Chapter 4901:5-5 Electric Utility Forecast Reports

4901:5-5-01 Definitions.

(A) "ATC" means available transfer capability as defined by the regional reliability organization standards.

(B) "Alternative energy resource" has the meaning set forth in division (A)(1) of section 4928.64 of the Revised Code.

(C) "Available system capability" means the installed capability of all generating units on the utility system plus firm purchases.

(D) "Capability" means the net seasonal demonstrated rating of generating equipment, as defined by the regional reliability organization reliability standards.

(E) "Certified territory" means the service area established for an electric supplier under sections 4933.81 to 4933.90 of the Revised Code.

(F) "Demand-side management" means those programs or activities that are designed to modify the magnitude and/or patterns of electricity consumption in a utility's service area by means of equipment installed or actions taken on the customer's premises.

(G) "Electric transmission owner" means the owner of a major utility facility as defined in section 4935.04 of the Revised Code.

(H) "Energy-price relationships" means the calculated or observed effect on peak load, load shape, or energy consumption resulting from changes in the retail price of electricity or other fuels.

(I) "Forecast year," "year of the forecast," or "year zero" means the year in which the forecast is filed.

(J) "Forecast period" means year zero through year ten.

(K) "Integrated operating system" means a group of electric transmission owners or electric utilities who are members of a jointly or commonly operated system as a single entity.

(L) "Integrated resource plan" means that plan or program, established by a person subject to the requirements of this chapter, to furnish electric energy services in a cost-effective and reasonable manner consistent with the provision of adequate and reliable service, which gives appropriate consideration to supply- and demand-side resources and transmission or distribution investments for meeting the person's projected demand and energy requirements.

(M) "Internal load" of a system means the summation of the net output of its generators plus the net of interconnection receipts and deliveries.

(N) "Interruptible load" means load that can be curtailed or reduced at the supplier's discretion or in accordance with a contractual agreement.

(O) "Load" means the amount of power needed to be delivered at a given point on an electric system.

(P) "Load modification" means the impact of a demand-side management, energy efficiency, demand reduction, price responsive demand, or demand response program designed to influence customers' patterns of electricity use in order to modify the utility's load shape.

(Q) "Load shape" means the distribution of a utility's total electricity demand measured over time, usually expressed as a curve which plots megawatts supplied against time of occurrence, and illustrates the varying magnitude of the load during that time period.

(R) "Native load" of a system means the internal load minus interruptible loads.

(S) "Nonutility generation" means any source of electricity which is interconnected with a utility's system, but is not exclusively owned by an electric utility.

(T) "Peak demand" or "peak load" means the electric transmission owner's or electric utility's maximum sixty-minute integrated clock hour predicted or actual load for the year.

(U) "Price responsive demand" means the predictable response to changes in wholesale electricity prices of electricity demand by consumers who are served at retail rates or prices that can vary based on wholesale electricity prices or market conditions.

(V) "Renewable energy resource" has the meaning set forth in division (A)(35) of section 4928.01 of the Revised Code.

(W) "Reporting person" means any person required to file a long-term forecast report under section 4935.04 of the Revised Code.

(X) "Supply-side resources" mean those resources that directly increase the amount of electricity available for consumption in a utility's certified territory.

(Y) "Transfer capability" means the ability of the transmission owner's system to move power over its system to another interconnected transmission system or distribution utility while meeting all national standard reliability requirements.

(Z) "TTC" means total transfer capacity as defined by the regional reliability organization standards and is the measure of the ability of the interconnected electric systems to reliably move or transfer power from one area to another over all transmission lines or paths within the interconnected electric systems.

Effective: 02/12/2012
R.C. 119.032 review dates: 11/21/2011 and 12/01/2015
Promulgated Under: 111.15
Statutory Authority: 4901.13 , 4935.04
Rule Amplifies: 4935.04
Prior Effective Dates: 7/26/78, 4/2/83, 6/1/83, 7/2/84, 10/14/85, 11/20/87, 1/15/90, 3/24/97, 9/18/00

4901:5-5-02 Purpose and scope.

(A) This chapter specifies the reporting requirements for long-term forecast reports filed by electric utilities and transmission owners pursuant to Chapter 4901:5-1 of the Administrative Code.

(B) Unless otherwise directed by the commission, all reports shall be filed using such forms as may be posted on the commission's web site. Such forms may be changed without further commission entry and each reporting person should check the commission's web site to obtain the current forms before filing a report.

(C) The commission may, upon an application or a motion filed by a party, waive any requirement of this chapter, other than a requirement mandated by statute, for good cause shown.

R.C. 119.032 review dates: 11/30/2011 and 12/01/2015
Promulgated Under: 111.15
Statutory Authority: 4901.13 , 4935.04
Rule Amplifies: 4935.04
Prior Effective Dates: 12/10/2009

4901:5-5-03 Forecast report requirements for electric utilities and transmission owners.

(A) Summary of the long-term forecast report.

The long-term forecast report shall contain a summary describing the electric utility's forecast of loads and the resource plan to meet that load, and shall include at a minimum:

(1) The planning objectives.

(2) A summary of its forecasts of energy and peak load demands and the key assumptions or projections underlying these forecasts.

(3) A description of the process by which the energy and peak load forecasts were developed.

(B) General guidelines. The following guidelines shall be used in the preparation of the forecast:

(1) The forecast must be based upon independent analysis by the reporting electric transmission owner or electric utility.

(2) The forecast may be based on those forecasting methods that yield the most useful results to the electric transmission owner or electric utility.

(3) Where the required data have not been calculated directly, relevant conversion factors shall be displayed.

(C) Special subject areas.

(1) The following matters shall specifically be addressed:

(a) A description of the extent to which the reporting electric transmission owner or electric utility coordinates its load and resource forecasts with those of other systems such as affiliated systems in a holding company group, associated systems in an integrated operating system or other coordinating organizations, or other neighboring systems.

(b) A description of the manner in which such forecasts are coordinated, and any problems experienced in efforts to coordinate forecasts.

(c) A brief description of any polls, surveys, or data-gathering activities used in preparation of the forecast.

(2) No later than six months prior to the required date of submission of the forecast, the commission may supply the reporting electric transmission owner or electric utility:

(a) Copies of appropriate commission or other state documents or public statements that include the state energy policy for consideration in preparation of the forecast.

(b) Such current energy policy changes or deliberations, which, due to their immediate significance, the commission determines to be relevant for specific identification in the forecast (including but not limited to new legislation, regulations, or adjudicatory findings). The reporting person shall provide a discussion of the impacts of such factors and how it has taken these factors into account.

(3) Existing energy efficiency, demand reduction, and demand response programs and policies of the reporting person, which support energy conservation and load modification, shall be described along with an estimate of their impacts on energy and peak demand and supply resources.

(4) Energy-price relationships:

(a) To the extent possible, identify the relationship between price and energy consumption and describe how such changes are accounted for in the forecast.

(b) To the extent possible, specify a demand function that will or can be used to identify the relationship between any dynamic retail prices and peak load, which captures the impact of price responsive demand.

(c) A description of, and justification for, the methodologies employed for determining such energy-price relationships shall be included.

(D) Forecast documentation. The purpose of the documentation section of the report is to permit a thorough review of the forecast methodology and test its validity. The components of the forecast documentation include:

(1) A description of the forecast methodology employed, including:

(a) Overall methodological framework chosen.

(b) Specific analytical techniques used, their purpose, and the forecast component to which they are applied.

(c) The manner in which specific techniques are related in producing the forecast.

(d) Where statistical techniques have been used:

(i) All relevant equations and data.

(ii) The size of the standard error of the estimate, and the size of the forecasting error, associated with each relevant forecasting model equation, this information shall be included for each forecast at the bottom of forms FE-D1 to FE-D6.

(iii) A description of the technique.

(iv) The reason for choosing the technique.

(v) Identification of significant computer software used.

(e) An explanation of how controllable and interruptible loads are forecasted and how they are treated in the total forecast.

(f) An identification of load factors or other relevant conversion factors and a description of how they are used within the forecast.

(g) Where the methodology for any sector has changed significantly from the previous year, a discussion of the rationale for the change.

(2) Assumptions and special information. The reporting person shall:

(a) For each significant assumption made in preparing the forecasts, include a discussion of the basis for the assumption and the impact it has on the forecast results. Give sources of the assumption if other than the reporting person.

(b) Identify special information bearing on the forecast (e.g., the existence of a major planned industrial expansion program in the area of service or other need determined on a regional basis).

(3) Database documentation. The responsibilities of the reporting person with regard to its forecast database are as follows:

(a) The reporting person shall provide or cause to be provided:

(i) A brief description of all data sets used in making the forecast, both internal and external, input and output, and a citation to the sources.

(ii) The reasons for the selection of the specific database used.

(iii) A clear identification of any significant adjustments made to raw data in order to adapt them for use in the forecast, including, to the extent practicable:

(a) The nature of the adjustment made.

(b) The basis for the adjustment made.

(c) The magnitude of the adjustment.

(b) If a hearing is to be held on the forecast in the current forecast year, the reporting person shall provide to the commission in electronic formats or other medium as the commission directs, all data series, both input and output, raw and adjusted, and model equations used in the preparation of the forecast.

(c) The reporting person shall provide to the commission, on request:

(i) Copies of all data sets used in making the forecasts, including both raw and adjusted data, input and output data, and complete descriptions of any mathematical, technical, statistical, or other model used in preparing the data.

(ii) A narrative explaining the data sets and any adjustments made with the data to adapt it for use in the forecast.

Replaces: 4901:5-5-02

R.C. 119.032 review dates: 11/30/2011 and 12/01/2015
Promulgated Under: 111.15
Statutory Authority: 4901.13 , 4935.04
Rule Amplifies: 4935.04
Prior Effective Dates: 7/26/78, 4/2/83, 6/1/83, 7/2/84, 10/14/85, 11/20/87, 1/15/90, 3/24/97, 9/18/00, 12/10/09

4901:5-5-04 Forecasts for electric transmission owners.

(A) General guidelines.

The electric transmission owner shall provide or cause to be provided data on the use of its transmission lines and facilities.

(1) The forecast shall include data on all existing transmission lines and associated facilities of one hundred twenty-five kilovolts (kV) and above as defined by the commission, for year zero to year ten.

(2) The forecast shall include data on all planned transmission lines and associated facilities of one hundred twenty-five kilovolts (kV) and above as well as substantial planned additions to, and replacement of existing facilities, as defined by the commission for year zero to year ten.

(3) The reporting electric transmission owner shall be prepared to supply to the commission on demand, additional data and maps of transmission lines and facilities.

(B) Transmission energy data and peak demand forecast forms.

The electric transmission owner's forecast shall be submitted in an electronic form prescribed by the commission or its staff.

(1) Electric transmission owners shall file energy delivery forecast (megawatt hours/year) data: Actual and forecast as shown on form FE-T1. The electric transmission owner shall indicate the total energy it received from all generating sources connected to their transmission system within Ohio as well as the total energy received from all generating sources connected to their system. They shall indicate the total energy received at interconnections with other electric transmission owners within Ohio as well as the total energy received from all its interconnections. The electric transmission owner shall report the total energy deliveries to interconnections within Ohio as well as to all its interconnections. The electric transmission owner shall report the total energy deliveries for loads within Ohio as well as to all load deliveries.

(2) Electric transmission owners shall file system seasonal peak load demand forecasts: Actual and forecast system peak demand levels for summer and winter seasons as displayed on form FE-T2, covering both native and internal loads, as defined in the form.

(3) Monthly data of energy and peak loads. The electric transmission owner shall specify in detail the methodology employed to produce monthly forecasts of energy and peak load for the current year and one year in the future. The reporting electric transmission owner shall provide or cause to be provided monthly information as required on the following forms:

(a) "Total monthly energy forecast" forecast information concerning monthly energy forecasts shall be provided for two years on form FE-T3.

(b) "Monthly internal peak load forecast" forecast information concerning monthly peak load forecasts shall be provided for two years on form FE-T4.

(c) "Monthly energy transaction" the reporting electric transmission owner shall provide or cause to be provided monthly data on all energy received and delivered for the twelve months of the most recent year for which actual data is reported on the forms FE-T5 and FE-T6:

(i) On form FE-T5 part A, the electric transmission owner shall provide or cause to be provided monthly data on all energy received under firm contract and nonfirm contract:

(a) From power plants directly connected to their transmission system.

(b) From other sources.

(c) The total energy received from all sources for the month.

(ii) On form FE-T5 part B, the electric transmission owner shall provide or cause to be provided monthly data on energy delivered under firm and nonfirm contract for the total system and for delivery points located in Ohio:

(a) The amount of power delivered to affiliated electric utilities.

(b) The amount of power delivered to other nonaffiliated investor-owned electric utilities.

(c) The amount of power delivered to cooperatively owned electric utilities.

(d) The amount of power delivered to municipally owned electric utilities.

(e) The amount of power delivered to federal and state electric agencies.

(f) The amount of power delivered for nondistribution service.

(g) The total amount of power delivered.

(iii) On form FE-T5 part C, the electric transmission owner shall provide or cause to be provided monthly data on system losses and/or unaccounted for energy by firm and nonfirm transmission service.

(4) The reporting electric transmission owner shall provide the following data on the operating conditions of transmission owner's system at the time of the system's monthly peak for each month during the most recent year on form FE-T6:

(a) The date and time of peak.

(b) The peak MWs.

(c) Any scheduled transmission outages on the system.

(d) Any unscheduled transmission outages on the system.

(e) Any emergency operating procedures in effect.

(C) The existing transmission system.

(1) The reporting electric transmission owner shall provide or cause to be provided a brief narrative description of the existing electric transmission system and identify any transmission constraints and critical contingencies with and without the power transfers to the neighboring companies detailed in forms FE-T7 and FE-T8:

(a) A summary of the characteristics of existing transmission lines shall be shown as indicated in form FE-T7, characteristics of existing transmission lines.

(b) A separate listing of substations for each line included in form FE-T7 shall be shown as indicated in form FE-T8, summary of existing substations.

(2) Each reporting electric transmission owner shall provide or cause to be provided maps of its electric transmission system as follows:

(a) One schematic map of the transmission network.

(b) A map showing the actual, physical routing of the transmission lines, geographic landmarks, major metropolitan areas, and the location of substations and generating plants, interconnects with distribution, and interconnections with other electric transmission owners.

(c) Two copies of the map described in paragraph (C)(2)(b) of this rule, for commission use, on a 1:250,000 scale. The electric transmission owners may jointly provide one set of maps to meet this requirement. Participation in the commission's joint mapping project will meet this requirement.

(D) The planned transmission system.

The reporting electric transmission owner shall provide or cause to be provided a detailed narrative description of the planned electric transmission and identify any transmission constraints and critical contingencies with and without the power transfers to the neighboring companies and a description of the plans for development of facilities for years zero through ten as follows:

(1) Specifications of planned transmission lines shall be provided on form FE-T9, specifications of planned electric transmission lines for:

(a) New lines requiring new rights-of-way.

(b) Lines in which changes of capacity, either in terms of current, voltage, or both, are scheduled to take place.

(c) Other changes in transmission lines or rights-of-way, which would be considered as substantial additions, as defined in rule 4906-1-02 of the Administrative Code.

(2) A listing of all proposed substations shall be provided in form FE-T10, summary of proposed substations.

(3) The transmission forecast shall include maps of the planned transmission system as follows:

(a) An overlay to each of the maps required in paragraph (C) of this rule showing the planned transmission lines, substation, and generating plants as they will tie into the existing system; planned lines shall be shown and identified as such and keyed into form FE-T9, to provide as complete a picture of the system as is possible. Combined maps showing both existing and proposed facilities may be substituted for the overlays. Where planning horizons make it impractical to comply fully with the data requirements of this rule, as many data as are available shall be provided along with the estimated date on which additional data will be available.

(b) Two copies of the above overlay, for commission use, on a scale of 1:250,000. The electric transmission owners may jointly provide one set of overlays to meet this requirement. Participation in the commission's joint mapping project will meet this requirement.

(E) Substantiation of the planned transmission system.

The reporting electric transmission owner shall submit a substantiation of transmission development plans, including:

(1) Description and transcription diagrams of the base case load flow studies of the transmission owner's transmission system in Ohio, one for the current year and one as projected either three or five years into the future, and provide base case load flow studies on computer disks in PSSE or PSLF format along with transcription diagrams for the base cases.

(2) A tabulation of and transcription diagrams for a representative number of contingency cases studied along with a brief statements concerning the results.

(3) Analysis of proposed solutions to problems identified in paragraph (E)(2) of this rule.

(4) Adequacy of the electric transmission owner's transmission system to withstand natural disasters and overload conditions.

(5) Analysis of the electric transmission owner's transmission system to permit power interchange with neighboring systems.

(6) A diagram showing the electric transmission owner's import and export transfer capabilities and identifying the limiting element(s) during each season of the reporting period. In addition, the reporting electric transmission owner will provide a listing of transmission loading relief (TLR) procedures called during the last two seasons for which actual data are available. That listing may include only those TLRs called as a result of a transmission limit on the reporting electric transmission owner's transmission system. For each TLR event, the listing shall include the maximum level, and the duration at the maximum level, and the magnitude (in MW) of the power curtailments.

(7) A description of any studies regarding transmission system improvement, including, but not limited to, any studies of the potential for reducing line losses, thermal loading, and low voltage, and for improving access to alternative energy resources.

(8) A switching diagram of the transmission network.

(F) Regional and bulk power requirements.

To avoid the inefficiencies associated with having each electric transmission owner report this data, the electric transmission owners may have the regional transmission system operator submit a single report on their behalf. This information shall be provided as soon as it becomes available. Data provided to the commission concerning the electric transmission owner's existing and planned bulk power transmission system (two hundred thirty kV and above) shall include the following:

(1) The most recent regional power existing facilities and an authorized map.

(2) A plan on the bulk power transmission network of the region in service (total certified territory of the companies in the region including out-of-state certified territories) at the time of the report, including interfaces with adjoining regions.

(3) Regional transmission system power interchange matrix.

(4) A transmission diagram and a summary of the load flow base case studies of the bulk power network of the region as it now exists at the time of reporting.

(5) A plan of the bulk power transmission network of the region (including interties with adjoining regions) and the general routing of facilities committed or tentatively projected for service within ten years, including identification of principal substations, operating voltages, and projected in-service dates.

(6) A list and diagram showing transmission constrains of the bulk power transmission network, including interconnections.

(G) To the extent that information sought in this rule contains critical energy infrastructure, the reporting person shall provide such information to the commission's staff but redact all such information before filing in the case docket.

Replaces: 4901:5-5-03

R.C. 119.032 review dates: 11/30/2011 and 12/01/2015
Promulgated Under: 111.15
Statutory Authority: 4901.13 , 4935.04
Rule Amplifies: 4935.04
Prior Effective Dates: 11/20/87, 1/15/90, 8/17/90, 9/18/00, 5/31/07, 12/10/09

4901:5-5-05 Energy and demand forecasts for electric utilities.

(A) General guidelines.

(1) The reporting person shall provide or cause to be provided data on the use of the electric utility's distribution lines and facilities.

(2) The reporting person shall specify in detail the methodology employed to produce monthly forecasts of energy and peak load for the current year and one year in the future.

(3) The reporting person shall, upon request, supply to the commission with additional data and maps of distribution lines and facilities.

(B) Distribution energy data and peak demand forecast forms.

The distribution forecast shall be submitted in an electronic form prescribed by the commission or its staff.

(1) Each electric utility shall file a certified territory energy forecast (megawatt-hours/year). Each electric utility operating in Ohio shall furnish completed sets of FE-D1 and FE-D2 forms:

(a) FE-D1 shall contain data for only the Ohio portion of the reporting electric utility's total certified territory.

(b) Electric utilities that are members of an integrated operating system and operated on a system basis shall also file FE-D2 for the integrated system.

(2) Each electric utility shall file Ohio and system seasonal peak load demand forecasts: Actual and forecast system peak demand levels for summer and winter seasons as displayed on forms FE-D3 and FE-D4, as follows:

(a) FE-D3 shall contain data for only the Ohio portion of the reporting electric utility's total certified territory.

(b) Electric utilities that are members of an integrated operating system and operated on a system basis shall also file form FE-D4 for the integrated system.

(3) Monthly forecasts of energy and peak loads.

The electric utility shall specify in detail the methodology employed to produce monthly forecasts of energy peak load and resources for the current year and one year in the future. The reporting electric utility shall provide or cause to be provided monthly information as required on the following forms:

(a) From FE-D5, monthly net energy for load forecast.

(b) Form FE-D6, monthly native and internal peak load forecasts.

(C) Substantiation of the planned distribution system.

The reporting electric utility shall submit a substantiation of distribution development plans, including:

(1) Load flow or other system analysis by voltage class of the electric utility's distribution system performance in Ohio, that identifies and considers each of the following:

(a) Any thermal overloading of distribution circuits and equipment.

(b) Any voltage variations on distribution circuits that do not comply with the current version of the American National Standard Institute (ANSI) standard C 84.1, electric power systems and equipment voltage ratings or standard as later amended.

(2) Analysis and consideration of proposed solutions to problems identified in paragraph (C)(1) of this rule.

(3) Adequacy of the electric utility distribution system to withstand natural disasters and overload conditions.

(4) Analysis and consideration of any studies regarding distribution system improvement, including, but not limited to, any studies of the potential for reducing line losses, thermal loading and low voltage or any other problems, and for improving access to alternative resources.

(5) A switching diagram of circuits less than one hundred twenty-five kV that are not radial.

Replaces: 4901:5-5-04

R.C. 119.032 review dates: 11/30/2011 and 12/01/2015
Promulgated Under: 111.15
Statutory Authority: 4901.13 , 4935.04
Rule Amplifies: 4935.04
Prior Effective Dates: 11/20/87, 1/15/90, 8/17/90, 3/24/97, 9/18/00, 5/31/07, 12/10/09

4901:5-5-06 Resource plans.

(A) As part of the long-term forecast report filed pursuant to rule 4901:5-3-01 of the Administrative Code, an electric utility shall include a resource plan as defined in rule 4901:5-5-01 of the Administrative Code, which shall contain a narrative discussion and analysis of the following:

(1) Anticipated technological changes which may be expected to influence the reporting person's generation mix, use of energy efficiency and peak-demand reduction programs, availability of fuels, type of generation, use of alternative energy resources pursuant to section 4928.64 of the Revised Code or techniques used to store energy for peak use.

(2) The availability and potential development of alternative energy resources pursuant to section 4928.64 of the Revised Code for generating electricity.

(3) Research, development, and demonstration efforts relating to alternative energy resources, including expenditure information and description of specific investigations, and the nature and timing of anticipated results of these investigations.

(4) The impact of environmental regulations on generating capacity, cost, and reliability, including precise quantitative estimates and/or historical data pursuant to division (B)(2)(b) and/or (B)(2)(c) of section 4928.143 of the Revised Code.

(5) Textual material not specifically required but of importance to the resource forecast of the reporting utility may be included in the appropriate section.

(6) Electricity resource forecast forms. In addition to the foregoing discussion and analysis, an electric utility shall include the following forms as published by the commission:

(a) Form FE-R1, "Monthly Forecast of Electric Utility's Ohio Service Area Peak Load and Resources Dedicated to Meet Ohio Service Area Peak Load." Forecast information concerning monthly loads and resources shall be provided for two years on form FE-R1.

(b) Form FE-R2, "Monthly Forecast of System Peak Load and Resources Dedicated to Meet System Peak Load." Forecast information concerning monthly loads and resources shall be provided for two years on form FE-R2.

(c) Existing system description. The reporting person shall provide the existing electric system generating capability both inside and outside Ohio in summary form as indicated in form FE-R3: "Summary of Existing Electric Generation Facilities for the System."

(d) Long-term forecast requirements. The reporting person shall provide a ten-year forecast which shall identify the electricity resource options (including purchased power) expected to be needed to meet forecast system load levels, as identified in the peak load demand forecast, on the following forms:

(i) Form FE-R4: "Actual Generating Capability Dedicated to Meet Ohio Peak Load."

(ii) Form FE-R5: "Projected Generating Capability Changes To Meet Ohio Peak Load." A summary and reconciliation of the information given in form FE-R10 shall be provided by the completion of form FE-R5.

(iii) Form FE-R6: "Electric Utility's Actual and Forecast Ohio Peak Load and Resources Dedicated to Meet Ohio Peak Load." Actual and forecast information concerning summer seasonal loads and resources shall be provided for years minus five through ten on form FE-R6.

(iv) Form FE-R7: "Actual and Forecast System Peak Load and Resources Dedicated to Meet System Peak Load." Actual and forecast information concerning summer seasonal loads and resources shall be provided for years minus five through ten on form FE-R7.

(v) Form FE-R8: "Electric Utility's Actual and Forecast Ohio Peak Load and Resources Dedicated to Meet Ohio Peak Load." Actual and forecast information concerning winter seasonal loads and resources shall be provided for years minus five through ten on form FE-R8.

(vi) Form FE-R9: "Actual and Forecast System Peak Load and Resources Dedicated to Meet System Peak Load." Actual and forecast information concerning winter seasonal loads and resources shall be provided for years minus five through ten on form FE-R9.

(e) Plans for development of facilities in the forecast period. Information regarding new generating capacity shall be provided for each planned facility on form FE-R10: "Specifications of Planned Electric Generation Facilities."

(i) All information on facilities which will commence operating during the forecast period and facilities on which construction will commence during the forecast period shall be displayed.

(ii) Each applicable facility shall be keyed to the capacity increases summarized in form FE-R5, indicating the amount and timing of additional generating capability provided.

(B) In the long-term forecast report filed pursuant to rule 4901:5-3-01 of the Administrative Code, the following must be filed in the forecast year prior to any filing for an allowance under divisions (B)(2)(b) and (B)(2)(c) of section 4928.143 of the Revised Code:

(1) Existing generating system description.

(a) The reporting person shall provide a brief summary narrative of the existing electric generating system. If a hearing is to be held on the forecast in the current year, the reporting person shall submit to the commission with its long-term forecast report, the anticipated operating, maintenance, and fuel expense of each unit for each year of the forecast period. The commission may make exceptions to this paragraph for good cause.

(b) A summary of the pooling, mutual assistance, and all agreements for purchasing from and selling power and energy to other utilities or nonutility generators, including costs and amounts, shall be provided.

(2) Need for additional electricity resource options. The reporting person shall describe the procedure followed in determining the need for additional electricity resource options. All major factors shall be discussed, including but not limited to:

(a) System load profile.

(b) Maintenance requirements of existing and planned units.

(c) Number of units, unit size, and availability of existing and planned units.

(d) Forecast uncertainty.

(e) Electricity resource option uncertainty with respect to cost, availability, commercial in-service dates, and performance.

(f) Lead times for construction or implementation of planned electricity resource options.

(g) Power interchange with other electric systems, including consideration of the ability to buy and sell power.

(h) Price-responsive demand and price elasticity due to the implementation of time-differentiated pricing options and assessments of the value of lost load.

(i) Regulatory climate.

(j) Reliability criteria, including a discussion and analysis of the reporting person's reliability criteria and factors influencing their selection, including, but not limited to:

(i) Reliability measures used and factors including the selection.

(ii) Engineering analysis performed.

(iii) Economic analysis performed.

(iv) Any judgments applied.

(3) Resource plan.

(a) This paragraph shall include the electric utility's projected mix of resource options to meet the base case projection of peak demand and total energy requirements.

(b) A discussion of the electric utility's projected system reliability shall be presented. It shall include:

(i) A discussion of the future adequacy of the electric utility's projected system in both the short- and long-term.

(ii) A discussion of the future adequacy of fuel supplies in both the short- and long-term. Additionally, the reporting person shall provide, for the forecast period, a description of its overall fuel procurement policies and procedures. A description of the system's fuel requirements, the system's geographic source of fuel supply, and the percentage of fuel supply under contract shall be included.

(c) The electric utility shall demonstrate the cost-effectiveness of the plan through a comparison over the ten-year forecast horizon of the revenue requirement and rate impacts of the selected plan and alternative plans evaluated. The selection of the plan shall demonstrate adequate consideration of the risks, reliability, and uncertainties associated with the person's selected plan and alternative plans, and of other factors the electric utility deems appropriate.

(d) The methodology for arriving at the plan must be fully explained and described. The description must be sufficiently explicit, detailed, and complete to allow the commission and other knowledgeable parties to understand how the assessment was conducted. This description shall also include:

(i) A general discussion of the decision-making process, criteria, and standards employed by the electric utility as it relates to the development of the resource plan.

(ii) A discussion of how the plan is consistent with the overall planning objectives of paragraph (A) of rule 4901:5-5-03 of the Administrative Code.

(iii) A discussion of key assumptions and judgments used in development of the resource plan.

(e) The reporting person shall provide information sufficient for the commission to determine the reasonableness of the resource plan, including:

(i) The adequacy, reliability, and cost-effectiveness of the plan.

(ii) Whether the methodology used to develop the plan evaluates demand-side management programs and nonelectric utility generation on both sides of the meter in a manner consistent with electric utility's generation and other electricity resource options. At a minimum, the total resource cost test as defined in rule 4901:1-39-01 of the Administrative Code, should be used to determine the cost-effectiveness of demand-side management programs.

(iii) Whether the plan gives adequate consideration to the following factors:

(a) Potential rate and customer bill impacts of the plan.

(b) Environmental impacts of the plan and their associated costs.

(c) Other significant economic impacts and their associated costs.

(d) Impacts of the plan on the financial status of the company.

(e) Other strategic considerations including flexibility, diversity, the size and lead time of commitments, and lost opportunities for investment.

(f) Equity among customer classes.

(g) The impacts of the plan over time.

(h) Such other matters the commission considers appropriate.

Effective: 02/12/2012
R.C. 119.032 review dates: 11/21/2011 and 12/01/2015
Promulgated Under: 111.15
Statutory Authority: 4901.13 , 4935.04
Rule Amplifies: 4935.04
Prior Effective Dates: 12/10/09