Chapter 4901:1-39 Energy Efficiency Programs
(A) "Achievable potential" means the reduction in energy usage or peak demand that would result from the expected adoption by electricity consumers of the most efficient and cost-effective commercially available energy efficiency measures, taking into account applicable societal and market-related barriers to customer adoption of those measures. Achievable potential is a subset of "economic potential."
(B) "Annualized energy savings" means the recognition, in the year of installation or implementation, of the total amount of energy savings that would be achieved in a full year of service, regardless of the actual date of installation or implementation.
(C) "Anticipated savings" means the reduction in energy usage or peak demand that is expected to accrue from program participation.
(D) "Benchmark comparison method" means the comparison of customer's energy efficiency savings percentage to the electric utility's statutorily required energy efficiency savings percentage, for the purpose of determining the length of the rider exemption that the customer may receive for dedication of its energy efficiency savings to the electric utility.
(E) "Coincident peak-demand savings" means the demand savings resulting from energy efficiency measures that occur during the summer on-peak period which is defined as June through August on weekdays between two p.m. and six p.m.
(F) "Combined Heat and Power System" means the coproduction of electricity and useful thermal energy from the same fuel source designed to achieve thermal-efficiency levels of at least sixty per cent, with at least twenty per cent of the system's total useful energy in the form of thermal energy.
(G) "Commission" means the public utilities commission of Ohio.
(H) "Cost-effective" means that the measure, program, or portfolio being evaluated satisfies the total resource cost test or utility cost test, as applicable.
(I) "Demand response" means a change or potential change in customer behavior or a change in customer-owned or operated equipment that reduces the demand for electricity during specified time periods as a result of price signals or other incentives.
(J) "Economic potential" means the reduction in energy usage or peak demand that would result if all electricity consumers adopted the most efficient, cost-effective commercially available energy efficiency measures. Economic potential is a subset of technical potential.
(K) "Electric utility" has the meaning set forth in division (A)(11) of section 4928.01 of the Revised Code.
(L) "Energy baseline" means the annual average total kilowatt-hours of distribution service sold to retail customers of the electric utility in the preceding three calendar years as reported in the electric utility's most recent long-term forecast report, pursuant to division (A)(2)(a) of section 4928.66 of the Revised Code.
(M) "Energy benchmark" means the annual level of energy savings that an electric utility must achieve as provided in division (A)(1)(a) of section 4928.66 of the Revised Code.
(N) "Energy efficiency" means reducing the consumption of electrical energy, without substitution from other energy sources, while maintaining or improving the end-use customer's existing level of functionality, or while maintaining or improving the utility system functionality, or producing electricity from waste energy recovery systems or producing electricity from combined heat and power systems.
(O) "Gross savings" means the energy and demand savings that result from program activities without regard to the reasons behind the decision to participate in those programs.
(P) "Independent program evaluator" means the person(s) chosen by the commission, to monitor, verify, evaluate and report on one or more of the following activities:
(1) Electric energy savings and peak-demand reductions resulting from electric utility energy efficiency and peak demand reduction programs, as reported in the electric utility's annual performance verification process, pursuant to rule 4901:1-39-05 of the Administrative Code.
(2) Electric utility energy efficiency portfolio plan design and implementation, including evaluation of the plan's programs, measures, and cost effectiveness, and make recommendations for improvement.
(3) Recommend updates to the technical reference manual, as necessary, pursuant to changes in regulations, equipment availability, and market conditions.
(4) Appropriateness and reasonableness of all costs included in any riders designed to recover the costs of energy efficiency portfolio plan implementation from ratepayers.
(5) Perform other due-diligence reviews of evaluations and/or documentation provided by an electric utility or mercantile customer, as directed by the commission or its staff.
Such person shall work at the sole direction of the commission. If a person other than staff is chosen by the commission as an independent program evaluator, that person shall contract with the electric utility for payment for the work activities, and work at the direction of the commission or its staff.
(Q) "Measure" means any material, device, technology, operational practice, or educational program that makes it possible to deliver a comparable level and quality of end-use electrical energy service while using less electrical energy or capacity than would otherwise be required.
(R) "Mercantile customer" means a commercial or industrial customer if the electricity consumed is for nonresidential use and the customer consumes more than seven hundred thousand kilowatt hours per year or is part of a national account involving multiple facilities in one or more states, as set forth in division (A)(19) of section 4928.01 of the Revised Code.
(S) "Non-energy benefits" mean positive non-monetized impacts that do not affect the calculation of program cost-effectiveness pursuant to the total resource cost test including but not limited to low-income customer participation in utility programs, reductions in greenhouse gas emissions, reductions in regulated air emissions, reductions in natural resource depletion, enhanced system reliability, or advancement of state policy as itemized in section 4928.02 of the Revised Code.
(T) "Peak demand," when measuring reduction programs, means the average maximum hourly electricity usage during the highest one hundred hours on the electric utility's system in a calendar year.
(U) "Peak-demand baseline" means the annual average of peak demand on the electric utility's system in the preceding three calendar years as reported in the electric utility's most recent long-term forecast report, pursuant to division (A)(2)(a) of section 4928.66 of the Revised Code.
(V) "Peak-demand benchmark" means the reduction in peak demand an electric utility's system must achieve, or have the capability to achieve, as provided in division (A) (1)(b) of section 4928.66 of the Revised Code.
(W) "Person" shall have the meaning set forth in division (A)(24) of section 4928.01 of the Revised Code.
(X) "Program" means a single offering that includes one or more measures provided to electricity consumers.
(Y) "Shared savings" means the percentage of the net savings that a distribution electric utility may earn in any year in which it exceeds a statutory energy efficiency and/or peak demand reduction benchmark. The net savings is the difference in the present value of the EDU's portfolio of avoided generation, transmission and distribution costs minus the total costs of the energy efficiency programs inclusive of each program's measurement and verification costs. The net savings do not include banked savings or any savings related to historical mercantile programs, transmission and distribution infrastructure projects, customer action programs, and special improvement districts as defined in section 1710.01, Revised Code.
(Z) "Staff" means the public utilities commission's staff or authorized representative.
(AA) "Technical potential" means the reduction in energy usage or peak demand that would result if all electricity consumers adopted the most efficient commercially available energy efficiency measures.
(BB) "Total resource cost test" means an ex-ante analysis to determine if, for an investment in energy efficiency or peak-demand reduction measure or program, on a life-cycle basis, the present value of the avoided supply costs for the periods of load reduction, valued at marginal cost, are greater than the present value of the monetary costs of the demand-side measure or program borne by both the electric utility and the participants, plus the increase in supply costs for any periods of increased load resulting directly from the measure or program adoption. Supply costs are those costs of supplying energy and/or capacity that are avoided by the investment, including generation, transmission, and distribution to customers. Demand-side measure or program costs include, but are not limited to, the costs for equipment, installation, operation and maintenance, removal of replaced equipment, and program administration, net of any residual benefits and avoided expenses such as the comparable costs for devices that would otherwise have been installed, and the salvage value of removed equipment.
(CC) "Useful thermal energy" means the thermal energy output of a CHP system that is recovered for use by the facility.
(DD) "Utility cost test" means a benefit-cost test where benefits are avoided utility costs resulting from the demand-side management program, and costs are those incurred by the EDU, including incentive costs and excluding any direct customer costs. The utility cost test is also known as the program administrator cost test.
(EE) "Verified savings" means an annual reduction of energy usage or peak demand from an energy efficiency or peak-demand reduction program directly measured or calculated using methods found in the Ohio technical reference manual or other reasonable statistical and/or engineering, as approved by the commission.
(FF) "Waste Energy Recovery System" shall have the same meaning as set forth in division (A)(38) of section 4928.01 of the Revised Code.
(A) Pursuant to division (A)(1)(a) of section 4928.66 of the Revised Code, each electric utility is required to implement energy efficiency programs. Such programs, at a minimum, shall achieve established statutory energy benchmarks for energy efficiency and peak demand reduction, and may include a combined heat and power system placed into service or retrofitted on or after September 10, 2012, or a waste energy recovery system placed into service or retrofitted on or after the same date, except that a waste energy recovery system described in division (A)(38)(b) of section 4928.01 of the Revised Code may be included only if it was placed into service between January 1, 2002 and December 31, 2004. The purpose of this chapter is to establish rules for the implementation of electric utility energy efficiency and peak-demand reduction programs.
(B) The commission may, sua sponte, or 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.
(A) Assessment of potential. Unless otherwise ordered by the commission, at least once every five years, an electric utility shall conduct an assessment of potential energy savings and peak-demand reduction from adoption of energy efficiency and demand-response measures within its certified territory . Such assessment may be updated by the electric utility from time to time, at less than five year intervals, as market conditions warrant. An electric utility may collaborate with other electric utilities to co-fund or conduct such an assessment on a broader geographic basis than its certified territory. However, such an assessment must also disaggregate results on the basis of each electric utility's certified territory. Such assessment shall include, but not be limited to, the following:
(1) Analysis of technical potential. Based upon a survey and characterization of electricity- consuming facilities within its certified territory, the electric utility shall conduct an analysis of the technical potential for energy efficiency and peak-demand reduction obtainable from applying commercially available measures.
(2) Analysis of economic potential. For each available measure identified in its assessment of technical potential, the electric utility shall conduct an assessment of cost-effectiveness using either the total resource cost test or the utility cost test, whichever is applicable.
(3) Analysis of achievable potential. For each available measure identified in its analysis of economic potential as cost-effective, the electric utility shall conduct an analysis of achievable potential. Such analysis shall consider the ability of the program design to overcome barriers to customer adoption, including, but not limited to, appropriate bundling of measures.
(4) For each measure considered, the electric utility shall describe all attributes relevant to assessing its value, including, but not limited to potential energy savings or peak-demand reduction, cost, and nonenergy benefits.
(B) Program portfolio plan design criteria. When developing programs for inclusion in its program portfolio plan, an electric utility shall consider the following criteria:
(1) Relative cost-effectiveness.
(2) Benefits and costs to all members of a customer class, including nonparticipants.
(3) Potential for broad participation within the targeted customer class.
(4) Projected magnitude of aggregate energy savings or peak-demand reduction.
(5) Nonenergy benefits.
(6) Equity among customer classes.
(7) Anticipated impacts on the construction of new facilities, or the replacement , or retrofitting of existing facilities.
(8) Potential to partner the proposed program with similar programs offered by other utilities, in a cost-effective manner.
(9) Potential to bundle measures so as to avoid lost opportunities to attain energy savings or peak reductions that would not be cost-effective or would be less cost-effective if installed individually.
(10) Potential to engage the energy efficiency supply chain and leverages partners in program delivery.
(11) Potential to successfully address market barriers or market failures.
(12) Potential to leverage knowledge gained from existing program successes and failures.
(13) Opt-out customers, which are customers, as defined in section 4928.6610 of the Revised Code, which have chosen not to participate in an electric utility's energy efficiency and peak demand reduction portfolio plan.
(C) Promising measures not selected. Each electric utility shall identify measures considered but found not to be cost-effective or achievable but show promise for future deployment. The electric utility shall identify potential actions that it could undertake to improve the measure's technical potential, economic potential, and achievable potential to enhance the likelihood that the measure would become cost-effective and reasonably achievable.
(D) The electric utility may seek to collaborate or consult with other utilities, regional and municipal governmental organizations, nonprofit organizations, businesses, and other stakeholders to develop programs meeting the requirements of this chapter.
Five Year Review (FYR) Dates: 11/27/2019 and 03/26/2025
Promulgated Under: 111.15
Statutory Authority: R.C. 4901.13, 4905.04, 4905.06, 4928.02, and 4928.66
Rule Amplifies: R.C. 4928.66
Prior Effective Dates: 12/10/2009
(A) Upon the expiration of any existing commission-approved program portfolio plans, each electric utility shall continue to implement a comprehensive energy efficiency and peak-demand reduction program portfolio, which was developed pursuant to the requirements of rule 4901:1-39-03 of the Administrative Code, and which will cost-effectively achieve the statutory benchmarks for energy efficiency and peak-demand reduction. No later than September first in the last year of an existing commission approved portfolio plan, and no later than September first each year thereafter, each electric utility shall file an updated program portfolio plan to be implemented in the following calendar year, unless otherwise directed by the commission.
(B) Each electric utility shall demonstrate that its program portfolio plan is cost-effective on a portfolio basis, based on the total resource cost test. In general, each program proposed within a program portfolio plan must also be cost-effective, although each measure within a program need not be cost-effective. However, an electric utility may include a program within its program portfolio plan that is not cost-effective pursuant to the total resource cost test when that program provides substantial non-energy benefits or the electric utility can demonstrate that an alternative cost test is more appropriate.
(C) Content of filing. An electric utility's program portfolio plan shall include, but not be limited to, the following:
(1) An executive summary and its assessment of potential pursuant to paragraph (A) of rule 4901:1-39-03 of the Administrative Code.
(2) A description of stakeholder participation in program planning efforts and program portfolio development. At a minimum, each electric utility shall conduct quarterly stakeholder meetings. At these meetings, the electric utility shall provide updates on the energy efficiency and peak demand reductions achieved by its programs, all costs incurred in implementation of its programs, and information about new programs or measures that it is considering. Additionally, the electric utility shall solicit input from stakeholders on existing and potential new programs.
(3) A description of attempts to align and coordinate programs with other public utilities' programs.
(4) An analysis of existing programs. The electric utility shall provide a description of each existing program, and measures within the program, including an analysis of the success of the program and the electric utility's rationale for continuing, modifying, or eliminating the program or measures within the program.
(5) A description of programs included in the portfolio plan. An electric utility shall describe each program included within its program portfolio plan with at least the following information:
(a) A narrative describing why the program is being included pursuant to the program design criteria in this chapter. For existing programs being retained from the prior portfolio plan, a reference to the analysis described in paragraph (C)(4) of this rule is sufficient.
(b) Program objectives, including projections and basis for calculating energy savings and/or peak-demand reduction resulting from the program.
(c) The targeted customer sector.
(d) The proposed duration of the program.
(e) An estimate of the level of program participation.
(f) Program participation requirements, if any.
(g) A description of the marketing approach to be employed, including whether the electric utility intends to make use of rebates or incentives offered through each program, and how it is expected to influence consumer choice or behavior.
(h) A description of the program implementation approach to be employed.
(i) A program budget with projected expenditures, identifying program costs to be borne by the electric utility and collected from its customers, with customer class allocation, when costs will be shared among customer classes.
(j) Participant costs, if any.
(k) A description of the plan for preparing reports that document the electric utility's evaluation, measurement, and verification of the energy savings and/or peak-demand reduction resulting from each program and the process evaluations conducted by the electric utility.
(D) An electric utility, as part of its filing, may request to adjust its sales and/or demand baseline. In making such an adjustment, the baseline shall be normalized for weather and for changes in numbers of customers, sales, and peak demand to the extent such changes are outside the control of the electric utility. The electric utility shall include in its application all assumptions, rationales, and calculations, and shall propose methodologies and practices to be used in any proposed adjustments or normalizations. To the extent approved by the commission, normalizations for weather, changes in numbers of customers, sales, and peak demand shall be consistently applied from year to year. The electric utility shall modify its baseline, on a going forward basis, to exclude load and usage characteristics of all opt-out customers and the customers in its certified distribution territory with a reasonable arrangement authorized by the commission pursuant to section 4905.31 of the Revised Code.
(A) Portfolio performance report. By May fifteenth of each year, each electric utility shall file a portfolio performance report addressing the performance of its energy efficiency and peak-demand reduction programs in its program portfolio plan over the previous calendar year which includes, at a minimum, the following information:
(1) Compliance demonstration. Each electric utility shall include a section in its portfolio performance report detailing its achieved annualized energy savings, achieved demand reductions, and the demand reductions that its programs were reasonably designed to achieve, relative to its corresponding energy and peak demand reduction baselines. At a minimum, this section of the portfolio status report shall include each of the following:
(a) A benchmark report. The benchmark report shall provide the energy and peak demand baselines for kilowatt-hour sales and kilowatt demand for the reporting year, including a description of the method of calculating the baselines, and the applicable statutory benchmarks for energy savings and electric utility peak-demand reduction, with supporting data.
(b) A comparison of actual annualized energy savings and peak-demand reductions achieved by electric utility programs with the applicable benchmarks. An electric utility shall not provide a financial or rider exemption incentive for, but may count in meeting any statutory benchmark, the adoption of measures that are required to comply with energy performance standards set by law or regulation, including but not limited to, those embodied in federal standards, or an applicable building code. The prohibition against a financial or rider exemption incentive does not preclude the electric utility from compensating a customer for the administrative costs and inconvenience of undertaking the commitment process, in the form of a commitment payment.
(c) Banking surplus energy savings. To the extent that an electric utility's actual energy savings exceeds its energy efficiency benchmark for any year, the electric utility may apply such surplus energy savings to its energy efficiency benchmarks for a subsequent year. Banked surplus may be used by the utility to trigger the shared savings incentive. However, the shared savings incentive is only eligible for energy and demand savings achieved in the current program year.
(d) Benchmarks not reasonably achievable. If an electric utility determines that it is unable to meet a benchmark due to regulatory, economic, or technological reasons beyond its reasonable control, the electric utility may file an application to amend its benchmarks.
(e) The electric utility shall specify the methodology it has used to measure and verify its energy efficiency and peak-demand reduction savings. An electric utility's methodologies for measuring and verifying its energy efficiency and peak demand reduction savings will be presumed reasonable if they follow the measurement and verification methodologies specified in the technical reference manual published by the commission's staff. If an electric distribution utility utilizes different methodologies to measure and verify the energy efficiency and peak demand reduction savings it has achieved, the electric distribution utility shall demonstrate that the measurement and verification methodologies it relies upon are reasonable.
(f) The electric utility shall include a summary of program savings and expenditures in a template prescribed by staff.
(2) Program performance assessment. Each electric utility shall include a section in its portfolio performance report demonstrating whether it has successfully implemented the energy efficiency and demand-reduction programs in its program portfolio plan. At a minimum, this section of the annual portfolio performance report shall include each of the following:
(a) A description of each energy efficiency or peak-demand reduction program implemented in the previous calendar year including:
(i) The key activities undertaken in each program, the number and type of participants, a comparison of the forecasted savings to the verified savings achieved by such program, the magnitude of anticipated savings, and a trend analysis of how anticipated savings will be realized over the life of the program.
(ii) All energy savings and peak-demand reductions counted toward the applicable benchmark as a result of energy efficiency improvements, demand response, or demand reduction improvements implemented by mercantile customers and committed to the electric utility.
(iii) A description of all transmission and distribution infrastructure improvements made by the electric utility that reduce line losses to the extent the reduction in line losses has been applied to meet the applicable benchmarks with a calculation and description of the net impact of such improvements on losses.
(iv) A description of all other applicable energy efficiency and peak demand reduction activities that the electric utility proposes to count toward its applicable benchmarks.
(b) An evaluation, measurement, and verification report that documents the energy savings and peak-demand reduction values and the cost-effectiveness of each energy efficiency and demand-side management program reported in the electric utility's portfolio status report. Such report shall include documentation of any process evaluations and expenditures, measured and verified savings, and cost-effectiveness of each program. Measurement and verification processes shall confirm that the measures were actually installed, the installation meets reasonable quality standards, and the measures are operating correctly and are expected to generate the predicted savings.
(B) Independent program evaluator report. The independent program evaluator may conduct its report-related review activities on an ongoing basis, including during the implementation of the electric utility's program portfolio plan, subsequent to completion of the plan year, and subsequent to the filing of the electric utility's portfolio performance report. The electric utility shall cooperate with the independent program evaluator as it conducts its review activities. Subsequent to the filing of the electric utility's portfolio performance report, the independent program evaluator will prepare and file a report which shall include, but is not limited to, the following:
(1) A description of the independent program evaluator's activities, analyses, and conclusions in monitoring, verifying, and evaluating the energy savings and peak-demand reductions resulting from the electric utility programs and mercantile customer activities.
(2) The independent program evaluator's verification and evaluation, through the use of due-diligence techniques including project inspections, of the electric utility's evaluation, measurement, and verification report.
(3) An evaluation of the electric utility's energy efficiency portfolio plan's programs, measures, cost-effectiveness, and the appropriateness of all costs included in the electric utility's energy efficiency cost recovery riders.
(C) The independent evaluator shall file recommended revisions to the technical reference manual, in addition to its report filed pursuant to paragraph (B) of this rule.
(D) Any person may file comments regarding an electric utility's annual portfolio performance report and the independent program evaluator's report filed pursuant to this chapter within thirty days after the filing of the independent program evaluator's report. Reply comments shall be due fifteen days later.
(E) Based upon the recommendations of the independent program evaluator relative to the electric utility's performance, and the comments received on the reports pursuant to paragraph (D) of this rule, the commission may schedule a hearing in order to review the electric utility's performance in meeting its annual statutory requirements for energy efficiency and peak demand reduction, or issue its opinion and order.
(F) Based upon the recommendations of the independent program evaluator relative to revisions to the technical reference manual, and the comments received on the independent program evaluator's recommendations pursuant to paragraph (D) of this rule, the commission's staff shall direct the independent program evaluator to file an updated technical reference manual. Unless otherwise indicated by the commission, the updated technical reference manual shall be deemed to be automatically approved on the thirtieth day after its filing.
(A) Concurrent with the filing of its program portfolio plan, the electric utility shall file a proposed rate adjustment mechanism for recovery of costs incurred in implementing its energy efficiency, peak-demand reduction, and demand response programs. If the electric utility proposes to include for recovery anything in addition to direct program implementation costs, the electric utility shall demonstrate how it proposes such recovery to occur and why such recovery is appropriate and necessary.
(B) Unless otherwise ordered by the commission, any person may file comments within thirty days after the filing of an electric utility's proposed recovery mechanism. Any person filing comments shall specify the basis for all recommendations made, or modifications that are suggested to be made to the electric utility's proposed recovery mechanism. Based on comments received, the commission may schedule a hearing on the proposed recovery mechanism. If the commission takes no action within thirty days of receiving comments, the recovery mechanism shall be automatically deemed to be reasonable. Any revenue received under the electric utility's rate adjustment mechanism shall be subject to potential disallowance and reconciliation based on the commission's decision issued in the annual performance verification process in rule 4901:1-39-05 of the Administrative Code.
(A) An application to commit a mercantile customer's energy efficiency program, or a customer's combined heat and power system or waste energy recovery system, to its electric utility's programs, pursuant to division (A)(2) of section 4928.66 of the Revised Code, may include a request for an incentive payment based on payment levels established in the electric utility's portfolio plan, or a commitment payment for behavioral programs, combined heat and power systems, waste energy recovery systems, or other payment for efficiency savings that do not qualify for an incentive payment, or an exemption from the cost recovery mechanism set forth in rule 4901:1-39-06 of the Administrative Code. Such application shall be filed pursuant to the requirements set forth in paragraph (C) of this rule. Alternatively, an application for an incentive payment, commitment payment, or cost recovery mechanism exemption may be combined with any other reasonable arrangement, approved pursuant to Chapter 4901:1-38 of the Administrative Code, if such reasonable arrangement contains appropriate measurements and verification of program results.
(B) In meeting its energy efficiency and peak-demand reduction benchmarks, an electric utility shall include mercantile customer energy efficiency, peak demand reduction, combined heat and power, and waste energy recovery programs implemented on mercantile customer sites where the mercantile program is committed to the electric utility.
(1) For energy efficiency programs, an electric utility may count the programs' effects resulting in energy savings and coincident peak-demand savings towards its energy efficiency requirements and peak demand reduction requirements.
(2) For demand response programs, an electric utility may count demand reductions towards its peak-demand reduction benchmarks by demonstrating that either the electric utility has reduced its actual peak demand, or has the capability to reduce its peak demand and such capability is created under either of the following circumstances:
(a) A peak-demand reduction program meets the requirements to be counted as a capacity resource under the tariff or capacity auction of the regional transmission organization in which the electric utility is a member and which has been approved by the federal energy regulatory commission.
(b) A peak-demand reduction program equivalent to a regional transmission organization program, which has been approved by the commission.
(3) A mercantile customer's energy savings and peak-demand reductions shall be presumed to be the effect of a demand response, energy efficiency, or peak-demand reduction program to the extent they involve the replacement of functioning equipment. If the mercantile customer's program involves the replacement of non-functioning equipment or an initial installation of new equipment, the electric utility may count the savings based on the efficiency of the replaced equipment, if any, but may provide a financial or rate exemption incentive based only on the reductions in energy use and peak demand that exceed the reductions or levels that would have occurred had the customer used standard new equipment or practices where practicable. However, nothing in this section prohibits the electric utility from compensating a mercantile customer for the administrative costs and inconvenience of undertaking the commitment process, in the form of a commitment payment. Electric utilities may make an alternative demonstration, subject to commission approval, that mercantile customer energy savings or peak demand reductions are eligible to be counted toward the electric utility's statutory requirements.
(4) Inclusion of all such mercantile customer energy efficiency and peak demand reduction programs shall be subject to commission approval and subsequent verification through the annual performance verification process, pursuant to rule 4901:1-39-05 of the Administrative Code.
(C) A mercantile customer may file, either individually or jointly with an electric utility, an application to commit the customer's demand reduction, demand response, or energy efficiency programs or the output of the customer's combined heat and power system or waste energy recovery system that have been implemented in the previous three years for integration with the electric utility's demand reduction, demand response, and energy efficiency programs, pursuant to division (A)(2) of section 4928.66 of the Revised Code. Such application, if filed individually, shall be filed no later than December thirty-first of the calendar year following the end of the three-year period. However, such applications that are filed jointly shall be filed no later than March thirty-first of the year following the individual application deadline, but only if the mercantile customer commitment agreement with the electric utility was executed by the individual filing deadline.
(1) Any such application filed in accordance with the automatic approval template published by the commission shall be deemed automatically approved unless suspended by order of the commission or an attorney examiner within sixty days of the filing of the application.
(2) Commitment of a mercantile customer's behavioral energy efficiency program that is made pursuant to a commitment payment shall be counted by the electric utility for one year. Subsequent annual applications may be made if the behavioral program continues. After five consecutive years of approved commitment payment applications, the energy efficiency savings shall be counted as permanent by the electric utility, and no additional payments will be made to the customer. If the energy savings levels vary from year to year during the five year period, the lowest of the energy savings levels shall be counted as permanent by the electric utility, and no additional payments will be made to the customer.
(3) No exemption from an energy efficiency cost recovery rider granted pursuant to an automatic approval shall extend more than one year unless the mercantile customer, or the electric utility on behalf of the mercantile customer, provides an annual update to staff on such form as published by the commission. The length of rider exemption shall be determined by the use of the benchmark comparison method.
(4) An application to commit a mercantile customer's demand reduction, demand response, or energy efficiency program to the electric utility that is not filed in accordance with the commission's automatic approval template, shall not be deemed automatically approved. Such an application shall address the following areas:
(a) Coordination requirements between the electric utility and the mercantile customer with regard to voluntary reductions in load by the mercantile customer, which are not part of an electric utility program, including specific communication procedures.
(b) Grant permission to the electric utility and staff to measure and verify energy savings and/or peak-demand reductions resulting from customer-sited projects and resources.
(c) Identify all consequences of noncompliance by the customer with the terms of the commitment.
(d) Include a copy of the formal declaration or agreement that commits the mercantile customer's programs for integration, including any requirement that the electric utility will treat the customer's information as confidential and will not disclose such information except under an appropriate protective agreement or a protective order issued by the commission pursuant to rule 4901-1-24 of the Administrative Code.
(e) Include a description of all methodologies, protocols, and practices used or proposed to be used in measuring and verifying program results, and identify and explain all deviations from any program measurement and verification guidelines that may be published by the commission.
Five Year Review (FYR) Dates: 11/27/2019
Promulgated Under: 111.15
Statutory Authority: R.C. 4901.13, 4905.04, 4905.06, 4928.02, and 4928.66
Rule Amplifies: R.C. 4928.66
Prior Effective Dates: 12/10/2009