocations for generation regulatory assets, plant in service, and employee assistance costs. List the information as requested below in the same format as chapter II, schedules B-7 and B- 7.1 of rule 4901-7-01 of the Administrative Code.

(a) Jurisdictional allocation factors

Identify by each account, subaccount or component the factor(s) used in allocating total utility costs to the jurisdiction.

(b) Jurisdictional allocation statistics

For each allocation factor to be used, provide the statistics used in determining the jurisdictional percentage. Statistics must be those that were used to determine current base rates.

(2) The most recent federal energy regulatory commission (FERC) audit report.

(3) The electric utility's current uniform statistical report. If the applicant no longer produces a uniform statistical report, the information contained in that report may be provided in another format.

(4) The most recent federal and/or state regulatory agency report (FERC form 1).

(5) Annual reports of the electric utility to stockholders or parent company, if the electric utility is a wholly owned subsidiary, for the most recent five years and the most recent statistical supplement.

(6) References to the edgar database for the most recent securities and exchange commission forms 10-K, 10-Q, and 8-K of the electric utility, and/or parent company if the electric utility is a wholly owned subsidiary. In addition, the applicant should stand ready to make these reports available to the commission staff upon request.

(7) Quarterly reports of the electric utility to stockholders or parent company, if the electric utility is wholly owned subsidiary, for the most recent five quarters.

Appendix E Shopping Incentive

(A) Each electric utility shall propose as a part of its transition plan a customer shopping incentive that is specific to each of its tariffs or rate schedules proposed to be in effect during the market development period. The proposed shopping incentive must be sufficient to cause customers representing at least twenty per cent of the load in each customer class to switch generation suppliers to someone other than the incumbent utility by the midpoint of the utility's market development period but not later than December 31, 2003. For purposes of this appendix, customer classes shall be: (a) the residential class, (b) the commercial class, and (c) the mercantile commercial and industrial class. Each utility shall provide annual projections of customer load switching for each customer class for each of the first three years of the market development period based on the proposed shopping incentive. The transition plan should also address the issue of shopping incentives for those tariff schedules that have not been historically included in the above customer classes (e.g., street lighting or public authority).

(B) Each electric utility shall provide as a part of its transition plan a report that supports and demonstrates that the proposed shopping incentive is adequate to cause twenty percent of the load in each customer class to switch suppliers by the midpoint of the utility's market development period, but not later than December 31, 2003. Documentation shall be provided in the report that supports each proposed shopping incentive for each customer class. The documentation shall include, but not be limited to:

(1) All marketing studies, research, and analyses that indicate the relationship between price or percentage savings and customer switching behavior;

(2) Analyses of specific prices and other pertinent factors that have motivated industrial customers to purchase electricity from alternative suppliers pursuant to third-party buy-through programs; and

(3) Analyses of specific prices and other pertinent factors that have motivated residential, commercial, and industrial customers to purchase electricity from alternative municipal suppliers and where, in border situations, there is direct competition between investor-owner utilities and municipal systems.

(C) The report shall propose a specific approach to adjusting the shopping incentive after the first and second years of the market development period based on actual customer load switching rates should those actual load switching rates be different from the utility's projections of customer load switching.

The report shall specify and be based upon reasonable assumptions and accurate data, and shall fully describe and employ an adequate methodology to arrive at: (1) the level of shopping incentive proposed; (2) the projections of customer load switching that will result in each of the first three years of the market development period from the proposed shopping incentive; and (3) the utility's proposed approach to adjusting the shopping incentive in years two and/or three of the market development period.

R.C. 119.032 review dates: 08/02/2004 and 11/30/2008

Promulgated Under: 111.15

Statutory Authority: 4928.06

Rule Amplifies: 4928.31(A) , 4928.32(C)

Prior Effective Dates: 3/10/00