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Home My Public Portal About001-2021 - Revise Rates and Charges for RP&L Services RESOLUTION NO. 001-2021 A RESOLUTION OF THE BOARD OF DIRECTORS OF RICHMOND POWER& LIGHT BECOMMENPING TfJ ESTAB .IS1IMENT OF REVISED RATES AND CHARGES FOR'111E USE OF,AND SERVICES PROVIDED BY, RICHMOND POWER&LIGHT WHEREAS,the Board of Directors ("Board") of Richmond Power& Light(the "Utility") desires to continue to provide adequate and efficient electric service for the protection of the health, well-being and property of the City of Richmond and its electric customers; and WHEREAS,the existing rates and charges for electric services provided by the Utility were placed into effect following approval by the Indiana Utility Regulatory Commission(the "Commission") in Cause No. 42713 in a Final Order dated February 9, 2005; and WHEREAS,the Board has the fiduciary responsibility of making recommendations to the Common Council relative to the need for the adoption of revised electric rates and charges; and WHEREAS, in Resolution 1-2020,the Board recommended to the Richmond Common Council that the Utility file new rates and charges for approval by the Indiana Utility Regulatory Commission("Commission"); and WHEREAS,pursuant to Ordinance#11-2020 approved February 11, 2020, RP&L filed a petition with the Commission for a new schedule of rates and charges which would have increased the Utility's rates by approximately 9.58%in three phases; and WHEREAS,the Utility reached a Settlement Agreement in that proceeding with the State's consumer advocate,the Indiana Office of the Utility Consumer Counselor("OUCC"), resolving all issues and agreeing to lower the Utility's requested rate increase to only 7.23% in three phases; and WHEREAS,the Commission approved this Settlement Agreement in a Final Order issued January 20, 2021, along with the Utility's statutory revenue requirements, and revenues from rates and charges as set forth in IC 8-1.5-3-8, including a reasonable return on Rate Base; and WHEREAS,the Utility's customers and the general public have already received legal notice and the opportunity to be heard regarding the proposed rate increase, both before the Council and the Commission, and this rate increase is less than originally proposed,to the benefit of the Utility's customers; and NOW, THEREFORE,BE IT RESOLVED by the Utility Service Board that the attached schedule of as-settled rates and charges approved by the Commission should be recommended for approval by the Common Council by Rate Ordinance. BE IT FURTHER RESOLVED WHEREAS,the Board finds the Settlement Agreement to be a reasonable, as approved by the Commission; and(ii)pursuant to IC 8-1.5-3-4(a)(7) recommended said rates and charges to the Common Council for its review and approval. PASSED AND ADOPTED BY THE BOARD OF DIRECTORS OF RICHMOND POWER&LIGHT THIS DAY Cs 7��E / 21. BOARD OF DIRECTORS OF RICHMOND POWER& LIGHT By: Chairman Att t: Exhibit A 2021 New Schedule of Rates and Charges for Richmond Power& Light CERTIFICATE OF SERVICE I certify that a copy of the foregoing was served upon the following via electronic mail this 20th day of January, 2021: Randy Helmen Lorraine Hitz-Bradley Indiana Office of the Utility Consumer Counselor PNC Center, Suite 1500 South 115 West Washington Street Indianapolis, IN 46204 rhelmen@oucc.in.gov lhitzbradley@oucc.in.gov infomgt a,oucc.in.gov Kristina Kern Wheeler Bose McKinney&Evans LLP 111 Monument Circle, Suite 2700 Indianapolis, IN 46204 (317) 684-5000 (317) 684-5173 Fax 3994828_1 ii 1 RICHMOND POWER AND LIGHT RATES AND CHARGES FOR ELECTRIC SERVICE RICHMOND, INDIANA PURUSUANT TO IURC FINAL ORDER IN CAUSE NO. 45361 EFFECTIVE: JANUARY 20, 2021 The supplying of, and billing for, service and all conditions applying thereto, are subject to the Utility's General Terms and Conditions adopted by the Richmond Utility Service Board on October 19,2004. • Table of Contents Appendix A—Quarterly Wholesale Purchase Power/Energy Cost Adjustment(ECA) 3 Appendix B—Non-Recurring Charges 4 Residential Electric Service(R) 5 Commercial Lighting Service(CLS) 6 General Power Service(GPS) 8 Large Power Service Secondary(LPSS) 11 Large Power Service Secondary Optional Coincident Peak Service(LPSS COIN) 13 Large Power Service Primary(LPSP) 15 Large Power Service Primary Optional Coincident Peak Service(LPSP COIN) 17 Industrial Service Secondary(ISS) 19 Industrial Service Secondary Optional Coincident Peak Service(ISS-COIN) 21 Industrial Service Primary(ISP) 23 Industrial Service Primary Optional Coincident Peak Service(ISP-COIN) 25 Transmission Service(TS) 27 Transmission Service Optional Coincident Peak Service(TS-COIN) 29 Lighting Service (LS) 31 Electric Heating Schools (EHS) 36 General Electric Heating(GEH) 37 Electric Vehicle Charging Program—Public Location (EV-PP) 39 Rider NM—Net Metering 41 Rider ED—Economic Development 45 Rider QF—Qualifying Facilities 47 Rider IS—PJM-DRS-Emergency 55 2 Richmond Power and Light Rate Schedule Appendix A—Quarterly Wholesale Purchase Power/Energy Cost Adjustment (ECA) RATE ADJUSTMENTS The Rate Adjustments shall be on the basis of a Purchase Power Cost Adjustment Tracking Factor occasioned solely by changes in the cost of purchased power and energy, in accordance with the Order of the Indiana Utility Regulatory Commission (IURC or Commission), approved December 13, 1989 in Cause No. 36835-S3, as follows: Rate Adjustments applicable to the below listed Rate Schedules are as follows: • Rate Schedule , ECA Adjustment 1 Billing Unit R $X.XXXXX Per kWh CL $X.XXXXX Per kWh EHS $X.X0XXX Per kWh GP and GEH $X.XX Per kW $X.XXXXX Per kWh LPSS $X.XX Per kVA $X.XXXXX Per kWh LPSS Coincident $X.XX Per kW $X.XXXXX Per kWh LPSP $X.XX Per kVA $X.XXXXX Per kWh LPSP Coincident $X.XX Per kW $X.XXXXX Per kWh ISS $X.XX Per kVA $X.XXXXX Per kWh ISS Coincident $X.XX Per kW $X.XXXX X Per kWh ISP $X.XX Per kVA $X.XXXXX Per kWh ISP Coincident $X.XX Per kW $X.XXXXX Per kWh LS $X.X>000X Per kWh TS $X.XX Per kVA $X.XXXXX Per kWh TS Coincident $X.XX Per kW $X.XXXXX Per kWh (Insert Applicable Quarterly Version As Currently Approved by the IURC -- Last Approved January 13, 2021 for 1st Quarter 2021. The first ECA under the new ECA rate design approved by the January 20,2021 Final Order in Cause No. 45361 will be for 2nd Quarter, 2021.) 3 Richmond Power and Light Rate Schedule Appendix B—Non-Recurring Charges Description of Charge Fee Dishonored Check Charge: $30.00 Connect/Disconnect Charge: At the Meter(Normal Hours) $40.00 At the Meter (After Hours—Non-Sunday and Non-Holiday) $70.00 At the Meter (After Hours—Sunday or Holiday) $90.00 At the Pole (Normal Hours). $100.00 At the Pole (After Hours) $150.00 Late Payment Charge A late payment charge of three percent(3%) of all bills will be charged if the bill is not paid by the due date printed on the bill Initiate service—Same day connect(Customer requested after 12PM) $40.00 Meter Test Charge: All Meters 2 x free/24 months, 3xis $100 Meter Tampering Charge: Actual labor, materials, vehicle, and estimated energy usage at applicable rate Trip Charge ($/hr): $25.00 4 Effective: January 20, 2021 Richmond Power and Light Rate Schedule Residential Electric Service(R) AVAILABILITY Service to Residential Customers, including Rural Customers for all domestic uses in individual private Customer-occupied residences or dwellings and their appurtenances, when all service is taken through one meter. When service is supplied to a residential dwelling unit where the use is primarily for the accommodations of roomers or boarders, the service will be provided under Rate Schedule CL,the commercial lighting rate schedule,unless separate circuits are furnished by the Customer to permit the Richmond Power & Light Company (the Utility) to separately meter and bill the residential and commercial uses. CHARACTER OF SERVICE Alternating current, 60 Hertz, single phase, at a voltage of approximately 120 volts two-wire, 120/240 volts three-wire, or 120/208 volts three-wire as designated by the Utility. RATE* _ Residential Units Phase 1 Phase 2 Phase 3 Facilities Charge $/Month $10.75 $11.50 $12.25 Energy Charge: Tier 1 for the first 350 kWh $/kWh $0.10110 $0.10151 $0.10191 Tier 2 for the next 1150 kWh $/kWh $0.09360 $0.09760 $0.10191 Tier 3 for all kWh above 1500 kWh $/kWh $0.08610 $0.09401 $0.10191 * Subject to the provisions of Appendices A and B. MINIMUM CHARGE The minimum monthly charge shall be the Facilities Charge. SPECIAL TERMS AND CONDITIONS This rate schedule is available for single phase service only, except as required by the Utility. Where three-phase service will be used for commercial or industrial purposes, the applicable rate schedules will apply to such service. 5 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 Richmond Power and Light Rate Schedule Commercial Lighting Service (CLS) AVAILABILITY Service to Commercial and Non-Residential Customers for lighting, appliances, and incidental power not exceeding 11 kW in aggregate capacity when such combined service is furnished through a single metering installation. CHARACTER OF SERVICE Alternating current, 60 Hertz, single phase, at a voltage of approximately 120 volts two-wire, 120/240 volts three-wire, or 120/208 volts three-wire or three phase 120/240 volts three-wire or 120/208 volts four-wire as designated by the Richmond Power& Light Company (the Utility). RATE* Commercial Lighting Units Phase 1 Phase 2 Phase 3 Facilities Charge $/Month $20.75 $20.75 $20.75 Energy Charge $/kWh $0.12124 $0.12124 $0.12124 * Subject to the provisions of Appendices A and B. MINIMUM CHARGE The minimum monthly charge shall be the Facilities Charge. METERING ADJUSTMENT If service is metered at a voltage of approximately 2,400 volts or higher,the energy measurements shall be decreased by two percent(2%)to convert such measurement to the equivalent of metering at the Utility's secondary voltage. SPECIAL TERMS AND CONDITIONS Electric service will be available under this rate schedule for the operation of Cable Television (CATV) distribution line power supply equipment. Such service will be available only on a metered basis and for purposes of billing, each CATV Customer will be billed on an add consumption basis for their total service under this rate schedule; provided, however, each individual delivery point for such CATV Customer shall be billed the Facilities Charge of this rate schedule. 6 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 This rate schedule is available for single phase service only, except as required by the Utility. Where three-phase service will be used for commercial or industrial purposes, the applicable rate schedules will apply to such service 7 Phase 1 Effective: January 20,2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 • Richmond Power and Light Rate Schedule General Power Service (GPS) AVAILABILITY Service to any Customer for general power purposes when the Customer's load exceeds 11 kW, but does not exceed 60 kW, and/or the Customer has any three-phase power load served from the distribution system. CHARACTER OF SERVICE Alternating current having a frequency of 60 Hertz and furnished at a voltage, which is standard with the Richmond Power& Light Company (the Utility) in the area served. RATE* General Power Units Phase 1 Phase 2 Phase 3 Facilities Charge $/Month $46.50 $73.00 $73.00 Energy Charge: Tier 1 for the first 500 kWh $/kWh $0.09946 $0.07600 $0.07600 Tier 2 for the next 1,500 kWh $/kWh $0.09613 $0.07600 $0.07600 Tier 3 for the next 3,000 kWh $/kWh $0.09279 $0.07600 $0.07600 Tier 4 for all kWh above 5,000 kWh $/kWh $0.08946 $0.07600 $0.07600 Demand Charge: Tier 1 for up to 25 kW $/kW $1.40 $6.50 $6.50 Tier 2 for each kW of demand in excess of 25 kW $/kW $2.80 $6.50 $6.50 * Subject to the provisions of Appendices A and B. MINIMUM CHARGE The minimum monthly charge shall be the Facilities Charge plus the Demand Charge. MEASUREMENT OF DEMAND 8 Phase 1 Effective: January 20,2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20,2023 All demand shall be measured by suitable instruments and, in any month the demand shall be the average number of kWs in the 30-minute interval during which the energy metered is greater than in any other 30-minute interval in such month. METERING ADJUSTMENT If service is metered at a voltage of approximately 2,400 volts or higher, the demand and energy measurements shall be decreased by two percent (2%) to convert such measurements to the equivalent of metering at the Utility's secondary voltage. EQUIPMENT SUPPLIED BY CUSTOMER When the Customer furnishes and maintains substation equipment including any and all transformers, and/or switches, and/or the equipment necessary to take its entire service at the primary voltage of the distribution line from which the service is to be received, a credit of $0.47 per kW of billing demand will be applied to each month's net bill. TERMS AND CONDITIONS FOR RENDERING SERVICE 1. Incidental lighting will be permitted provided the Customer furnishes the necessary equipment to take such lighting from the power service. 2. The Company will supply and maintain at a single location,the complete substation equipment that is necessary in order to make one transformation to a standard voltage from the voltage of such available distribution line as the Utility deems adequate and suitable to serve the requirements of the Customer. Not more than one such transformation will be installed at the Utility's expense for any one Customer. Where service is metered at a primary voltage and the Customer desires and requests transformation to more than one standard voltage, or service of a standard voltage at more than one location within its premises, the Utility will, at its option, furnish and maintain such additional transformation equipment and such interconnecting lines as may be necessary; provided, however, that the Customer shall reimburse the Utility for the amount of the cost of furnishing the entire facilities, which is in excess of the cost of furnishing transformation in accordance with the next paragraph. The right and title to all equipment so furnished by the Utility shall be and remain in the Utility. Should the Customer require a non-standard voltage, the Customer shall, at its own expense, furnish and maintain all transformers and protective equipment therefore necessary in order to obtain such non-standard voltage. 3. All service hereunder shall be furnished through one meter. 9 Phase 1 Effective: January 20,2021 Phase 2 Effective: January 20,2022 Phase 3 Effective: January 20, 2023 4. All wiring,pole lines, wires, and other electrical equipment and apparatus located beyond the point of connection of the Customer's service lines with the lines of the Utility are considered the distribution system of the Customer and shall be furnished, owned, and maintained by the Customer, except in the case of metering equipment and other equipment incidental to the rendering of service,if any,that is furnished,owned and maintained by the Utility and installed beyond the point of connection. 5. When fire or other casualty shall render the physical plant or premises of the Customer unfit for the purposes of conducting the Customer's normal business operations, or makes the premises uninhabitable,the minimum charge of this rate schedule shall, commencing with the first billing period or portion thereof in which normal business operations cease, be waived until the beginning of the subsequent billing period or portion thereof in which the plant or premises shall have been reconstructed and reoccupied by the Customer. When a strike or lockout of employees of the Customer causes the temporary suspension of the Customer's business,the minimum charge of this rate schedule shall, commencing with the first billing period or portion thereof in which normal business operations cease,be waived for each period or portion thereof during the continuance of the strike or lockout at the plant involved. In either event, the Customer shall be billed under this rate schedule for electric requirements used during each billing period. 10 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20,2023 Richmond Power and Light Rate Schedule Large Power Service Secondary (LPSS) AVAILABILITY Available for general service through one meter to any Customer having a maximum load requirement of at least 60 kW,but not exceeding 1,000 kW, served at secondary voltage. Customer must be located adjacent to the Richmond Power&Light Company's(the Utility) distribution line that is adequate and suitable for supplying the service requested. CHARACTER OF SERVICE Alternating current having a frequency of 60 Hertz and furnished at a voltage, which is standard with the Utility in the area served. RATE* Large Power Service Secondary. Units , Phase,l _ Phase 2 Phase_3 Facilities Charge $/Month $195.25 $195.25 $195.25 Energy Charge $/kWh $0.03757 $0.03515 $0.03515 Demand Charge $/kVA $22.50 $25.00 $25.00 * Subject to the provisions of Appendices A and B. MINIMUM CHARGE The minimum monthly charge shall be the Facilities Charge plus the Demand Charge. METERING ADJUSTMENT If service is metered at a voltage of approximately 2,400 volts or higher,the demand measurements and the energy measurements shall be decreased by two percent (2%) to convert such measurements to the equivalent of metering at the Utility's secondary voltage. MEASUREMENT OF DEMAND AND ENERGY Peak demand shall be measured by suitable recording instruments provided by the Utility and shall be the average number of kVAs in the 30-minute period during which the kVA demand is greater than in any other 30-minute interval in such month. For billing purposes,the billing demand shall be the greater of the peak demand occurring during the month or 60 kVA. Energy shall be measured by suitable integrating instruments. 11 Phase 1 Effective: January 20,2021 Phase 2 Effective: January 20,2022 Phase 3 Effective: January 20,2023 TERMS AND CONDITIONS FOR RENDERING SERVICE 1. The Utility will supply and maintain at a single location, the complete substation equipment that is necessary in order to make one transformation to a standard voltage from the voltage of such available distribution line as the Utility deems adequate and suitable to serve the requirements of the Customer. Not more than one such transformation will be installed at the Utility's expense for any one Customer. Where service is metered at a primary voltage and the Customer desires and requests transformation to more than one standard voltage, or service of a standard voltage at more than one location within its premises, the Utility will, at its option, furnish and maintain such additional transformation equipment and such interconnecting lines as may be necessary; provided, however,that the Customer shall reimburse the Utility for the amount of the cost of furnishing the entire facilities, which is in excess of the cost of furnishing transformation in accordance with the next paragraph. The right and title to all equipment so furnished by the Utility shall be and remain in the Utility. Should the Customer require a non-standard voltage, the Customer shall, at its own expense, furnish and maintain all transformers and protective equipment therefore necessary in order to obtain such non-standard voltage. 2. When fire or other casualty shall render the physical plant or premises of the Customer unfit for the purposes of conducting the Customer's normal business operations, or makes the premises uninhabitable,the minimum charge of this rate schedule shall, commencing with the first billing period or portion thereof in which normal business operations cease, be waived until the beginning of the subsequent billing period or portion thereof in which the plant or premises shall have been reconstructed and reoccupied by the Customer. When a strike or lockout of employees of the Customer causes the temporary suspension of the Customer's business,the minimum charge of this rate schedule shall, commencing with the first billing period or portion thereof in which normal business operations cease,be waived for each period or portion thereof during the continuance of the strike or lockout at the plant involved. In either event, Customer shall be billed under this rate schedule for electric requirements used during each billing period. 12 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 Richmond Power and Light Rate Schedule Large Power Service Secondary Optional Coincident Peak Service (LPSS COIN) AVAILABILITY Secondary service to any Customer whose electric service is provided under Rate Schedule LPSS - Large Power Service Secondary, who agrees to participate in this Demand Side Management Program to reduce load during the Richmond Power&Light Company's (the Utility)net system peak hour each month, and who contracts for Optional Coincident Peak Service. Potential Customers must demonstrate to the Utility's satisfaction that the Customer has the ability to move kW demand from the on-peak period to the off-peak period. Customers taking service under Rate LPSS must move a minimum of five percent(5%) of kW demand from the on-peak period to the off-peak period as compared to its level of on-peak demand prior to taking service under this Rate. Customers will be evaluated during the first 12 months of taking service under this Rate to determine if the Customer is moving five percent(5%) of kW demand from the on-peak period to the off-peak period. If, in the sole judgment of the Utility, a Customer is not consistently moving a significant amount of kW demand from the on-peak period to the off-peak period,the Customer must take service from another applicable Rate. RATE* Large Power COIN— Service Secondary Units Phase 1 Phase 2 Phase 3 Facilities Charge $/Month $195.25 $195.25 $195.25 Energy Charge $/kWh $0.03441 $0.03317 $0.02870 Billing Demand Charge $/kW $23.81 $25.37 $26.90 Transmission and Distribution Demand Charge(in addition to Billing Demand and Energy Charge) $/kVA $3.33 $4.47 $5.60 * Subject to the provisions of Appendices A and B. MINIMUM CHARGE The minimum monthly charge shall be the Facilities Charge, Demand Charge, plus the Transmission and Distribution Demand Charge. In any month the maximum Transmission and Distribution demand shall not be less than 60 kVA. MEASUREMENT OF DEMAND AND ENERGY 1. Billing Demand shall be measured by suitable recording instruments provided by Utility and in any month, the demand shall be the 60-minute integrated kW demand and occurring in the 13 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 same 60-minute interval and on the same day of each month as the 60-minute integrated that Utility will use to determine Utility's power supply billing demands. 2. If Customer fails to maintain a ninety-six percent (96%) power factor during the 60-minute coincident demand period,the Billing Demand will be adjusted as follows: Billing Demand x 96% Actual Power Factor 3. Transmission and Distribution Demand shall be for any month the number of kVAs in the 30-minute interval during which the kVAs are greater than in any other 30-minute interval in such month. 4. Energy shall be measured by suitable integrating instruments. 5. For Purposes of the determination of Billing Demand, Maximum Demand and Energy, the provisions of the Metering Adjustment of Rate LPSS will be applicable. NOTIFICATION TO CUSTOMER The Utility will assist the Customer in reducing the billings under the Demand Charge provision of the Rate Schedule by making their best efforts to notify the Customer at least one-half hour prior to the anticipated hour of the Billing Demand for each month. Such notification may occur multiple times each month. Such notification will give the Customer the opportunity to reduce its demand during the hour of the Billing Demand. The Utility shall not be held responsible for failure to accurately predict the hour of such Billing Demand or for failure to notify the Customer one-half hour in advance of the hour of such Billing Demand or for the Customer's failure to reduce its demand when notified of an impending Billing Demand. 14 Phase 1 Effective: January 20,2021 Phase 2 Effective: January 20,2022 Phase 3 Effective: January 20,2023 • Richmond Power and Light Rate Schedule Large Power Service Primary (LPSP) AVAILABILITY Available for general service through one meter to any Customer having a maximum load requirement of at least 60 kW,but not exceeding 1,000 kW, served at primary voltage. Applicant must be located adjacent to the Richmond Power&Light Company's(the Utility) distribution line that is adequate and suitable for supplying the service requested. CHARACTER OF SERVICE Alternating current having a frequency of 60 Hertz and furnished at a voltage, which is standard with the Utility in the area served. RATE* Large PowerService Primary Units Phase 1 Phase 2, Phase 3, Facilities Charge $/Month $195.25 $195.25 $195.25 Energy Charge $iWh $0.03574 $0.03561 $0.03548 Demand Charge $/kVA $22.84 $22.99 $23.13 * Subject to the provisions of Appendices A and B. MINIMUM CHARGE The minimum monthly charge shall be the Facilities Charge plus the Demand Charge. MEASUREMENT OF DEMAND AND ENERGY Peak demand shall be measured by suitable recording instruments provided by Utility and shall be the average number of kVAs in the 30-minute period during which the kVA demand is greater than in any other 30-minute interval in such month. For billing purposes, the billing demand shall be the greater of the peak demand occurring during the month or 60 kVA. Energy shall be measured by suitable integrating instruments. 15 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 TERMS AND CONDITIONS FOR RENDERING SERVICE 1. This rate schedule is based upon the delivery and measurement of energy at the primary voltage of existing distribution lines operating at not more than 15,000 volts, or less than 2,400 volts, and the Customer furnishing and maintaining the complete substation and line equipment on the Customer's premises, including any and all transformers, switches, and other apparatus necessary for the Customer to take service at the voltage of the distribution line from which service is to be served. 2. When fire or other casualty shall render the physical plant or premises of the Customer unfit for the purposes of conducting the Customer's normal business operations, or makes the premises uninhabitable,the minimum charge of this rate schedule shall, commencing with the first billing period or portion thereof in which normal business operations cease, be waived until the beginning of the subsequent billing period or portion thereof in which the plant or premises shall have been reconstructed and reoccupied by the Customer. When a strike or lockout of employees of the Customer causes the temporary suspension of the Customer's business,the minimum charge of this rate schedule shall, commencing with the first billing period or portion thereof in which normal business operations cease,be waived for each period or portion thereof during the continuance of the strike or lockout at the plant involved. In either event, the Customer shall be billed under this rate schedule for electric requirements used during each billing period. In either event, the Customer shall be billed under this rate schedule for electric requirements used during each billing period. 16 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 Richmond Power and Light Rate Schedule Large Power Service Primary Optional Coincident Peak Service (LPSP COIN) AVAILABILITY Service to any Customer whose electric service is provided under Rate Schedule LPSP —Large Power Service Primary, who agrees to participate in this Demand Side Management Program to reduce load during the Richmond Power & Light Company's (the Utility) net system peak hour each month, and who contracts for Optional Coincident Peak Service. Potential Customers must demonstrate to the Utility's satisfaction that the Customer has the ability to move kW demand from the on-peak period to the off-peak period. Customers taking service under Rate LPSP must move a minimum of five percent (5%) of kW demand from the on-peak period to the off-peak period as compared to its level of on-peak demand prior to taking service under this Rate. Customers will be evaluated during the first 12 months of taking service under this Rate to determine if the Customer is moving a minimum of five percent (5%) of kW demand from the on-peak period to the off-peak period. If, in the sole judgment of the Utility, a Customer is not consistently moving a significant amount of kW demand from the on-peak period to the off-peak period,the Customer must take service from another applicable Rate. RATE* Large Power COIN—Service Primary : Units Phase 1 Phase 2 . . Phase 3 Facilities Charge $/Month $195.25 $195.25 $195.25 Energy Charge $/kWh $0.03273 $0.02897 $0.02897 Billing Demand Charge $/kW $24.43 $26.34 $26.34 Transmission and Distribution Demand Charge (in addition to Billing Demand and Energy Charge) $/kVA $3.12 $3.73 $3.73 * Subject to the provisions of Appendices A and B. MINIMUM CHARGE The minimum monthly charge shall be the Facilities Charge, Demand Charge, plus the Transmission and Distribution Demand Charge. In any month the maximum Transmission and Distribution demand shall not be less than 60 kVA. MEASUREMENT OF DEMAND AND ENERGY 1. Billing Demand shall be measured by suitable recording instruments provided by the Utility and in any month,the demand shall be the 60-minute integrated kW demand and occurring in 17 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20,2022 Phase 3 Effective: January 20, 2023 the same 60-minute interval and on the same day of each month as the 60-minute integrated that the Utility will use to determine the Utility's power supply billing demands. 2. If the Customer fails to maintain a ninety-six percent(96%)power factor during the 60-minute coincident demand period, the Billing Demand will be adjusted as follows: Billing Demand x 96% Actual Power Factor 3. Transmission and Distribution Demand shall be for any month the number of kVAs in the 30-minute interval during which the kVAs are greater than in any other 30-minute interval in such month. 4. Energy shall be measured by suitable integrating instruments. NOTIFICATION TO CUSTOMER The Utility will assist the Customer in reducing the billings under the Demand Charge provision of the Rate Schedule by making their best efforts to notify the Customer at least one-half hour prior to the anticipated hour of the Billing Demand for each month. Such notification may occur multiple times each month. Such notification will give the Customer the opportunity to reduce its demand during the hour of the Billing Demand.The Utility shall not be held responsible for failure to accurately predict the hour of such Billing Demand or for failure to notify the Customer one-half hour in advance of the hour of such Billing Demand or for the Customer's failure to reduce its demand when notified of an impending Billing Demand. 18 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20,2022 Phase 3 Effective: January 20, 2023 Richmond Power and Light Rate Schedule Industrial Service Secondary (ISS) AVAILABILITY Secondary service available through one meter to any Customer having a maximum load requirement of at least 1,000 kW. Applicant must be located adjacent to the Richmond Power& Light Company's (the Utility) distribution line that is adequate and suitable for supplying the service requested. CHARACTER OF SERVICE Alternating current having a frequency of 60 Hertz and furnished at a voltage, which is standard with the Utility in the area served. RATE* Industrial Service Secondary Units Phase 1 Phase 2 Phase 3 Facilities Charge $/Month $195.25 $195.25 $195.25 Energy Charge $/kWh $0.03622 $0.03440 $0.03440 Demand Charge $/kVA $22.50 $25.00 $25.00 * Subject to the provisions of Appendices A and B. MINIMUM CHARGE The minimum monthly charge shall be the Facilities Charge plus the Demand Charge. MEASUREMENT OF DEMAND AND ENERGY Peak demand shall be measured by suitable recording instruments provided by the Utility and shall be the average number of kVAs in the 30-minute period during which the kVA demand is greater than in any other 30-minute interval in such month. For billing purposes, the billing demand shall be the greater of the peak demand occurring during the month or 1,000 kVA. Energy shall be measured by suitable integrating instruments. TERMS AND CONDITIONS FOR RENDERING SERVICE 1. The Utility will supply and maintain at a single location, the complete substation equipment that is necessary in order to make one transformation to a standard voltage from the voltage of such available distribution line as the Utility deems adequate and suitable to serve the 19 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 requirements of the Customer. Not more than one such transformation will be installed at the Utility's expense for any one Customer. 2. When fire or other casualty shall render the physical plant or premises of the Customer unfit for the purposes of conducting the Customer's normal business operations, or makes the premises uninhabitable,the minimum charge of this rate schedule shall, commencing with the first billing period or portion thereof in which normal business operations cease, be waived until the beginning of the subsequent billing period or portion thereof in which the plant or premises shall have been reconstructed and reoccupied by the Customer. 3. When a strike or lockout of employees of the Customer causes the temporary suspension of the Customer's business,the minimum charge of this rate schedule shall,commencing with the first billing period or portion thereof in which normal business operations cease,be waived for each period or portion thereof during the continuance of the strike or lockout at the plant involved. In either event, the Customer shall be billed under this rate schedule for electric requirements used during each billing period. 20 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 Richmond Power and Light Rate Schedule Industrial Service Secondary Optional Coincident Peak Service (ISS-COIN) AVAILABILITY Service to any Customer whose electric service is provided under Rate Schedule ISS —Industrial Service Secondary,who agrees to participate in this Demand Side Management Program to reduce load during the Richmond Power & Light Company's (the Utility) net system peak hour each month, and who contracts for Optional Coincident Peak Service. Potential Customers must demonstrate to the Utility's satisfaction that the Customer has the ability to move kW demand from the on-peak period to the off-peak period. Customers taking service under Rate IS must move a minimum of five percent(5%) of kW demand from the on-peak period to the off-peak period as compared to its level of on-peak demand prior to taking service under this Rate. Customers will be evaluated during the first 12 months of taking service under this Rate to determine if the Customer is moving a minimum of five percent (5%) of kW demand from the on-peak period to the off-peak period. If, in the sole judgment of the Utility, a Customer is not consistently moving a significant amount of kW demand from the on-peak period to the off-peak period,the Customer must take service from another applicable rate. RATE • Industrial COIN Service Secondary Units Phase.1 Phase 2 Phase 3 Facilities Charge $/Month $195.25 $195.25 $195.25 Energy Charge $/kWh $0.03281 $0.02689 $0.02498 Billing Demand Charge $/kW $23.81 $25.37 $26.90 Transmission and Distribution Demand Charge (in addition to Billing Demand and Energy Charge) $/kVA $3.33 $4.47 $5.60 * Subject to the provisions of Appendices A and B. MINIMUM CHARGE The minimum monthly charge shall be the Facilities Charge, Demand Charge, plus the Transmission and Distribution Demand Charge. In any month, the maximum Transmission and Distribution demand shall not be less than 1,000 kVA. MEASUREMENT OF DEMAND AND ENERGY 21 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 1. Billing Demand shall be measured by suitable recording instruments provided by the Utility and in any month,the demand shall be the 60-minute integrated kW demand and occurring in the same 60-minute interval and on the same day of each month as the 60-minute integrated demand that the Utility will use to determine the Utility's power supply billing demands. 2. If the Customer fails to maintain a ninety-six percent(96%)power factor during the 60-minute coincident demand period, the Billing Demand will be adjusted as follows: Billing Demand x 96% Actual Power Factor 3. Transmission and Distribution Demand shall be for any month the number of kVAs in the 30-minute interval during which the kVAs are greater than in any other 30-minute interval in such month. 4. Energy shall be measured by suitable integrating instruments. NOTIFICATION TO CUSTOMER The Utility will assist the Customer in reducing the billings under the Demand Charge provision of the Rate Schedule by making their best efforts to notify the Customer at least one-half hour prior to the anticipated hour of the Billing Demand for each month. Such notification may occur multiple times each month. Such notification will give the Customer the opportunity to reduce its demand during the hour of the Billing Demand. The Utility shall not be held responsible for failure to accurately predict the hour of such Billing Demand or for failure to notify the Customer one-half hour in advance of the hour of such Billing Demand or for the Customer's failure to reduce its demand when notified of an impending Billing Demand. 22 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 Richmond Power and Light Rate Schedule Industrial Service Primary (ISP) AVAILABILITY Primary service available through one meter to any Customer having a maximum load requirement of at least 1,000 kW. Applicant must be located adjacent to the Richmond Power & Light Company's (the Utility) distribution line that is adequate and suitable for supplying the service requested. CHARACTER OF SERVICE Alternating current having a frequency of 60 Hertz and furnished at a voltage, which is standard with the Utility in the area served. RATE* Industrial Service Primary Units Phase 1 Phase 2 Phase 3 Facilities Charge $/Month $195.25 $195.25 $195.25 Energy Charge $/kWh $0.03550 $0.03371 $0.03371 Demand Charge $/kVA $22.60 $24.00 $24.00 * Subject to the provisions of Appendices A and B. MINIMUM CHARGE The minimum monthly charge shall be the Facilities Charge plus the Demand Charge. MEASUREMENT OF DEMAND AND ENERGY Peak demand shall be measured by suitable recording instruments provided by the Utility and shall be the average number of kVAs in the 30-minute period during which the kVA demand is greater than in any other 30-minute interval in such month. For billing purposes, the billing demand shall be the greater of the peak demand occurring during the month or 1,000 kVA. Energy shall be measured by suitable integrating instruments. 23 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 TERMS AND CONDITIONS FOR RENDERING SERVICE 1. This rate schedule is based upon the delivery and measurement of energy at the primary voltage of existing distribution lines operating at not more than 15,000 volts, or less than 2,400 volts, and the Customer furnishing and maintaining the complete substation and line equipment on the Customer's premises, including any and all transformers, switches, and other apparatus necessary for the Customer to take service at the voltage of the distribution line from which service is to be served. 2. When fire or other casualty shall render the physical plant or premises of the Customer unfit for the purposes of conducting the Customer's normal business operations, or makes the premises uninhabitable,the minimum charge of this rate schedule shall, commencing with the first billing period or portion thereof in which normal business operations cease, be waived until the beginning of the subsequent billing period or portion thereof in which the plant or premises shall have been reconstructed and reoccupied by the Customer. When a strike or lockout of employees of the Customer causes the temporary suspension of the Customer's business,the minimum charge of this rate schedule shall, commencing with the first billing period or portion thereof in which normal business operations cease,be waived for each period or portion thereof during the continuance of the strike or lockout at the plant involved. In either event, the Customer shall be billed under this rate schedule for electric requirements used during each billing period. 24 Phase 1 Effective: January 20,2021 Phase 2 Effective: January 20,2022 Phase 3 Effective: January 20,2023 Richmond Power and Light Rate Schedule Industrial Service Primary Optional Coincident Peak Service (ISP-COIN) AVAILABILITY Service to any Customer whose electric service is provided under Rate Schedule ISP —Industrial Service Primary, who agrees to participate in this Demand Side Management Program to reduce load during the Richmond Power & Light Company's (the Utility) net system peak hour each month, and who contracts for Optional Coincident Peak Service. Potential Customers must demonstrate to the Utility's satisfaction that the Customer has the ability to move kW demand from the on-peak period to the off-peak period. Customers taking service under Rate IS must move a minimum of five percent(5%) of kW demand from the on-peak period to the off-peak period as compared to its level of on-peak demand prior to taking service under this Rate. Customers will be evaluated during the first 12 months of taking service under this Rate to determine if the Customer is moving a minimum of five percent (5%) of kW demand from the on-peak period to the off-peak period. If, in the sole judgment of the Utility, a Customer is not consistently moving a significant amount of kW demand from the on-peak period to the off-peak period, the Customer must take service from another applicable rate. RATE Industrial COIN Service,Primary __ Units_ Phase 1 Phase 2 Phase 3 Facilities Charge $/Month $195.25 $195.25 $195.25 Energy Charge $/kWh $0.03215 $0.02635 $0.02448 Billing Demand Charge $/kW $24.13 $26.24 $26.34 Transmission and Distribution Demand Charge (in addition to Billing Demand and Energy Charge) $/kVA $2.51 $3.12 $3.73 * Subject to the provisions of Appendices A and B. MINIMUM CHARGE The minimum monthly charge shall be the Facilities Charge, Demand Charge, plus the Transmission and Distribution Demand Charge. In any month, the maximum Transmission and Distribution demand shall not be less than 1,000 kVA. MEASUREMENT OF DEMAND AND ENERGY 25 Phase 1 Effective: January 20,2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 1. Billing Demand shall be measured by suitable recording instruments provided by the Utility and in any month, the demand shall be the 60-minute integrated kW demand and occurring in the same 60-minute interval and on the same day of each month as the 60-minute integrated demand that the Utility will use to determine the Utility's power supply billing demands. 2. If the Customer fails to maintain a ninety-six percent(96%)power factor during the 60-minute coincident demand period, the Billing Demand will be adjusted as follows: Billing Demand x 96% Actual Power Factor 3. Transmission and Distribution Demand shall be for any month the number of kVAs in the 30-minute interval during which the kVAs are greater than in any other 30-minute interval in such month. 4. Energy shall be measured by suitable integrating instruments. NOTIFICATION TO CUSTOMER The Utility will assist the Customer in reducing the billings under the Demand Charge provision of the Rate Schedule by making their best efforts to notify the Customer at least one-half hour prior to the anticipated hour of the Billing Demand for each month. Such notification may occur multiple times each month. Such notification will give the Customer the opportunity to reduce its demand during the hour of the Billing Demand. The Utility shall not be held responsible for failure to accurately predict the hour of such Billing Demand or for failure to notify the Customer one-half hour in advance of the hour of such Billing Demand or for the Customer's failure to reduce its demand when notified of an impending Billing Demand. 26 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 • Richmond Power and Light Rate Schedule Transmission Service (TS) AVAILABILITY Transmission service available through one meter to any Customer having a maximum load requirement of 10,000 kW or more and taking service at 69 kV voltage or higher. Applicant must be located adjacent to the Richmond Power&Light Company's (the Utility)transmission line that is adequate and suitable for supplying the service requested. CHARACTER OF SERVICE Alternating current having a frequency of 60 Hertz and furnished at a voltage, which is standard with the Utility in the area served. RATE* Transmission Service Units Phase I Phase 2 Phase 3 Facilities Charge $/Month $195.25 $195.25 $195.25 Energy Charge $/kWh $0.02748 $0.02748 $0.02748 Demand Charge $/kVA $22.00 $22.00 $22.00 * Subject to the provisions of Appendices A and B. MINIMUM CHARGE The minimum monthly charge shall be the Facilities Charge plus the Demand Charge. MEASUREMENT OF DEMAND AND ENERGY Peak demand shall be measured by suitable recording instruments provided by the Utility and shall be the average number of kVAs in the 30-minute period during which the kVA demand is greater than in any other 30-minute interval in such month. For billing purposes,the billing demand shall be the greater of the peak demand occurring during the month or 10,000 kVA. Energy shall be measured by suitable integrating instruments. 27 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 TERMS AND CONDITIONS FOR RENDERING SERVICE 1. This rate schedule is based upon the delivery and measurement of energy at the primary voltage of existing overhead distribution lines operating at 69 kV voltage or higher, and the Customer furnishing and maintaining the complete substation and line equipment on the Customer's premises, including any and all transformers, switches, and other apparatus necessary for the Customer to take service at the voltage of the distribution line from which service is to be served. 2. When fire or other casualty shall render the physical plant or premises of the Customer unfit for the purposes of conducting the Customer's normal business operations, or makes the premises uninhabitable,the minimum charge of this rate schedule shall, commencing with the first billing period or portion thereof in which normal business operations cease, be waived until the beginning of the subsequent billing period or portion thereof in which the plant or premises shall have been reconstructed and reoccupied by the Customer. When a strike or lockout of employees of the Customer causes the temporary suspension of the Customer's business, the minimum charge of this rate schedule shall, commencing with the first billing period or portion thereof in which normal business operations cease,be waived for each period or portion thereof during the continuance of the strike or lockout at the plant involved. In either event, the Customer shall be billed under this rate schedule for electric requirements used during each billing period. 28 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20,2023 Richmond Power and Light Rate Schedule Transmission Service Optional Coincident Peak Service(TS-COIN) AVAILABILITY Service available to any Customer whose electric service is provided under Rate Schedule TS — Transmission Service, who agrees to participate in this Demand Side Management Program to reduce load during the Richmond Power & Light Company's (the Utility) net system peak hour each month, and who contracts for Optional Coincident Peak Service. Potential Customers must demonstrate to the Utility's satisfaction that the Customer has the ability to move kW demand from the on-peak period to the off-peak period. Customers taking service under Rate TS must move a minimum of five percent (5%) of kW demand from the on-peak period to the off-peak period as compared to its level of on-peak demand prior to taking service under this Rate. Customers will be evaluated during the first 12 months of taking service under this Rate to determine if the Customer is moving a significant amount of kW demand from the on-peak period to the off-peak period. If, in the sole judgment of the Utility, a Customer is not consistently moving a minimum of five percent(5%) of kW demand from the on-peak period to the off-peak period, the Customer must take service from another applicable Rate. RATE* Transmission Service COIN Units Phase 1 Phase 2 Phase 3 Facilities Charge $/Month $195.25 $195.25 $195.25 Energy Charge $/kWh $0.02748 $0.02748 $0.02748 Billing Demand Charge $/kW $25.55 $25.55 $25.55 Transmission and Distribution Demand Charge (in addition to Billing Demand and Energy Charge) $/kVA $2.02 $2.02 $2.02 * Subject to the provisions of Appendices A and B. MINIMUM CHARGE The minimum monthly charge shall be the Facilities Charge, Demand Charge, plus the Transmission and Distribution Demand Charge. In any month, the maximum Transmission and Distribution demand shall not be less than 10,000 kVA. MEASUREMENT OF DEMAND AND ENERGY 1. Billing Demand shall be measured by suitable recording instruments provided by the Utility and in any month,the demand shall be the 60-minute integrated kW demand and occurring in 29 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 the same 60-minute interval and on the same day of each month as the 60-minute integrated demand that the Utility will use to determine the Utility's power supply billing demands. 2. If the Customer fails to maintain a ninety-six percent(96%)power factor during the 60-minute coincident demand period, the Billing Demand will be adjusted as follows: Billing Demand x 96% Actual Power Factor 3. Transmission and Distribution Demand shall be for any month the number of kVAs in the 30-minute interval during which the kVAs are greater than in any other 30-minute interval in such month. 4. Energy shall be measured by suitable integrating instruments. NOTIFICATION TO CUSTOMER The Utility will assist the Customer in reducing the billings under the Demand Charge provision of the Rate Schedule by making their best efforts to notify the Customer at least one-half hour prior to the anticipated hour of the Billing Demand for each month. Such notification may occur multiple times each month. Such notification will give the Customer the opportunity to reduce its demand during the hour of the Billing Demand. Utility shall not be held responsible for failure to accurately predict the hour of such Billing Demand or for failure to notify the Customer one-half hour in advance of the hour of such Billing Demand or for the Customer's failure to reduce its demand when notified of an impending Billing Demand. 30 Phase 1 Effective: January 20,2021 Phase 2 Effective: January 20,2022 Phase 3 Effective: January 20, 2023 Richmond Power and Light Rate Schedule Lighting Service (LS) AVAILABILITY Outdoor Lighting is available only for continuous year-round service to individual Customers on private property. Street Lighting and Area Lighting are available for the lighting of any City of Richmond (City) street, alley, or park, within the corporate limits. This rate schedule is applicable for service when it is supplied through existing,new, or rebuilt street lighting systems,including extensions of such street lighting system to additional locations where service is requested by the City,provided that the equipment to be installed at such new location is comparable to the equipment utilized on the existing system. The Mercury Vapor (MV) lights are in process of elimination and are withdrawn except for Customers that contracted for service prior to December 31, 1999 and will not be applicable to any future Customers. If service hereunder is at any time discontinued at the Customer's option, MV lights shall not be available again. Richmond Power & Light Company (the Utility) will support existing high intensity discharge (HID) lighting offerings for as long as the technology is available. The National Energy Policy Act of 2005 requires that MV lamp ballasts shall not be manufactured or imported after January 1, 2008. To the extent that the Utility has the necessary materials, the Utility will continue to maintain existing MV lamp installations in accordance with this tariff. The Energy Independence and Security Act of 2007 mandated pulse start ballasts; therefore, standard ballast Metal Halide (MH) lamps are no longer offered for new construction. To the extent that the Utility has the necessary materials, the Utility will continue to maintain existing MH lamp installations in accordance with this tariff CHARACTER OF SERVICE For each lamp with luminaire and an upsweep arm not over 6 feet in length, controlled by a photo-electric relay, when mounted on a utility pole and service supplied from existing secondary facilities. RATE* For Outdoor Lighting service, rates are differentiated by bulb wattage and type between Sodium Vapor (SV), Mercury Vapor(MV), and Light Emitting Diode (LED) as follows: Outdoor Lighting _ a Plug' 100 W Sodium Vapor OL $5.63 $5.88 $6.14 150 W Sodium Vapor OL $6.19 $6.46 $6.74 31 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 Outdoor Lighting H. 1,44s `4 . a ' ,,,. :. , . tliate> 175 W Mercury Vapor OL $8.16 $8.52 $8.89 250 W Metal Halide Flood OL $8.93 $9.33 $9.74 250 W Mercury Vapor OL $10.18 $10.62 $11.09 250 W Sodium Vapor Flood OL $8.74 $9.12 $9.52 250 W Sodium Vapor OL $11.58 $12.09 $12.62 400 W Metal Halide Flood OL $10.47 $10.93 $11.41 400 W Mercury Vapor OL $12.23 $12.77 $13.33 400 W Sodium Vapor Flood OL $10.37 $10.83 $11.30 50 W LED (100W HPS Equiv) $8.23 $8.23 $8.23 111 W LED (250W HPS Equiv) $11.26 $11.26 $11.26 243 W LED (400W HPS Equiv) $15.51 $15.51 $15.51 For Street Lighting and Area Lighting service for lighting of a City street, alley, or park, within the corporate limits, rates are differentiated by pole type, overhead (OH) or underground (UG) service, bulb wattage, and bulb type as follows: Street Lighting and Area Lighting Rate($/Lamp/Month) r , J €g x � .,.� z it G!, , `^E 9 '�- v n _.�e 1�f. 't . >' .P 6.. , hase12, *liils.. n 100 W Sodium Vapor-UG-Fiber $7.68 $7.94 $7.94 100 W Sodium Vapor-UG-Metal $7.68 $7.94 $7.94 150 W Sodium Vapor-OH-Metal $12.39 $12.80 $12.80 150 W Sodium Vapor-OH-Metal-T $16.49 $17.05 $17.05 150 W Sodium Vapor-OH-Wood $8.07 $8.35 $8.35 150 W Sodium Vapor-UG-Metal $16.52 $17.07 $17.07 150 W Sodium Vapor-UG-Metal-T $20.73 $21.42 $21.42 175 W Metal Hal-UG-Metal-C-S $8.89 $9.19 $9.19 175 W Metal Hal-UG-Metal-C-T $12.21 $12.63 $12.63 175 W Metal Halide-UG-Metal $16.46 $17.01 $17.01 175 W Mercury Vapor UG-Metal $17.95 $18.56 $18.56 175 W Mercury Vapor-UG-Metal-S $8.68 $8.98 $8.98 175 W Mercury Vapor-UG-Wood $12.90 $13.34 $13.34 32 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 Street Lighting and Area Lighting_ `_,_ Rate $LLamp/Month „ 7 ` 250 W Mercury Vapor-OH-Metal $13.31 $13.76 $13.76 250 W Sodium Vapor-OH-Metal $13.35 $13.80 $13.80 250 W Mercury Vapor-OH-Wood $9.27 $9.58 $9.58 250 W Sodium Vapor-OH-Wood $9.27 $9.58 $9.58 250 W Sodium Vapor-OH-Metal-T $17.47 $18.06 $18.06 250 W Mercury Vapor-UG-Metal-S $18.54 $19.17 $19.17 250 W Sodium Vapor-UG-Metal $18.54 $19.17 $19.17 250 W Sodium Vapor-UG-Metal-T $22.01 $22.76 $22.76 400 W Sodium Vapor-OH-Wood $30.46 $31.48 $31.48 400 W Metal Hal-UG-Metal-C-S $10.48 $10.83 $10.83 400 W Sodium Vapor-UG-Metal $32.28 $33.37 $33.37 1000 W Metal Halide-UG-Metal-T $35.48 $36.69 $36.69 150 Sodium Vapor-UG-Metal $24.59 $25.42 $25.42 2-400 W Sodium Vapor-UG-Met-N $42.03 $43.44 $43.44 4-400 W Mercury Vapor-UG-Met-N $45.88 $47.43 $47.43 400 W Sodium Vapor-UG-Metal-N $30.52 $31.55 $31.55 70 W Sodium Vapor-UG-Metal $21.45 $22.17 $22.17 70 W-Sodium Vapor-UG-Metal-T $30.52 $31.55 $31.55 SL<400W-OH-Wood $11.58 $11.97 $11.97 72 W LED (100 W HPS Equiv.)-UG-Metal Post $19.81 $19.81 $19.81 72 W LED (100 W HPS Equiv.)-UG-Decorative Post $24.38 $24.38 $24.38 71 W LED (150 W HPS Equiv.)-OH-Wood Single Pendant $17.39 $17.39 $17.39 111 W LED (250 W HPS Equiv.)-OH-Wood Single Pendant $19.19 $19.19 $19.19 278 W LED (400 W HPS Equiv.)-OH-Wood Single Pendant $23.44 $23.44 $23.44 71 W LED (150 W HPS Equiv.)-OH-Metal Single Pendant $21.41 $21.41 $21.41 111 W LED (250 W HPS Equiv.)-OH-Metal Single Pendant $23.21 $23.21 $23.21 278 W LED (400 W HPS Equiv.)-OH-Metal Single Pendant $27.47 $27.47 $27.47 71 W LED (150 W HPS Equiv.)-UG-Metal Single Pendant $22.81 $22.81 $22.81 111 W LED (250 W HPS Equiv.)-UG-Metal Single Pendant $24.61 $24.61 $24.61 33 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 Street__Lighting and Area Lighting Rate ($/Lamp/Month) _ -, a _ s ' mod _, ' .r :a. .# 7...$w, _3 °]iase Pbas Pas 41, 278 W LED (400 W HPS Equiv.)-UG-Metal.Single Pendant $28.86 $28.86 $28.86 71 W LED (150 W HPS Equiv.)-OH-Metal Twin Pendant $24.27 $24.27 $24.27 111 W LED (250 W HPS Equiv.)-OH-Metal Twin Pendant $26.97 $26.97 $26.97 278 W LED (400 W HPS Equiv.)-OH-Metal Twin Pendant $31.70 $31.70 $31.70 71 W LED (150 W HPS Equiv.)-UG-Metal Twin Pendant $25.66 $25.66 $25.66 111 W LED (250 W HPS Equiv.)-UG-Metal Twin Pendant $28.36 $28.36 $28.36 278 W LED (400 W HPS Equiv.)-UG-Metal Twin Pendant $33.09 $33.09 $33.09 111 W LED (250 W HPS Equiv.)-UG-Metal Decorative $46.18 $46.18 $46.18 242 W LED (400 W HPS Equiv.)-UG-Metal Decorative $50.35 $50.35 $50.35 * Subject to the provisions of Appendices A and B. STREET LIGHTING FACILITIES All facilities necessary for service hereunder, including all poles, fixtures, street lighting circuits, transformers, lamps,and other necessary facilities will be furnished and maintained by the Utility. ADDITIONAL FACILITIES When other new facilities are to be installed by the Utility to furnish the lighting service, the Customer will, in addition to the above monthly rate, pay in advance the installation cost of such new overhead facilities, extending from the nearest, or the most suitable pole of the Utility,to the point designated by the Customer for the installation of the lamp. CONTRACTS Contracts under this rate schedule will be for not less than one (1) year for Residential or Farm Customers and not less than three (3) years for Commercial or Industrial Customers. The Utility reserves the right to include in the contract such provisions as it may deem necessary to ensure payment of bills throughout the term of the contract OWNERSHIP OF FACILITIES All facilities necessary for service, including, fixtures, controls, poles, transformers, secondaries, lamps, and other appurtenances, shall be owned and maintained by the Utility. All service and necessary maintenance will be performed only during the regular scheduled working hours of the Utility.Burned out lamps will normally be replaced within 48 hours after notification by Customer. HOURS OF LIGHTING 34 Phase 1 Effective: January 20,2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 All lamps shall burn from approximately one-half hour after sunset until approximately one-half hour before sunrise each day in the year, approximately 4,000 hours per annum. 35 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 Richmond Power and Light Rate Schedule Electric Heating Schools (EHS) AVAILABILITY This rate schedule is closed to new Customers after October 31, 1980. If service hereunder is at any time discontinued at the Customer's option,this schedule shall not again be available. RATE* Electric Heating Schools Units Phase 1< Phase 2 Phase 3 Facilities Charge $/Month $24.30 $48.65 $73.00 Energy Charge $/kWh $0.09457 $0.09759 $0.10079 * Subject to the provisions of Appendices A and B. MINIMUM CHARGE The minimum monthly charge shall be the Facilities Charge. SPECIAL TERMS AND CONDITIONS 1. The Customer may elect to receive service for any individual building at a school complex under the terms of this rate schedule. 2. The entire requirements for electrical service for the building, or additions,will be supplied at one voltage through one point of delivery, and all energy will be measured by one meter. 3. Nothing in this rate schedule shall be construed to prohibit the use of a form of energy other than electric energy for instruction and/or training and/or demonstration purposes. 36 Phase 1 Effective: January 20,2021 Phase 2 Effective: January 20,2022 Phase 3 Effective: January 20, 2023 Richmond Power and Light Rate Schedule General Electric Heating(GEH) AVAILABILITY This rate schedule is closed to new Customers after October 31, 1980. If service hereunder is at any time discontinued at the Customer's option, this schedule shall not again be available. RATE* General Electric Heating _ Units Phase'1. Phase 2 Phase 3 Facilities Charge $/Month $25.75 $51.50 $51.50 Energy Charge: Tier 1 for the first 170 kWh or less used per month $/kWh $0.13008 $0.09993 $0.09993 Tier 2 for the next 30 kWh used per month $/kWh $0.13008 $0.09993 $0.09993 Tier 3 for the next 6,800 kWh used per month $/kWh $0.10008 $0.07993 $0.07993 Tier 4 for all over 7,000 kWh used per month $/kWh $0.09008 $0.07993 $0.07993 Demand Charge: Tier 1 for up to 30 kW $/kW $1.40 $6.50 $6.50 Tier 2 for all over 30 kW used per month $/kW $2.80 $6.50 $6.50 * Subject to the provisions of Appendices A and B. MINIMUM CHARGE The minimum monthly charge shall be the Facilities Charge plus the Demand Charge. MEASUREMENT OF DEMAND All demand shall be measured by suitable instruments and, in any month the demand shall be the average number of kWs in the 30-minute interval during which the energy metered is greater than in any other 30-minute interval in such month. MEASUREMENT OF ENERGY Energy supplied hereunder will be delivered through not more than one single phase and/or one polyphase meter. Customer's demand will be determined monthly to be the highest registration of 37 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 a suitable indicating or recording type meter. Where energy is delivered through more than one meter the monthly billing demand will be taken as the sum of the demands separately determined. SPECIAL TERMS AND CONDITIONS This rate schedule is available to Customers operating permanently installed electric space heating, whether resistance type, radiant, or heat pump of 3 kW, of more, total rated capacity, which conforms to the specifications of the Richmond Power&Light Company(the Utility), and is used as the principal source of space heating.At least fifty percent(50%)of the Customer's electric load must be permanently located inside the buildings which are electrically heated. 38 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 Richmond Power and Light Rate Schedule Electric Vehicle Charging Program—Public Location (EV-PP) AVAILABILITY • Service to a separately metered electric vehicle(EV) charging station operating in a public location to be made available to the general public, whose peak load does not exceed 60 kW in Richmond Power&Light Company's (the Utility) service territory. EQUIPMENT The EV charging equipment to which electric service is provided under this rate may be owned, operated, and maintained by either the Utility or a third-party, at the Utility's discretion. CHARACTER OF SERVICE Alternating current having a frequency of 60 Hertz and furnished at a voltage, which is standard with the Utility in the area served. RATE* • General Power Units Phase 1 Phase 2 Phase 3 Energy Charge: $lkWh $0.14834 $0.18284 $0.21736 * Subject to the provisions of Appendices A and B. METERING AND BILLING EV charging service will be paid for by the end user at the point of service prior to charging by means of credit, debit, or pre-paid cards, as determined by the company owning the facilities, and rates specified in this rate schedule. The charging service will be metered separately, and if owned by a third party, will be billed at this rate using the Utility's standard terms and practices. TERMS AND CONDITIONS FOR RENDERING SERVICE 1. The Company will supply and maintain at a single location,the complete substation equipment that is necessary in order to make one transfoilnation to a standard voltage from the voltage of such available distribution line as the Utility deems adequate and suitable to serve the requirements of the Customer. Not more than one such transformation will be installed at Utility's expense for any one Customer. 39 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 Where service is metered at a primary voltage and the Customer desires and requests transformation to more than one standard voltage, or service of a standard voltage at more than one location within its premises,Utility will, at its option,furnish and maintain such additional transformation equipment and such interconnecting lines as may be necessary, provided, however,that the Customer shall reimburse the Utility for the amount of the cost of furnishing the entire facilities which is in excess of the cost of furnishing transformation in accordance with the next paragraph. The right and title to all equipment so furnished by the Utility shall be and remain in the Utility. Should the Customer require a non-standard voltage, the Customer shall, at its own expense, furnish and maintain all transformers and protective equipment therefore necessary in order to obtain such non-standard voltage. 2. All service hereunder shall be furnished through one meter. 3. All wiring, pole lines,wires, and other electrical equipment and apparatus located beyond the point of connection of the Customer's service lines with the lines of the Utility are considered the distribution system of the Customer and shall be furnished, owned, and maintained by the Customer, except in the case of metering equipment and other equipment incidental to the rendering of service,if any,that is furnished,owned and maintained by the Utility and installed beyond the point of connection. 4. Charging stations will be installed at the charging level and/or service voltage selected in the Company's sole discretion and may be modified by the Company at any time in any manner. Modifications to charging level and/or service voltage requested by a customer that can be reasonably accommodated by the distribution system may be approved in the Company's sole discretion. The Company reserves the right to require a customer requesting a change to charging level and/or service voltage to pay for any required system upgrades or investment in distribution system infrastructure. 40 Phase 1 Effective: January 20, 2021 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20, 2023 Richmond Power and Light Rate Schedule Rider NM—Net Metering AVAILABILITY Net Metering is provided upon request and on a first-come, first-served basis. Net Metering is available to Residential, Commercial, and Industrial Customers in good standing that own and operate an eligible solar, wind, biomass, geothermal,hydroelectric, or other renewable generation source. The nameplate rating of Customer's generator may not exceed 10 kW. Customers served under this tariff must also take service from the Richmond Power &Light Company (the Utility) under the otherwise applicable standard service tariff. Total Net Metering participation under this tariff is limited to a total nameplate rating of all of the Customers' generators of one-tenth of one percent(0.1%) of the Utility's most recent summer peak load. DEFINITIONS "Net Metering"means measuring the difference in an applicable billing period between the amount of electricity supplied by the Utility to the Customer who generates electricity using an eligible solar, wind, biomass, geothermal, hydroelectric, or other renewable generation source and the amount of electricity generated by such respective Customer that is delivered to the Utility. BILLING Monthly charges for energy and demand, where applicable, to serve the Customer's net or total load shall be determined according to the Utility's standard service tariff under which the Customer otherwise would be served,absent the Customer's eligible Net Metering facility. The measurement of net energy supplied by the Utility and delivered to the Utility shall be calculated in the following manner. The Utility shall measure the difference between the amount of electricity delivered by the Utility to the Customer and the amount of electricity generated by the Customer and delivered to the Utility during the billing period, in accordance with noinial metering practices. If the kWh delivered by the Utility to the Customer exceeds the kWh delivered by the Customer to the Utility during the billing period,the Customer shall be billed for the kWh difference.If the kWh generated by the Customer and delivered to the Utility exceeds the kWh supplied by the Utility to the Customer during the billing period,the Customer shall be credited in the next billing cycle for the kWh difference. When the Customer elects to discontinue Net Metering service, any unused credit will be granted to the Utility. The Utility shall not purchase, or wheel power produced by Net Metering facilities.Bill charges and credits will be in accordance with the standard tariff that would apply if the Customer did not participate in Net Metering under this tariff. METERING The Customer's standard meter, if capable of measuring electricity in both directions,will be used. If the Utility determines new metering is necessary,the Utility will install metering capable of Net 41 Effective: January 20, 2021 Metering at the Customer's expense.Additionally,the Utility reserves the right to install, at its own expense, a meter to measure the output of the solar, wind, biomass, geothermal, hydroelectric, or other renewable generation system. TERMS AND CONDITIONS In order to be eligible for Net Metering, the Customer's generator must meet the following requirements: 1. All kWh must be generated from the output of solar, wind, biomass, geothermal, hydroelectric, or other renewable generation sources; 2. The generation equipment must be operated by the Customer and located on the Customer's premises; 3. The generator must operate in parallel with the Utility's transmission and distribution facilities without adversely affecting the Utility's system and equipment and without presenting safety hazards or threats to the reliability of service to the Utility, its personnel, and other Customers; 4. The Customer's generation must be intended primarily to offset all or part of the Customer's requirements for electricity; 5. The name plate rating of Customer's generator must not exceed 10 kW and the Customer's generation must satisfy the Interconnection requirements specified below. The Customer shall make an application for Interconnection Service and execute an Interconnection Agreement acceptable to the Utility. The Customer shall maintain homeowners, commercial, or other insurance providing coverage in the amount of at least one hundred thousand dollars ($100,000) for the liability of the insured against loss arising out of the use of generation equipment associated with Net Metering under this tariff. The supplying of, and billing for, service and all conditions applying thereto, are subject to the Utility's General Terms and Conditions. INTERCONNECTION For generator systems 10 kW or smaller eligible for this tariff,the Utility's technical requirements consist of: 1. IEEE 1547-2003, "IEEE Standard for Interconnecting Distributed Resources with Electric Power Systems" (IEEE 1547). 2. Current version of ANSI/NFPA 70, "National Electrical Code" (NEC). 42 Effective: January 20, 2021 3. Any other applicable local building codes. Inverter based systems listed by Underwriters Laboratories (UL) to UL Standard 1741, published May 7, 1999, as revised January 17, 2001 (UL 1741), are accepted by the Utility as meeting the technical requirements of IEEE 1547 tested by UL 1741. Conformance with these requirements does not convey any liability to the Utility for damages or injuries arising from the installation or operation of the generator system. The Utility may, at its own discretion, isolate any Net Metering facility if the Utility has reason to believe that continued interconnection with the Net Metering facility creates or contributes to a system emergency. The Utility may perform reasonable on-site inspections to verify the proper installation and continuing safe operation of the Net Metering facility and the interconnection facilities, at reasonable times and upon reasonable advance notice to the Net Metering Customer. The Customer shall operate the Net Metering facility in such a manner as not to cause undue fluctuations in voltage, intermittent load characteristics, or otherwise interfere with the operation of Utility's electric system. Customers shall agree that the interconnection and operation of the facility is secondary to, and shall not interfere with, the Utility's ability to meet its primary responsibility of furnishing reasonably adequate service to its Customers. Customer's control equipment for the Net Metering facility shall immediately, completely, and automatically disconnect and isolate the facility from the Utility's electric system in the event of a fault on the Utility's electric system, a fault on the Customer's electric system, or loss of a source or sources on the Utility's electric system. Customer shall install, operate, and maintain, at the Customer's sole cost and expense, the Net Metering facility in accordance with the manufacturer's suggested practices for safe, efficient, and reliable operation of the facility in parallel with the Utility's electric system. The Customer shall bear full responsibility for the installation, maintenance and safe operation of the Net Metering facility.The Customer shall be responsible for protecting, at the Customer's sole cost and expense, the Net Metering facility from any condition or disturbance on the Utility's electric system, including, but not limited to, voltage sags or swells, system faults, outages, loss of a single phase of supply, equipment failures, and lightning or switching surges. Upon reasonable advance notice to the Customer,the Utility shall have access at reasonable times to the Net Metering facility whether before, during or after the time facility first produces energy, to perform reasonable on-site inspections to verify that the installation and operation of the facility comply with the requirements of this tariff and to verify the proper installation and continuing safe operation of the facilities. The Utility shall also have, at all times, immediate access to breakers or any other equipment that will isolate the Net Metering facility from the Utility's electric system. In non-emergency situations, the Utility shall give the Customer reasonable notice prior to isolating the Net Metering facility. The Customer shall agree that, without the prior written permission from the Utility, no changes shall be made to the configuration of the Net Metering facility, as that configuration is described in the Interconnection Agreement, and no relay or other control or protection settings specified in 43 Effective: January 20, 2021 the Interconnection Agreement shall be set, reset, adjusted or tampered with, except to the extent necessary to verify that the facility complies with the Utility approved settings. 44 Effective: January 20, 2021 Richmond Power and Light Rate Schedule Rider ED—Economic Development AVAILABILITY This Rider is available to a Qualifying Customer (as defined herein) to encourage large power users to expand or create new operations within the Richmond Power & Light Company's (the Utility) service territory. QUALIFICATIONS A "Qualifying Customer" is a new or existing non-residential Customer in the Utility's service territory that is establishing new operations or expanding existing operations such that the new or expanded operations will result in new or additional demand of at least one (1) MW (1000 kW)at one delivery point (the Qualifying Demand) and the new or expanded operations has involved a capital investment of at least one million dollars ($1,000,000)within the Utility's service territory. For a Qualifying Customer that is expanding operations, Qualifying Demand is measured from the average monthly peak demand for the 12 months immediately preceding the effective date of the Service Application. For a Qualifying Customer that is establishing new operations, Qualifying Demand is measured from zero. A Qualifying Customer is not a Customer: (1) with "new" demand that results from a change in ownership of an existing establishment without qualifying new load; (2) renewing service following interruptions such as equipment failure, temporary plant shutdown, strike, economic conditions, or natural disaster; or (3) that has shifted its load from one operation or Customer to another within the Utility's service territory. The Utility may determine exclusively, without recourse by the Customer, whether an event has occurred that would prevent a Customer from being a Qualifying Customer. RATE INCENTIVE Beginning with the effective date indicated in the Service Application submitted by the Qualifying Customer, the Utility will receive a credit on its wholesale bill for the qualifying new load. The incentive amount received by the Utility from the Indiana Municipal Power Agency (IMPA) for such load will be passed in full to Qualifying Customers. For reference purposes, the discount to the Qualifying Customer's wholesale cost for qualifying new load will be calculated according to the following schedule: Months 1-12 20% Months 13-24 15% Months 25-36 10% Months 37-48 10% Months 49-60 5% 45 Effective: January 20, 2021 The Qualifying Customer must meet the minimum Qualifying Demand during each month of the incentive period (i.e., months 1 through 60, as designated above). Failure to meet the minimum Qualifying Demand in a particular month will result in zero percent(0%)reduction for that month. TERMS AND CONDITIONS The Qualifying Customer must submit a Service Application to the Utility specifying: (1) a description of the amount and nature of the new load; (2) the basis on which the Qualifying Customer meets the requirements of this Rider; (3) the Qualifying Customer's desired effective date. This Rider will terminate on the same date that IMPA's economic development rider terminates, except that any Qualifying Customer receiving the rate incentive at the time of the Rider's termination may continue receiving the incentive for the remainder of the applicable incentive period (as long it continues to meet the Rider's requirements) APPLICABLE RATE SCHEDULES This Rider is applicable to the following rate schedules: Large Power Service Secondary (LPSS) Large Power Service Secondary—Optional Coincident Peak(LPSS- COIN) Large Power Service Primary (LPSP) Large Power Service Primary—Optional Coincident Peak (LPSP- COIN) Industrial Service Secondary (ISS) Industrial Service Secondary—Optional Coincident Peak(IS S- COIN) Industrial Service Primary (ISP) Industrial Service Primary—Optional Coincident Peak (ISP- COIN) Transmission Service(TS) Transmission Service—Optional Coincident Peak(TS- COIN) 46 Effective: January 20, 2021 Richmond Power and Light Rate Schedule Rider OF—Qualifying Facilities AVAILABILITY On June 28, 2017 in Cause No. 44898, the Indiana Utility Regulatory Commission (IURC or Commission) approved the assumption by the Indiana Municipal Power Agency (IMPA) of all obligations of its Commission-regulated municipal members,including Richmond Power&Light, to purchase energy and capacity offered by a Qualifying Facility of less than twenty megawatts (20 MW)under 170 IAC 4-4.1 (for Cogeneration and Alternate Energy Production facilities),thus any Qualifying Facilities in the Richmond Power&Light Company's(the Utility)service territory shall be served by IMPA or the Utility pursuant to that Order. The provisions of this tariff, along with any interconnection agreement and the provisions of any agreement entered into between the Customer/Qualifying Facility and RP&L and/or IMPA shall govern such service, as applicable. RATES Pursuant to the Order in Cause No. 44898, the Utility maintains its retail sales obligation. Any backup or supplemental power needed by a Customer with a Qualifying Facility will be sold pursuant to the Utility's applicable tariff provisions. INTERCONNECTION A Customer desiring to interconnect a Qualifying Facility(also referred to herein as a "renewable generation facility") with the Utility's grid shall complete an interconnection application and submit the application to the Utility for review. After receipt of the application, the Utility shall conduct such further inspection of the renewable generation facilities as the Utility deems necessary and approve or deny the application. If the application is denied,the Utility shall provide a written response to the Customer explaining why the application was denied. The Utility is hereby authorized to charge a reasonable application fee to offset costs involved with reviewing the application, inspecting the renewable generation facilities, and otherwise ensuring compliance with these rules. If the interconnection application is approved, then the Customer agrees that no changes shall be made to the configuration of the renewable generation facilities, as that configuration is described in the application, and no relay or other control or protection settings specified in the application shall be set, reset, adjusted or tampered with, except to the extent necessary to verify that the renewable generation facilities comply with the Utility's approved settings. In addition to such other requirements as the Utility deems necessary, any renewable generation facility allowed to interconnect to the Utility's grid must comply with: (a) the National Electrical Code and the National Electrical Safety Code, as each may be revised from time to time; (b) the Utility's rules and regulations and the Utility's General Terms and Conditions for Electric Service, each as contained in the Utility's Electric Tariff and each as may be revised from time to time; and (c) all other applicable local, state, and federal codes and laws, as the same may be in effect from 47 Effective: January 20, 2021 time to time. For any approved renewable generation facilities interconnected to the Utility's grid,the Customer shall install, operate, and maintain, at the Customer's sole cost and expense, the renewable generation facilities in accordance with the Institute of Electrical and Electronics Engineers' applicable Standard for Interconnecting Distributed Resources with Electric Power Systems, as it may be amended from time to time. The Customer shall be responsible for protecting, at the Customer's sole cost and expense, the renewable generation facilities from any condition or disturbance on the Utility's electric system, including, but not limited to, voltage sags or swells, system faults, outages, loss of a single phase of supply, equipment failures, and lightning or switching surges. The Customer shall operate any interconnected renewable generation facilities in such a manner as not to cause undue fluctuations in voltage,intermittent load characteristics or otherwise interfere with the operation of the Utility's electric system. At all times when the renewable generation facilities are being operated in parallel with the Utility's electric system,the Customer shall operate the renewable generation facilities in a manner that no disturbance will be produced to the service rendered by the Utility to any of its other Customers or to any electric system interconnected with the Utility's electric system. The Customer's control equipment for the renewable generation facilities shall immediately, completely, and automatically disconnect and isolate the renewable generation facilities from the Utility's electric system in the event of a fault on the Utility's electric system, a fault on the Customer's renewable generation facilities, or loss of a source or sources on the Utility's electric system. The automatic disconnecting device included in such control equipment shall not be capable of reclosing until after service is restored on the Utility's electric system. Additionally, if the fault is with the Customer's renewable generation facilities, such automatic disconnecting device shall not be reclosed until after the fault is isolated from the Customer's renewable generation facilities. Upon reasonable advance notice to the Customer, the Utility shall have access to any interconnected renewable generation facilities to perform on-site inspections to verify that the installation and operation of the renewable generation facilities comply with the requirements of this tariff and to verify the proper installation and continuing safe operation of the renewable generation facilities. The Utility shall also have at all times immediate access to breakers or any other equipment that will isolate the renewable generation facilities from the Utility's electric system. The Utility shall not be responsible for any costs the Customer may incur as a result of such inspection(s).The Utility shall have the right and authority to isolate approved interconnected renewable generation facilities at the Utility's sole discretion if the Utility believes that: (a) continued interconnection and parallel operation of the renewable generation facilities with the Utility's electric system creates or contributes (or will create or contribute) to a system emergency on either the Utility's or the Customer's electric facilities; (b) the renewable generation facilities are not in compliance with the requirements of this tariff; or(c)the renewable generation facilities interfere with the operation of the Utility's electric system. In non-emergency situations,the Utility shall give the Customer reasonable notice prior to isolating the renewable generation facilities. Customer shall procure and keep in force during all periods of parallel operation of the renewable generation facilities with the Utility's electric system,homeowners,commercial,or other insurance 48 Effective: January 20, 2021 to protect the interests of the Utility, with an insurance carrier acceptable to the Utility, and in amounts not less than those reasonably determined by the Utility to be necessary taking into consideration the nameplate capacity,configuration and type of the renewable generation facilities. The Customer shall indemnify and hold harmless the Utility,the City of Richmond,its employees, representatives, agents and subcontractors from and against all claims, liability, damages and expenses, including attorney's fees, based on any injury to any person, including the loss of life, or damage to any property, including the loss of use thereof, arising out of, resulting from, or connected with, or that may be alleged to have arisen out of, resulted from, or connected with, an act or omission by the Customer, its employees, agents, representatives, successors or assigns in the construction, ownership, operation or maintenance of the Customer's renewable generation facilities. If the Utility is required to bring an action to enforce its rights under this Agreement, either as a separate action or in connection with another action, and said rights are upheld, the Customer shall reimburse the Utility for all expenses, including attorney's fees, incurred in connection with such action. • 49 Effective: January 20, 2021 INTERCONNECTION AGREEMENT FOR QUALIFIED FACILITIES RICHMOND POWER& LIGHT COMPANY THIS INTERCONNECTION AGREEMENT("Agreement") is made and entered into this day of, 20 , by and between Richmond Power & Light Company ("Utility"), and ("Customer"). Utility and.Customer are hereinafter sometimes referred to individually as "Party" or collectively as "Parties". WITNESSETH: WHEREAS, Customer is installing, or has installed, solar, wind, biomass, geothermal, hydroelectric, or other renewable generation equipment, controls, and protective relays and equipment ("Generation Facilities" or "Qualified Facilities") used to interconnect and operate in parallel with Utility's electric system, which Generation Facilities are more fully described in Exhibit A, attached hereto and incorporated herein by this Agreement, and as follows: Location: Generator Size and Type; and WHEREAS, the name plate rating of the Generation Facilities does not exceed 20 megawatts ("MW"); and WHEREAS,Customer desires to receive service under Utility's Qualified Facilities("QF") tariff. NOW, THEREFORE, in consideration thereof, Customer and Utility agree as follows: 1. Application. It is understood and agreed that this Agreement applies only to the operation of the Generation Facilities described above and on Exhibit A. 2. Interconnection. Utility agrees to allow Customer to interconnect and operate the Generation Facilities in parallel with Utility's electric system in accordance with any operating procedures or other conditions specified in Exhibit A. By this Agreement, or by inspection, if any, or by non-rejection,or by approval,or in any other way,Utility does not give any warranty,express or implied, as to the adequacy, safety, compliance with applicable codes or requirements, or as to any other characteristics of the Generation Facilities. The Generation Facilities installed and operated by or for Customer shall comply with, and Customer represents and warrants their compliance with: (a)the National Electrical Code and the National Electrical Safety Code, as each may be revised from time to time; (b) Utility's rules and regulations applicable to Qualified Facilities, and Utility's General Terms and Conditions for Electric Service, each as contained in Utility's Electric Tariff and as each as may be revised from time to time; (c) all other applicable local, state, and federal codes and laws, as the same may be in effect from time to time; and any other requirements as the Utility deems necessary. Customer shall install, operate, and maintain, at Customer's sole cost and expense, the Generation Facilities in accordance with the Institute of Electric and Electronics Engineers'applicable Standard for Interconnecting Distributed Resources 50 Effective: January 20, 2021 with Electric Power Systems, as it may be amended from time to time. Customer shall bear full responsibility for the installation, maintenance and safe operation of the Generation Facilities. Customer shall be responsible for protecting, at Customer's sole cost and expense, the Generation Facilities from any condition or disturbance on Utility's electric system, including,but not limited to, voltage sags or swells, system faults, outages, loss of a single phase of supply, equipment failures, and lightning or switching surges. Customer agrees that, without the prior written permission from Utility,no changes shall be made to the configuration of the Generation Facilities, as that configuration is described in Exhibit A, and no relay or other control or protection settings specified in Exhibit A shall be set, reset, adjusted or tampered with, except to the extent necessary to verify that the Generation Facilities comply with Utility approved settings. 3. Operation by Customer. Customer shall operate the Generation Facilities in such a manner as not to cause undue fluctuations in voltage, intermittent load characteristics or otherwise interfere with the operation of Utility's electric system. At all times when the Generation Facilities are being operated in parallel with Utility's electric system, Customer shall operate the Generation Facilities in a manner that no disturbance will be produced to the service rendered by Utility to any of its other Customers or to any electric system interconnected with Utility's electric system. Customer understands and agrees that the interconnection and operation of the Generation Facilities pursuant to this Agreement is secondary to, and shall not interfere with, Utility's ability to meet its primary responsibility of furnishing reasonably adequate service to its Customers. Customer's control equipment for the Generation Facilities shall immediately, completely, and automatically disconnect and isolate the Generation Facilities from Utility's electric system in the event of a fault on Utility's electric system,a fault on Customer's electric system,or loss of a source or sources on Utility's electric system.The automatic disconnecting device included in such control equipment shall not be capable of reclosing until after service is restored on Utility's electric system. Additionally, if the fault is with Customer's Generation Facilities, such automatic disconnecting device shall not be reclosed until after the fault is isolated from Customer's facilities. 4. Access by Utility. Upon reasonable advance notice to Customer, Utility shall have access to any_interconnected facilities whether before, during or after the time the Generation Facilities first produce energy, to perform on-site inspections to verify that the installation and operation of the Generation Facilities comply with the requirements of this Agreement,the Utility's Tariff, and to verify the proper installation and continuing safe operation of the Generation Facilities.Utility shall also have, at all times,immediate access to breakers or any other equipment that will isolate the Generation Facilities from Utility's electric system. The Utility shall not be responsible for any costs Customer may incur as a result of such inspection(s). Utility shall have the right and authority to isolate the Generation Facilities at Utility's sole discretion if Utility believes that: (a) continued interconnection and parallel operation of the Generation Facilities with Utility's electric system creates or contributes (or will create or contribute) to a system emergency on either Utility's or Customer's electric system; (b)the Generation Facilities are not in compliance with the requirements of this Agreement or the Utility's Tariff; or (c) the Generation Facilities interfere with the operation of Utility's electric system. In non-emergency situations, Utility shall give Customer reasonable notice prior to isolating the Generating Facilities. 5. Rates and Other Charges. On June 28,2017 in Cause No. 44898,the Indiana Utility Regulatory Commission ("IURC" or "Commission") approved the assumption by the Indiana 51 Effective: January 20, 2021 Municipal Power Agency ("IMPA") of all obligations of its Commission-regulated municipal members, including Richmond Power & Light, to purchase energy and capacity offered by a Qualifying Facility of greater than ten kilowatts (10 kw) and less than twenty megawatts (20 MW) under 170 IAC 4-4.1 (for Cogeneration and Alternate Energy Production facilities). Thus, Customer shall execute a separate Power Purchase Agreement with IMPA. The Utility maintains its retail sales obligation, and any backup or supplemental power needed by the Customer will be sold pursuant to the Utility's applicable tariff provisions. 6. Insurance. Customer shall procure and keep in force during all periods of parallel operation of the Generation Facilities with Utility's electric system, homeowners, commercial, or other insurance to protect the interests of Utility under this Agreement, with an insurance carrier acceptable to Utility, and in amounts not less than that reasonably determined by the Utility to be necessary taking into consideration the nameplate capacity, configuration and type of Generation Facilities,for the liability of the insured against loss arising out of the use of generation equipment associated with the Qualified Facility. Customer shall deliver a certificate of insurance verifying the required coverage to Utility at least fifteen (15) days prior to any interconnection of the Generation Facilities with Utility's electric system, and thereafter as requested by the Utility. 7. Indemnification. Customer shall indemnify and hold harmless the Utility, City of Richmond, its employees, representatives, agents and subcontractors from and against all claims, liability, damages and expenses, including attorney's fees, based on any injury to any person, including the loss of life, or damage to any property, including the loss of use thereof, arising out of, resulting from, or connected with, or that may be alleged to have arisen out of, resulted from, or connected with, an act or omission by the Customer, its employees, agents, representatives, successors or assigns in the construction, ownership, operation or maintenance of the Customer's facilities used in connection with this Agreement.Upon written request of the Utility,the Customer shall defend any suit asserting a claim covered by this Section 7. If Utility is required to bring an action to enforce its rights under this Agreement, either as a separate action or in connection with another action, and said rights are upheld, the Customer shall reimburse such Utility for all expenses, including attorney's fees, incurred in connection with such action. 8. Effective Term and Termination Rights. This Agreement shall become effective when executed by both Parties and shall continue in effect until terminated in accordance with the provisions of this Agreement. This Agreement may be terminated for the following reasons: (a) Customer may terminate this Agreement at any time by giving Utility at least sixty (60) days prior written notice stating Customer's intent to terminate this Agreement and the disconnection of any Generating Facilities in parallel operation with the Utility's facilities at the expiration of such notice period; (b) Utility may terminate this Agreement at any time following Customer's failure to generate energy from the Generation Facilities in parallel with Utility's electric system within twelve (12) months after completion of the interconnection provided for by this Agreement; (c) either Party may terminate this Agreement at any time by giving the other Party at least sixty (60) days prior written notice that the other Party is in default of any of the material teinis and conditions of this Agreement, so long as the notice specifies the basis for termination and there is reasonable opportunity for the Party in default to cure the default; or(d)Utility may terminate this Agreement at any time by giving Customer at least sixty(60) days prior written notice in the event that there is a change in an applicable rule or statute affecting this Agreement. 52 Effective: January 20, 2021 9. Teiinination of Any Applicable Existing Agreement. From and after the date when service commences under this Agreement,this Agreement shall supersede any oral and/or written agreement or understanding between Utility and Customer concerning the service covered by this Agreement and any such agreement or understanding shall be deemed to be terminated as of the date service commences under this Agreement. 10. Force Majeure.For purposes of this Agreement,the term Force Majeure means any cause or event not reasonably within the control of the Party claiming Force Maj eure, including, but not limited to, the following: acts of God, strikes, lockouts, or other industrial disturbances; acts of public enemies; orders or permits or the absence of the necessary orders or permits of any kind which have been properly applied for from the government of the United States, the State of Indiana, any political subdivision or municipal subdivision or any of their departments, agencies or officials,or any civil or military authority;unavailability of a fuel or resource used in connection with the generation of electricity; extraordinary delay in transportation;unforeseen soil conditions; equipment, material, supplies, labor or machinery shortages; epidemics; landslides; lightning; earthquakes; fires; hurricanes; tornadoes; stout's; floods; washouts; drought; arrest; war; civil disturbances; explosions; breakage or accident to machinery, transmission lines, pipes or canals; partial or entire failure of utilities; breach of contract by any supplier, contractor, subcontractor, laborer or materialman; sabotage; injunction; blight; famine; blockade; or quarantine. If either Party is rendered wholly or partly unable to perform its obligations under this Agreement because of Force Majeure, both Parties shall be excused from whatever obligations under this Agreement are affected by the Force Majeure (other than the obligation to pay money) and shall not be liable or responsible for any delay in the performance of, or the inability to perform,any such obligations for so long as the Force Majeure continues. The Party suffering an occurrence of Force Majeure shall, as soon as is reasonably possible after such occurrence, give the other Party written notice describing the particulars of the occurrence and shall use commercially reasonable efforts to remedy its inability to perfoiin; provided, however, that the settlement of any strike, walkout, lockout or other labor dispute shall be entirely within the discretion of the Party involved in such labor dispute. 11. Choice of Law. This Agreement and the rights and duties of the parties arising out of this Agreement shall be governed by, and construed in accordance with,the laws of the State of Indiana without reference to the conflict of laws rules thereof. The parties hereby submit to the jurisdiction of the Courts of Wayne County, Indiana for purposes of all legal proceedings may arise under this Agreement. The parties hereto irrevocably waive, to the fullest extent permitted by Applicable Law, any objection which either may have or hereafter have to the personal jurisdiction of such court or the laying of the venue of any such proceeding brought in such a court and any claim that any such proceeding brought in such a court has been brought in an inconvenient forum. EACH OF THE PARTIES HERETO HEREBY KNOWINGLY, VOLUNTARILY, AND INTENTIONALLY WAIVES ANY RIGHTS IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION OR ARISING OUT OF, UNDER, OR IN CONNECTION WITH, THIS AGREEMENT, OR ANY COURSE OF CONDUCT, COURSE OF DEALING, STATEMENTS (WHETHER VERBAL OR WRITTEN), OF THE PARTIES. 53 Effective: January 20, 2021 IN WITNESS WHEREOF, the Parties have executed this Agreement, effective as of the date first above written. UTILITY CUSTOMER By: By: Printed Name: Printed Name: Title: Title: • 54 Effective: January 20, 2021 r ' Richmond Power and Light Rate Schedule Rider IS—PJM-DRS-Emergency Applicability This Rider is available for demand response service (DRS) to any retail customer of Richmond Power & Light (Utility) capable of meeting the terms and conditions listed below. The retail customer shall enter into a contract with the Utility and its wholesale electricity supplier the Indiana Municipal Power Agency (IMPA) for an interruptible load of at least 500 kW. The customer's DRS capacity under this Rider will be enrolled by IMPA on behalf of the Utility in the PJM Emergency Demand. Response Program. Unless contracted directly with IMPA and the Utility, or through a curtailment service provider contracted with IMPA, the customer's DRS capacity is not eligible for enrollment in any PJM demand response program. Conditions of Service 1. The retail customer shall enter into a contract with the Utility and IMPA for an interruptible load of at least 500 kW. 2. The provisions of this Rider qualify under the PJM Emergency Demand Response Program as of the approval date of this Rider. The Utility and IMPA reserve the right to make changes to this Rider in order to continue to qualify under the PJM Emergency Demand Response Program, or otherwise, as appropriate. 3. The Utility and/or IMPA reserve the right to call-for (request) customers to curtail their DRS load during a NM Initiated Load Management Event. 4. The Utility and/or IMPA will endeavor to provide customer as much advance notice as reasonably possible of curtailments under this Rider, including an estimate of the duration of such curtailments. However,the customer's DRS load shall be curtailed within one (1) hour if so requested. 5. All curtailments will apply for the delivery year, which 'is defined by PIM as June 1 through May 31 of the following year. Contracts will .apply for multiple delivery years. 6. In no event shall the customer be subject to DRS load curtailment under the provisions of this Rider for more than' sixty (60) hours or ten (10) interruptions during any delivery year. The customer must agree to be subject to DRS curtailments of up to six (6) consecutive hours' duration for each curtailment event, on weekdays between noon and 8 p.m., Eastern Prevailing Time, for the months May through September and between 2 p.m. and 10 p.m., Eastern Prevailing Time, for the months of October through April, 7. The Utility and/or IMPA will inform the customer regarding the communication process for notices to curtail. The customer is ultimately responsible for receiving and acting upon a 55 Effective: January 20, 2021 curtailment notification from the Utility or IMPA. 8. During each delivery year, the Utility or IMPA will conduct a test and verify the customer's ability to curtail as required by PIM, However, if a curtailment event is called by PIM prior to the test,then the event shall be considered the test for the delivery year. The Utility and IMPA reserve the right to re-test the customer if IMPA does not achieve the minimum 80% compliance testing standards for all of IMPA's DRS customers as required by PJM. These tests must be conducted for one hour on a .weekday between noon and 8. p.m., Eastern Prevailing Time, from June.1 through September 30 during the delivery year. 9. If the customer fails to comply with the provisions of curtailment this Rider,the Utility, IMPA and the customer will discuss methods to comply during future events. However, the Utility and IMPA reserve the right to discontinue service to the customer under this Rider if the problem cannot be resolved to their satisfaction. 10.The minimum DRS capacity contracted for under this Rider will be 500 kW. Customers with multiple electric service accounts with the Utility may aggregate those individual accounts to meet the 500 kW minimum DRS capacity requirement under this Rider, however, the DRS capacity committed for each individual account shall not be less than 100 kW. DRS capacity may not be aggregated with accounts with other utilities. 11.The Utility and/or IMPA reserve the right to call for (request) customers to curtail their DRS load when, in the sole judgment of the Utility or 1 MPA, an emergency condition,exists on the system. The Utility shall determine whether an emergency condition exists and if curtailment* of load served under this Rider is necessary in order to maintain service to the Utility's other firm Service customers. 12.If not already installed, the customer will provide space, facilities and cost reimbursement to the Utility for a Utility-provided recording demand meter to measure the customer's integrated demand. The Utility and IMPA shall have the sight to obtain meter readings and inspect and test meters at all times. 13.NO RESPONSIBILITY OR LIABILITY OF ANY ICCND SHALL ATTACH TO OR BE INCURRED BY THE UTILITY OR TWA FOR, OR ON ACCOUNT OF, ANY LOSS, COST, EXPENSE, OR DAMAGE CAUSED BY OR RESULTING FROM, EITHER DIRECTLY OR INDIRECTLY, ANY CURTAILMENT OF SERVICE UNDER THE PROVISIONS OF THIS RIDER. Customer Baseline Load Calculation A Customer Baseline Load (CBL) will be calculated for each hour corresponding to each curtailment event hour. Normally, the CBL will be calculated for each hour as the average corresponding hourly demands from the highest four (4) out of the five (5) most recent similar non-event days in the period preceding the relevant curtailment event. The highest load days are defined as the similar- days (Weekday, Saturday, Sunday/Holiday) with the highest energy consumption spanning the curtailment event hours. In cases where the normal calculation does not 56 Effective: January 20, 2021 provide a reasonable representation of normal load conditions,the Utility, IMPA and the customer may develop an alternative CBL calculation that more accurately reflects the customer's normal consumption pattern. Curtailed Demand The customer's Curtailed Demand shall be determined based upon the method of measurement chosen by the customer. The customer may choose one of two methods to measure the curtailed demand: 1) Guaranteed Load Drop (GLD) or 2) Firm Service Level (FSL). The method chosen shall remain in effect for the entire contract period. 1) Guaranteed Load Drop Method a) Each customer must designate a Guaranteed Load Drop (GLD), which amount shall be the minimum demand reduction that the customer will provide for each hour during a curtailment event or during a curtailment test. b) If the customer fails to fully comply with a request for curtailment under the provisions of this Rider or does not reduce load by the full GLD, a non-compliance charge shall apply: For this purpose, Actual Load Drop (ALD) is defined as the difference between the customer's CBL and their actual hourly load. If the ALD is less than the GLD, the Event Non-Compliance' Demand shall be equal to the maximum difference between the GLD and the ALD occurring during the hours of the curtailment event. Otherwise, the Event Non-Compliance Demand shall be zero (0). 2) Firm Service Level (FSL) Method a) Firm Service Level Peak Load Contribution(PLC)—The customer's PLC will be calculated each year as the average of its load during NM's five (5) highest peak leads during the twelve month period ended October 3 x of the previous year. b) Available Curtailable Demand(ACD)—The customer must designate an ACD, defined as the difference between the PLC and the Firm Service Level (FSL). The FSL is the demand to which the customer agrees to reduce load to or below for each hour during a curtailment event. c) If the customer fails to fully comply with a request for curtailment under the provisions of this Rider, then the Non-Compliance Charge shall apply. If a customer is operating at or below their designated FSL during an event, it will be understood that they have no DRS Capacity available with which to comply and will not be charged a non-compliance penalty. If the metered demand during the curtailment event is above the FSL, the Event Non-Compliance Demand shall be equal to the maximum difference between the customer's metered demand and the FSL during the hours of the-curtailment event. Otherwise the Event Non-Compliance Demand shall be zero (0). 57 Effective: January 20, 2021 Curtailed Energy The Curtailed Energy shall be determined for each curtailment event hour, defined as the difference between the customer's CBL for that hour and the customer's metered load for that hour. Curtailment Credits The Curtailment Energy Credit shall be 95% of the AEP East Load Zone hourly Real-Time Locational Marginal Price (LMP) established by PJM (including congestion and marginal losses) for each curtailment event hour. The Curtailment Demand Credit shall be calculated as 95% of the applicable PJM Reliability Pricing Model(RPM)Base Residual Auction price for the delivery year. The Curtailment Demand Credit ($/kW-Month) shall equal: RPM Price * 95% * 365 Days/ 12 Months/ 1,000 Within 30 days of completion of each PJM RPM Base Residual Auction, IMPA will notify Utility and Customer of the Curtailment Demand Credit for that delivery year. Monthly Demand Credit The Monthly Demand Credit shall be applicable to each month the customer is served under this Rider, regardless of whether or not there are any curtailment events during the month. Guaranteed Load Drop Method—The Monthly Demand Credit shall be equal to the product of the GLD and the Curtailment Demand Credit. Firm Service Level (FSL) Method—The Monthly Demand Credit shall be equal to the product of the ACD and the Curtailment Demand Credit. Monthly Event Credit An Event Credit shall be calculated for each event hour equal to the product of the Curtailed Energy for that hour and the Curtailment Energy Credit for that hour. The Monthly Event Credit shall be the sum of the hourly Event Credits for all events occurring in the calendar month. The customer shall not receive Event Credit for any curtailment events to the extent that the customer's DRS Capacity is already reduced due to a planned or unplanned outage as a result of vacation, renovation, repair, refurbishment, force majeure, strike, economic conditions, or any situation other than the customer's normal operating conditions. Annual Non-Compliance Charge Charges-for non-compliance will be based on the customer's Non-Compliance-Demand which reflects any failure by the customer to fully comply with requests for curtailment under the provisions of this. Rider. The Annual Non-Compliance Charge will be computed on an estimated 58 Effective: January 20, 2021 basis at the completion of the September delivery month and on an actual basis at the completion of the delivery year, The Annual Non-Compliance Charge shall be equal to the average Non- Compliance Demand times the Curtailment Demand Credit times 12. In the event that the estimated Annual Non-Compliance Charge is greater than zero, such charge shall be assessed as a uniform offset to the Customer Credits for remaining months of the delivery year, September through May. In the event the actual Annual Non-Compliance Charge is greater than zero, the customer will be invoked for any amount greater than the Customer Credit for the last month of the delivery year. In no event shall the Annual Non-Compliance Demand Charge exceed the sum of the Customer Credits, excluding the Annual Non-Compliance Charge, for the delivery year. Customer Credit The net amount of the. Monthly Demand Credit, Monthly Energy Event Credit and Annual Non- Compliance Charge will be provided to the Utility within two (2) billing months after the end of the delivery month. A customer may request the aggregation of individual customer account credits into a single credit. Adjustments to Customer Billing Units During months when the customer's interruptible load, is interrupted and customers paid the Curtailment Energy Credits discussed above,the customer's Metered Energy shall be increased by the verified curtailed energy. If the customer is billed on a coincident peak basis, during months when the customer's interruptible load is interrupted during the hour of the Utility's Billing Demand from IMPA, the Customer's metered demand shall be increased by the verified CTID or ACD. Term Contracts under this Rider shall be made for an initial period -of four (4) delivery years and shall remain in effect until either party provides three (3) years' written notice prior to March 1 of its intention to discontinue service under the terms of this Rider for the fourth delivery year beginning after the notice is provided. Special Terms and Conditions Customer specific information, including, but not limited to, DRS contract capacity, shall remain confidential. 3994876 1 59 Effective: January 20, 2021 FI INAL Huston Commissioner Yes No Npt Particiari,us Huston —Freeman V Krevda • STATE OF INDIANA 0b Ziegrter INDIANA UTILITY REGULATORY COMMISSION PETITION OF THE CITY OF RICHMOND, ) INDIANA, BY AND THROUGH ITS MUNICIPAL ) ELECTRIC UTILITY, RICHMOND POWER AND ) CAUSE NO. 45361 LIGHT, FOR APPROVAL OF A NEW SCHEDULE ) OF RATES AND CHARGES FOR ELECTRIC ) APPROVED: JAN 20 2021 SERVICE AND FOR APPROVAL TO MODIFY ITS ) ENERGY COST ADJUSTMENT PROCEDURES. ) ORDER OF THE COMMISSION Presiding Officers: David E. Ziegner, Commissioner Stefanie N. Krevda, Commissioner Jennifer L. Schuster, Administrative Law Judge On March 24, 2020, the City of Richmond, Indiana, and Richmond Power and Light (collectively, "RP&L") filed a petition with the Indiana Utility Regulatory Commission ("Commission"). initiating this Cause. On March 25, 2020, RP&L filed its case-in-chief. The Commission conducted a public field hearing in this Cause at 6 p.m. on June 29, 2020, at the Richmond Municipal Building, 50 N. 5th St, Richmond, Indiana. On July 2,2020,the Indiana Office of Utility Consumer Counselor("OUCC") filed consumer comments and its case-in-chief On August 6,2020,RP&L and the OUCC filed a Notice of Settlement Agreement and Motion for Settlement Agreement, Settlement Testimony, and Settlement Hearing Dates, indicating that the parties had reached a settlement on all issues in this Cause. On August 24, 2020, RP&L filed a Stipulation and Settlement Agreement ("Settlement Agreement"), and both parties filed settlement testimony. On September 11, 2020, the Presiding Officers issued a docket entry requesting additional information from RP&L regarding its proposed electric vehicle rate. RP&L submitted its response to the docket entry on September 14, 2020. Due to the ongoing COVID-19 pandemic, the Commission conducted a settlement hearing via WebEx on September 17, 2020 at 3 p.m. RP&L and the OUCC appeared at and participated in the hearing, and the parties' evidence was offered and admitted into the record without objection. On October 2, 2020, RP&L and the OUCC filed a Verified Joint Motion to Reopen Record, seeking to reopen the record to submit supplemental settlement testimony in order to correct an error in the previously submitted light-emitting diode ("LED") lighting rates. The Commission granted the motion and held a settlement hearing on October 21, 2020 at 2:30 p.m. via WebEx. At the hearing, the Verified Supplemental Settlement Testimony of Andrew J. Reger and corrected Attachments JAM-10 and JAM-11 (corrected redlined and clean tariffs) were admitted into evidence without objection. The Commission,having considered the evidence of record and applicable law, now finds: 1. Notice and Jurisdiction. Due, legal, and timely notice of the public hearings in this Cause was given and published by the Commission as required by law.RP&L is a municipally owned utility as that teiin is defined in Ind. Code §§ 8-1-2-1(h) and 8-1.5-1-10. Under Ind. Code § 8-1.5-3- 8(f)(2),the Commission has jurisdiction over RP&L's rates and charges. Therefore,the Commission has jurisdiction over RP&L and the subject matter of this Cause. 2. RP&L's Characteristics. RP&L is a municipally owned utility with its principal office located at 2000 U.S. Highway 27 South, Richmond, Indiana. RP&L, through the Common Council of the City of Richmond, which serves as RP&L's Board of Directors (the "Board"), owns, operates,manages, and controls plant, property, equipment, and generation facilities used and useful to provide electric utility service to approximately 21,029 customers in and around Richmond and Wayne County. 3. Relief Requested. In its Petition, RP&L requests approval of a new schedule of rates and charges for electric utility service, a change to its energy cost adjustment ("ECA") tracking mechanism, and approval to submit any adjustments to its new electric vehicle ("EV") Rate via the Commission's 30-day filing process, if needed. Subsequently, RP&L and the OUCC filed, and now request approval of, the Settlement Agreement. 4. RP&L's Case-In-Chief. A. Randall W. Baker. Mr. Baker, RP&L's CEO and General Manager, testified regarding RP&L's current utility operations, rate proposal, capital improvement plan ("CIP"), and changes to rate design. Mr. Baker also testified regarding changes in operations at RP&L's Whitewater Valley generation station ("WWVS"). Mr.Baker testified that RP&L's electric utility system includes sub-transmission,distribution, substation, and power production facilities, including coal-fired electric generating units at the WWVS.RP&L purchases all of its power and energy requirements from the Indiana Municipal Power Agency ("IMPA") pursuant to the terms of a power sales contract. Mr. Baker testified that RP&L's base rates have not increased since its last rate case order on February 9, 2005 in Cause No. 42713. RP&L's 2018 Annual Report indicates that the utility's net income has been negative for the last three years due to, in part, a downward trend in total electric sales. Mr. Baker stated that, since the utility's last rate case, it has lowered its employee count from 151 to 95. Since 2016, RP&L has been deploying new advanced metering infrastructure ("AMI") meters and has spread the cost of AMI deployment over several years. Mr. Baker testified that RP&L engaged the services of NewGen Strategies and Solutions, LLC ("NewGen") to perform a financial study and cost-of-service study ("COSS"). Based on the results of the study and input from RP&L's management, the Board resolved to seek the Commission's authority to increase base rates and charges and to restructure the utility's rates and charges to more accurately reflect the cost of service. Mr. Baker testified that RP&L has developed a seven-year CIP for 2018 through 2025. The CIP includes objectives for environmental compliance, AMI, rebuilds and replacements for the 2 distribution system, and street lighting upgrades. NewGen used RP&L's 2019 and 2020 budgets, which included funds for the CIP, in developing the utility's revenue requirement. Mr. Baker stated that RP&L considered requesting a transmission and distribution system improvement charge ("TDSIC"),but ultimately concluded that a TDSIC tracker is not ideal for a smaller municipal electric utility like RP&L. Mr. Baker testified that RP&L is requesting Commission approval to modify its current ECA to reflect its proposed rate design, which expands customer class categories, creates new customer classes that initially will have no customers, and establishes new demand charges for the General Power and General Electric Heating rates. RP&L is also proposing a new Electric Vehicle ("EV") rate. According to Mr. Baker, WWVS is owned by RP&L and operated by IMPA pursuant to a capacity purchase agreement. WWVS consists of two sub-critical, pulverized-coal-fired units with nominal generating capacity of 35 MW and 65 MW. The base case in IMPA's 2017 Integrated Resource Plan called for WWVS to be retired in 2026, but, at this time, no definitive retirement studies or decisions have been made. As the owner of WWVS, RP&L has the ultimate say in when WWVS is retired and will make that decision in close consultation with IMPA. RP&L is proposing to establish a dedicated environmental remediation reserve fund and a dedicated plant decommissioning reserve fund to ensure that the utility has sufficient funds on hand to close WWVS and remediate the coal ash pond. B. Laurie A. Tomczyk. Ms. Tomczyk, an Executive Consultant at NewGen, testified regarding RP&L's electric revenue requirements for the 12 months ended September 30, 2019, and proposed changes to RP&L's ECA tracker. Her testimony includes Table LAT-1, which summarizes RP&L's actual and adjusted test-year revenue requirements. Ms. Tomczyk testified that RP&L's revenue requirement was developed using the utility basis, which is the same basis used in the utility's last rate case. Under the utility basis approach,the return on rate base and depreciation expenses are used to recover capital-related costs on an accrual accounting basis. She testified that,pursuant to Ind. Code § 8-1.5-3-8 and approval by RP&L's Board, the utility recovers a return on investment through rates, which the Commission has broad discretion to approve. Ms. Tomczyk provided detailed descriptions of her proposed adjustments to RP&L's revenue requirement. She also calculated RP&L's rate base, which includes net plant in service, working capital,materials and supplies, prepayments, and contributions in aid of construction ("CIAC"). Ms. Tomczyk summarized RP&L's actual and adjusted test-year rate base in Table LAT-4 on page 37 of her direct testimony, and she provided detailed descriptions of her rate base adjustments. Finally, Ms. Tomczyk explained the establishment and current calculation of the ECA rate and RP&L's proposed changes to the application of the ECA rate to certain customer classes. Ms. Tomczyk developed a recommended ECA model that incorporates the proposed changes, which she attached to her testimony as Attachment LAT-4. C. Joseph A. Mancinelli. Mr. Mancinelli, President and CEO of NewGen, testified regarding the COSS and RP&L's rate design and tariff changes. The COSS functionalizes, sub-functionalizes, classifies, and allocates costs using a generally accepted methodology recognized 3 by the National Association of Regulatory Utility Commissioners ("NARUC") and the American Public Power Association ("APPA"). Based on this data, the COSS allocates RP&L's test-year revenue requirement to each rate class. Mr. Mancinelli testified that a COSS typically classifies costs into three categories: demand- related costs, energy-related costs, and customer-related costs. The demand-related costs are typically associated with system capacity requirements, are fixed in nature, and do not vary with day-to-day changes in system energy use. Energy-related costs are variable in nature and vary with day-to-day changes in system energy use. Customer-related costs, such as billing, collections, and customer service functions, are driven by the number of customers on the system. Mr. Mancinelli explained how he prepared the COSS based on financial data,monthly system operating data and statistics, system sub-transmission and distribution infrastructure statistics, monthly billing data, and class peak demand data, provided by RP&L. He also provided detailed testimony describing the methods used to complete, and the results of,the COSS. He summarized the results of the COSS in Tables JAM-5 and JAM-6 on pages 22 and 23 of his direct testimony. Mr. Mancinelli testified that rate design principles utilized in this case represent the policies, goals, and objectives important to RP&L and the community that it serves. These principles include ensuring revenue adequacy, implementing gradualism by spreading rate increases over three years in three phases, better aligning rates with class cost-of-service results, improving efficiency signals to commercial and industrial classes, improving fixed-cost recovery, improving conservation signals to residential customers,creating new commercial and industrial rate classes,and recalibrating the ECA. Mr. Mancinelli summarized the proposed rates on current revenues by class in Table JAM-7 on page 28 of his direct testimony. Mr. Mancinelli testified that RP&L's current residential service rate is a three-tier declining block structure that provides an incentive to customers to use more electricity because the average rate declines with higher usage.Based on the COSS, the residential service class is approximately 25.9%below its cost of service. RP&L's proposed Residential Electric Service rate gradually moves the residential classes toward its cost of service and eliminates the current declining rate structure. Although the proposed rate structure will impact large users of electricity more than small users due to the elimination of the declining block rate structure, the new rates provide a stronger conservation signal to customers, which can help mitigate future infrastructure investment. • D. Andrew J. Reger. Mr. Reger, an Executive Consultant at NewGen, testified regarding RP&L's proposed rate designs for lighting service, the new EV rate, the Electric Heating School rate,and the General Electric Heating rate. He also discussed RP&L's proposed miscellaneous non-recurring fees and charges. Mr. Reger testified that he updated RP&L's existing Outdoor Area Lighting and Street Lighting service rates and developed new rates for lighting service,including LED lamps and fixtures. Mr. Reger also testified that RP&L wishes to support the deployment of EVs for private, business, and government uses throughout Richmond and surrounding areas. For several years, RP&L's load has been declining. EV adoption could potentially restore some load growth and reduce upward pressure for all electric customers. A separately developed EV rate allows RP&L to monitor the perfoiniance, usage patterns, and adoption of EVs over time. RP&L's EV Charging Pilot Program— Public Location ("EV-PP") rate is designed for service to separately metered EV charging stations 4 operating in a public location. The EV-PP rate is designed as an energy-only rate charged to end users of the public EV charging facility. Mr. Reger testified that RP&L's Electric Heating Schools ("EHS") rate is provided to customers operating educational facilities who primarily use electric space heating.RP&L is currently under-recovering its cost of service from the three customers in this rate class. With respect to the General Electric Heating rate class, Mr. Reger testified that he simplified the rates by collapsing the current four-tiered energy rate down to two tiers and collapsing the current two-tiered demand rate down to one demand charge. Finally, Mr. Reger updated RP&L's non-recurring charges, such as dishonored checks, connection and disconnection of service, meter testing, service calls, meter tampering charges, and minimum trip charges for service visits. The updates are based on updated cost information for each service and a comparison to neighboring utilities with similar fees and charges. 5. OUCC's Case-In-Chief. A. Lauren M. Aguilar. Ms. Aguilar, Utility Analyst in the OUCC's Electric Division, testified regarding RP&L's proposed EV rate and coal combustion residual ("CCR") remediation costs. Ms. Aguilar testified that, based on RP&L's testimony, the OUCC could not verify whether RP&L was proposing a permanent EV rate or an EV pilot program. She noted that RP&L's testimony included the word "pilot" in some places and that the utility's 2020 budget includes $70,000 for an "Electric Vehicle Charging Stations Pilot."After conferring with RP&L,Ms.Aguilar determined that the proposed EV rate is not intended to be a pilot program and that the $70,000 line item in the 2020 budget should be removed. Ms. Aguilar recommended that RP&L file an annual report with the Commission regarding public charging station usage and performance, the adoption of EVs in RP&L's service territory, and other specific information set forth in her testimony. With the removal of the word "pilot" and the $70,000 budget item and the addition of the reporting requirement, Ms. Aguilar recommended approval of the EV rate. Ms. Aguilar summarized the legal requirements for CCR pond closure. She testified that the WWVS contains a pond once used for storing CCR materials generated by the plant, but that RP&L stopped using the pond decades ago. She noted that RP&L has no plan to close the pond and has not filed a request for a closure permit with the Indiana Department of Environmental Management ("IDEM"). Ms. Aguilar testified that the remediation project could have cost significantly less if it had been started when RP&L stopped using the pond in the 1970s. Despite this, and because RP&L is a municipal utility, the OUCC recommended approval of the project amount with changes recommended by Mr. Loveman and discussed further below. B. Anthony A. Alvarez. Mr. Alvarez, Utility Analyst in the OUCC's Electric Division, testified regarding RP&L's CIP, including the micro-turbine pilot project, vehicle replacements, line extensions, AMI, and other system modifications. Mr. Alvarez testified that RP&L allocated $100,000 in its 2020 capital budget for a micro- turbine pilot project, but the utility did not provide testimony about the project. In response to the OUCC's discovery requests, RP&L stated that it intended to file corrected testimony to remove the 5 $100,000 budget for the project, but, as of the time Mr. Alvarez's direct testimony was filed, RP&L had not yet done so. Mr. Alvarez stated that, in calculating its budget for vehicle replacements, RP&L did not account for the trade-in value of the vehicles it was replacing. Based on data provided by RP&L in discovery, Mr. Alvarez calculated the relevant trade-in values and proposed an adjustment of $102,473 to RP&L's normalized budget amount. According to Mr. Alvarez, RP&L included an annual budget of$400,000 for line extensions and new loads in its CIP. He noted that RP&L's total system expansion project costs were only $115,386 in 2019 and $192,355 to date in 2020. As a result, Mr. Alvarez recommended a $200,000 adjustment to RP&L's proposed budget for these expansion projects. Mr. Alvarez testified that RP&L included an annual budget of$200,000 for miscellaneous substation modifications in its CIP, but the utility did not provide a detailed scope of work for the project. He recommended that the Commission require RP&L to keep the funding for these projects in a restricted account to ensure the funds are used for much-needed upgrades, modifications, and replacements of the utility's substation relays and major equipment. Mr. Alvarez also recommended a$100,000 adjustment to RP&L's proposed system modifications and rebuilds based on the utility's historical spending for such projects. Finally, Mr. Alvarez stated that he has no concerns regarding RP&L's AMI deployment. C. Wes R. Blakley. Mr. Blakley, Senior Utility Analyst in the OUCC's Electric Division, testified regarding RP&L's proposed revenue requirements and return on rate base calculation. Mr. Blakley testified that the OUCC treats interest income and other operating revenue differently than RP&L in the revenue requirement schedules. The difference results in an OUCC- calculated revenue deficiency that is approximately$9,000 less than RP&L's calculation. This results in a 9.45%revenue increase as opposed to the 9.6% increase that RP&L requested. Mr. Blakley testified that, under Ind. Code § 8-1.5-3-8(e), RP&L is entitled to a reasonable return on its utility plant, but RP&L calculated its return based on total rate base. He stated that RP&L's net plant less CIAC is $53,686,611, as compared to RP&L's rate base calculation of $65,714,525. This difference changes the calculation of RP&L's return from 6.59% to 8.07%. Mr. Blakley also testified that the WWVS should be excluded from RP&L's return calculation based on the terms of the capacity purchase agreement with IMPA. Mr. Blakley stated that this adjustment further increases RP&L's return to 9.02%. D. Peter M. Boerger, Ph.D. Dr. Boerger, Senior Utility Analyst in the OUCC's Electric Division, testified regarding RP&L's COSS and rate design. He stated that; in general, he agreed with RP&L's COSS methodology, but he questioned the use of data from other utilities and other rate classes to estimate coincident peak load contributions.Dr.Boerger concluded that,although it is not perfect,RP&L's COSS is reasonable given the data limitations for a small utility like RP&L, and he recommended that the Commission accept the COSS. 6 • • Dr.Boerger offered an alternative rate design to reduce the customer class subsidies identified in the COSS,which was summarized in Table PMB-1 in his direct testimony. He also recommended, due to the current economic conditions,that the Commission consider weighting the three phased rate increases so that a smaller increase is imposed in the first phase with progressively larger increases in phases two and three. Dr. Boerger testified that RP&L's proposed $15.75 facilities charge (also referred to as a "customer charge") is higher than RP&L's average cost to connect a residential customer to its system,which he calculated as$7.08 per month.Based on this conclusion,Dr. Boerger recommended that the Commission keep RP&L's residential customer charge at its current rate of$10.00 per month. He also proposed lower facilities charges for business classes for the same reason. Finally, Dr. Boerger recommended that the Commission delete RP&L's Customer-Specific Contract rate from its tariff because this rate gives the utility an inappropriate amount of discretion in setting rates,has not been used in the past, and RP&L discourages potential applicants from using the rate. E. Kaleb G. Lantrip. Mr. Lantrip, Utility Analyst in the OUCC's Electric Division, testified regarding RP&L's requested rate of return. Mr. Lantrip also proposed certain adjustments to RP&L's uncollectible expense, payment in lieu of taxes ("PILT"), and utility receipts tax ("URT"). Mr. Lantrip discussed the adjustments made by the OUCC's witnesses and attached schedules showing these adjustments. Mr. Lantrip testified that RP&L is proposing a return based on a 4.59% proxy cost of debt derived from the March 2019 report of the average return on long-term, municipal, tax-exempt, investment-grade bonds. Mr.Lantrip disagreed with RP&L's proposed hypothetical capital structure, which included both debt and equity,based on the 2018 APPA-based debt/equity weighting of capital structure to simulate an investor-owned utility. With respect to RP&L's rate base components, Mr. Lantrip testified that the utility's return should be calculated only on net plant in service, less adjustments for CIAC and the WWVS. He proposed a rate of return of 4.59% based on the Russell Tax-Exempt Bond's average coupon rate on a 10-plus-year issuance. Mr. Lantrip expressed his concern that RP&L transfers $1,361,917 of its excess cash to the City of Richmond's general fund, in addition to the utility's PILT obligation and other budget transfers. He testified that these cash transfers indicate RP&L's revenue requirement is providing more money than the utility needs to operate. Mr. Lantrip made a $16,349 adjustment to RP&L's proposed PILT amount based on the percentage of RP&L's customers and assets located within the City of Richmond's tax jurisdictional boundaries. Mr. Lantrip made a $29,774 adjustment to uncollectible accounts expense based on the OUCC's revenue requirement calculation. He also made a$48,976 adjustment to RP&L's URT. F. Caleb R. Loveman. Mr. Loveman, Utility Analyst in the OUCC's Electric Division, testified regarding proposed adjustments to RP&L's labor expense, employee benefits expense,Federal Insurance Contributions Act("FICA")tax expense, and remediation and demolition expenses at WWVS. 7 Mr. Loveman testified that RP&L's employee count has dropped over the past several years and any new hires are expected to replace vacant, or soon to be vacant, positions. Due to this, he stated that no increase in labor expense is warranted. Mr. Loveman recommended removing $94,245 of labor expense related to RP&L's affiliated company Parallax, which is reimbursed by Parallax. Mr. Loveman recommended an adjustment of $2,582 to remove expenses related to donations, retirement gifts, awards, and similar charges. Mr. Loveman recommended a 3% increase to test-year labor expense, as opposed to the 4.63% increase that RP&L proposed,based on the terms of RP&L's union-labor contract. Based on his adjustments to test-year labor expense, Mr. Loveman made corresponding adjustments to FICA tax expense. With respect to CCR pond remediation, Mr. Loveman agreed with RP&L's proposed calculation, but disagreed with the proposed amortization period. Mr. Loveman proposed that the remediation costs be amortized over an eight-year period. He also recommended that the annual amortization amounts be placed in a restricted cash reserve fund to ensure that the funds will only be used for CCR pond remediation. Finally, Mr. Loveman recommended an annual amortization amount of $835,087 for the decommissioning expense related to WWVS. Mr. Loveman used publicly available data provided by the U.S.Bureau of Labor Statistics for historical inflation rates, assumed a 2%inflation rate for future years, and amortized the final amount over a 10-year period. He also proposed that the annual decommissioning expense be placed in a restricted cash reserve fund to ensure the funds will only be used for WWVS decommissioning. 6. Settlement. In their Settlement Agreement, RP&L and the OUCC agreed that RP&L should be authorized to increase its rates and charges to reflect the total net revenue requirement of $86,551,153 (a total increase of 7.23%), which is a decrease of approximately $1.9 million from the amount originally requested by RP&L. The parties also agreed that RP&L will implement its overall 7.23%rate increase over three phases, with the first phase ("Phase 1") in the amount of 3.72%to be effective upon the issuance of the Commission's final order in this Cause. The second phase ("Phase 2"), in the amount of 2.26%, will be effective 12 months after the effective date of Phase 1. The third phase ("Phase 3"), in the amount of 1.10% will be effective 12 months after the effective date of Phase 2. Both RP&L and the OUCC submitted testimony supporting the Settlement Agreement,which is summarized below. A. RP&L's Settlement Testimony. i. Mr. Baker. Mr. Baker testified that the Settlement Agreement addresses RP&L's main concerns by increasing RP&L's rates by 7.23% to allow RP&L sufficient cash flow and income to prudently operate the utility, while still funding necessary reserve accounts. The key aspects of the Settlement Agreement are an agreed net revenue requirement and total revenue requirement, an agreed rate of return of 4.59%, an agreed phase-in of rate increases for certain rate classes, and gradual funding of reserve accounts for CCR pond remediation and WWVS decommissioning. In the Settlement Agreement,the parties agreed to RP&L's proposed modification to its ECA procedures as described in the Petition and Ms. Tomczyk's direct testimony. In addition, the 8 • u Settlement Agreement permits RP&L to begin its EV program with annual reporting requirements and requires RP&L to file annual CIP progress reports with the Commission and the OUCC. The Settlement Agreement also eliminates the Customer-Specific Contract tariff. Finally, the Settlement Agreement requires RP&L to file a petition to review its base rates no later than January 1, 2026. With respect to RP&L's proposed EV program, Mr. Baker testified that RP&L will annually report the following data to the Commission and the OUCC: • The number of customers in RP&L's service territory who drive an EV prior to the beginning of the program and annually thereafter; • The number of customers using the RP&L-provided public charging station each day; • The duration of each charge; • The kWh of each charge; • The time of day that charges occurred (or at least off peak vs. on peak); • The approximate location of the customer (i.e., local or out of state); and • The approximate battery level of the EV before and after charging. Mr. Baker opined that approval of the Settlement Agreement is in the public interest because it represents a comprehensive resolution of all issues in the proceeding raised by RP&L and the OUCC.He stated that the Settlement Agreement provides RP&L the opportunity to recover sufficient revenues, maintain adequate cash flows, and fund necessary reserve accounts while balancing the interest of RP&L's customers in receiving reasonable service at a fair cost. ii. Mr. Mancinelli. Mr. Mancinelli testified that the parties exchanged several settlement proposals and responses,participated in conference calls,and shared analyses. The parties recognized the uncertainty associated with litigation and understood that a well-reasoned compromise would result in an acceptable outcome that avoided the uncertainty and expense of a fully litigated case. Ultimately, the parties agreed on a lower total revenue requirement than that originally proposed by RP&L, an associated revenue requirement per rate class, a rate design, and a phase-in of rate increases tailored to specific rate classes. Mr. Mancinelli testified that RP&L original requested a $7,735,848 (9.58%) increase in operating revenues, and the parties ultimately agreed to a $5,833,797 (7.23%) increase. He summarized the agreed adjustments to RP&L's revenue requirement in his settlement testimony, including an updated Table JAM-1. He opined that the agreed revenue requirement addresses many of the concerns of the OUCC and still provides RP&L sufficient revenues to reliably operate the utility and generate sufficient cash to recapitalize the system and provide for necessary reserves. Mr. Mancinelli stated that a key component of the Settlement Agreement is the acceleration of rate increases to the commercial and industrial rate classes, which will mitigate the impacts of the reduced revenue requirement on RP&L and produce sufficient cash flow. He summarized the rate increases by rate class in Table JAM-3 on pages 13-14 of his settlement testimony. Rates for all classes except residential were redesigned based on the Settlement Agreement, while the rate structures for the commercial and industrial rate classes were largely unchanged from RP&L's original proposal. Mr. Mancinelli submitted an updated rate design and COSS as Attachment JAM-8 9 and Confidential Attachment JAM-9, respectively. RP&L also agreed to limit the annual increase in the Residential Facilities Charge to $0.75 (as opposed to the original proposal of$1). According to Mr. Mancinelli, the Settlement Agreement reflects a compromise that achieves a desirable and beneficial outcome for RP&L and its customers. Virtually all rate classes will receive a lower increase than originally requested by RP&L, and residential customers will see a lower cumulative increase of 11.89%, as opposed to the original proposal of 15.76%. RP&L will make deposits of reserve funds into restricted accounts, and the phase-in strategy mitigates customer bill impacts by spreading necessary increases over one to three years depending on the required increase for each class while also aligning RP&L's retail rates with the COSS results. Mr. Mancinelli attached an updated tariff and revenue proof as JAM-10 (redlined tariff), JAM-11 (clean tariff), and JAM-8 (revenue proof). iii. Mr. Reger. Mr. Reger testified that, after the September 17, 2020 settlement hearing in this Cause, Petitioner discovered that the LED lighting rates it submitted were incorrect,a fact that was unknown to the parties at the time the record was closed.Mr.Reger explained that the corrected LED lighting rates will be lower than the tariff rates submitted with Mr. Mancinelli's settlement testimony. Currently,there are no customers on these LED rates because they are new, and these corrections resulted in no impact to revenues or any other rate class. Mr. Reger corrected these errors and submitted new clean and redlined tariffs (Attachments JAM-10 and JAM- 11)to reflect the correct LED lighting rates. B. OUCC's Settlement Testimony. i. Dr. Boerger. Dr. Boerger testified that the parties agreed to a residential facilities charge that increases by$0.75 in each of the three annual rate increases,resulting in a charge of$12.25 in the third phase. The OUCC accepted RP&L's originally proposed facilities charges for all non-residential classes. With respect to the three-phase rate increases, the OUCC accepted RP&L's three-phase increase proposal. However, under the Settlement Agreement, rate classes with smaller overall rate increases will experience their increase in either one or two phases. This will provide adequate cash flow to RP&L while also ensuring that no rate class experiences an unreasonably burdensome rate increase in any one phase. Dr. Boerger opined that the Settlement Agreement is in the public interest because the rate design and facilities charges fall within the range of expert testimony presented in this case and represent a reasonable compromise. He stated that the structure of phased-in rate increases provides relief to customers by avoiding rate shock while also providing sufficient cash flow to RP&L so it may continue to provide reliable service to its customers. ii. Mr. Lantrip. Mr. Lantrip stated that the Settlement Agreement is the product of thorough negotiations, with each party offering to compromise on issues. Based on the number of benefits provided to ratepayers,the OUCC,as the statutory representative of all ratepayers, believes the Settlement Agreement is a fair resolution to the issues in this case, is supported by the evidence, and should be approved. Mr. Lantrip testified that the parties agreed to a revenue requirement increase of approximately $5.834 million, approximately $1.902 million less that RP&L's original request. The Settlement Agreement results in a 7.23% system-wide revenue increase. He described the benefits of 10 • the Settlement Agreement to customers, which include a reduced rate of return of 4.59% (compared to 6.59%),resulting in a$1.846 million revenue requirement reduction;a reduced increase to RP&L's labor expense of 3% (compared to 4.63%), resulting in a $186,520 revenue requirement reduction; and an annual amortization expense of$2,321,930 (compared to $2,680,000),resulting in a$358,070 revenue requirement reduction. Mr. Lantrip explained that the reduced rate of return is the product of compromise taking into consideration RP&L's cash flow needs and the impact on ratepayers' bills. The parties also agreed to base the rate of return on a net plant amount of$54,131,072,rather than RP&L's calculated rate base of$65,714,525, so that the return calculation is consistent with Ind. Code § 8-1.5-3-8(e). The parties also settled on an agreed escalation rate of 3% for labor expenses and amortization of remediation costs over six years rather than five years. The Settlement Agreement includes an agreed depreciation expense of$4,584,845 and a revenue requirement reduction of$50,311 to account for interest income that RP&L earns from its loan to Parallax. Finally, Mr. Lantrip stated that RP&L has agreed to file its next rate case by January 1, 2026 and to provide a new evaluation of the sufficiency of its funding of restricted accounts and adjust its depreciation and amortization account balances. 7. Commission Discussion and Findings. The parties seek approval of their Settlement Agreement, which resolves all issues in this case. Settlements presented to the Commission are not ordinary contracts between private parties. United States Gypsum, Inc. v. Indiana Gas Co., 735 N.E.2d 790, 803 (Ind. 2000). Any settlement agreement that is approved by the Commission "loses its status as a strictly private contract and takes on a public interest gloss." (quoting Citizens Action Coalition of Indiana, Inc. v. PSI Energy, Inc., 664 N.E.2d 401, 406 (Ind. Ct. App. 1996)). Thus, the Commission"may not accept a settlement merely because the private parties are satisfied;rather, [the Commission] must consider whether the public interest will be served by accepting the settlement." Citizens Action Coalition, 664 N.E.2d at 406. Any Commission decision,ruling, or order—including the approval of a settlement—must be supported by specific findings of fact and sufficient evidence, as well as a determination that the decision, ruling, or order is not contrary to law. United States Gypsum, 735 N.E.2d at 795 (citing Citizens Action Coalition of Indiana, Inc. v. Public Service Co. of Indiana, Inc., 582 N.E.2d 330, 331 (Ind. 1991)). Therefore, before we can approve the Settlement Agreement, we must determine whether the evidence in this Cause sufficiently supports the conclusion that the Settlement Agreement is reasonable, just, and consistent with the purpose of applicable law, is not contrary to law, and serves the public interest. Indiana law strongly favors settlement as a means of resolving contested proceedings. See, e.g., Georgos v. Jackson, 790 N.E.2d 448, 453 (Ind. 2003) ("Indiana strongly favors settlement agreements."); Mendenhall v. Skinner & Broadbent Co., 728 N.E.2d 140, 145 (Ind. 2000) ("The policy of the law generally is to discourage litigation and encourage negotiation and settlement of disputes.") (citation omitted). A settlement agreement"may be adopted as a resolution on the merits, if[the Commission] makes an independent finding supported by substantial evidence on the record as a whole that the proposal will establish just and reasonable rates."Mobil Oil Corp. v. Fed. Power Comm'n, 417 U.S. 283, 314 (1974) (emphasis in original) (internal quotation marks omitted); see also, e.g., Indianapolis Power & Light Co., Cause No. 39938, 1995 WL 735722 (IURC Aug. 24, 1995) (quoting Mobil Oil Corp., 417 U.S. at 314). 11 As explained further below, we find that the Settlement Agreement is reasonable, just, and consistent with the purpose of applicable law, is not contrary to law, and serves the public interest. Therefore, we approve the Settlement Agreement in its entirety. A. Test Period. The test period selected for deteuuining RP&L's revenues and expenses reasonably incurred in providing utility service to its customers is the 12 months ended September 30, 2019, adjusted for changes that are fixed, known, and measurable for ratemaking purposes and that occur within 12 months following the end of the test year. We find that the test period is sufficiently representative of RP&L's normal operations to provide reliable data for ratemaking purposes. B. Revenue Requirement. Ind. Code § 8-1.5-3-8(c) establishes how the Commission determines just and reasonable rates and charges for a municipally owned utility: (c) "Reasonable and just rates and charges for services"means rates and charges that produce sufficient revenue to: (1) pay all legal and other necessary expenses incident to the operation of the utility, including: (A)maintenance costs; (B) operating charges; (C)upkeep; (D) repairs; (E) depreciation; and (F) interest charges on bonds or other obligations, including leases; (2) provide a sinking fund for the liquidation of bonds or other obligations, including leases; (3) provide a debt service reserve for bonds or other obligations; including leases, in an amount established by the municipality, not to exceed the maximum annual debt service on the bonds or obligations or the maximum annual lease rentals; (4)provide adequate money for working capital; (5) provide adequate money for making extensions and replacements to the extent not provided for through depreciation in subdivision (1); and (6) provide money for the payment of any taxes that may be assessed against the utility. Rates and charges under hid. Code § 8-1.5-3-8 are designed to produce an income sufficient to maintain a municipally owned utility's property in a sound physical and financial condition to render adequate and efficient service. Rates and charges that are too low to meet the foregoing requirements are unlawful. RP&L's municipal legislative body also elected to include a reasonable return on the utility plant of the electric utility in accordance with Ind. Code § 8-1.5-3-8(e). RP&L and the OUCC have agreed to the level of RP&L's annual revenue requirements,which are reflected in the Settlement Agreement and summarized below. The parties submitted substantial evidence in their respective direct and settlement testimony and exhibits describing the components of and adjustments to RP&L's revenue requirement. Based on the evidence of record, we find that RP&L's current rates and charges are insufficient to provide for RP&L's annual cash revenue requirement and are therefore unlawful. We approve the agreed revenue requirement contained in the Settlement Agreement, which is summarized as follows: 12 Purchased Power Expense $63,409,146 O&M Expense $12,486,349 Depreciation Expense $4,584,845 Amortization Expense $2,321,930 Taxes Other Than Income Taxes $2,348,084 Other Revenue and Interest Income ($156,268) Return on Plant $2,484,616 Revenue Requirement $87,478,702 Plus: URT Amt on Adjustments $81,673 Plus: Uncollectible Amt on Adjustments $22,052 Total Revenue Requirement $87,582,427 Less Other Income ($1,031,274) Net Revenue Requirement $86,551,153 C. Authorized Rates and Customer/Facility Charges. To meet its revenue requirement of$86,551,153, RP&L is authorized to increase its current rates and charges for retail service so as to produce additional operating revenues of$5,833,797,representing a 7.23% increase in RP&L's annual revenues from retail rates and charges. In addition, RP&L and the OUCC agreed that the monthly customer/facility charge for the residential customer class will be increased by $0.75 in each of the three phases (for a total increase of$2.25),resulting in a total residential customer/facility charge in Phase 3 of$12.25.Mr.Mancinelli submitted an updated rate design as Exhibit JAM-8, which summarizes the rate schedules and monthly customer/facility charges, demand charges, and energy charges for each customer class. Based on the evidence of record, we approve the monthly customer/facility charges agreed to in the Settlement Agreement and as set forth in Exhibit JAM-8. D. Allocation of Revenue Requirement to Customer Classes. Mr. Mancinelli updated his COSS and rate design based on the terms of the Settlement Agreement and attached updated schedules to his settlement testimony. The parties, using the updated COSS, agreed to a rate allocation between customer classes that mitigates rate shock to any one class while moving the customer classes toward cost-based rates. Based on the evidence of record, we approve the allocation of revenue requirement to the customer classes contained in the Settlement Agreement and as set forth below: 13 Settlement Rate Increases Residential 11.89% Commercial Lighting Service 2.58% General Power Service 4.37% Large Power Secondary 9.05% Large Power CP-Primary 4.21% Large Power CP-Secondary 11.44% Industrial Service-Primary 4.16% Industrial Service CP Primary 2.58% Electric Heating Schools 13.79% General Electric Heating 8.70% Outdoor Lighting Services 13.79% Street Lighting Services 8.54% System Increase 7.23% E. Three-Phase Rate Increase Methodology. RP&L and the OUCC agreed to a three-phase rate increase methodology that is customized by rate class. The evidence presented by the parties shows that the three-phase methodology will mitigate the rate shock to customer classes facing large increases by ensuring that no class receives an increase greater that 5%in any one phase. At the same time,the methodology ensures that RP&L has sufficient cash flow starting in Phase 1 to maintain efficient and reliable utility service by front-loading the rate increases for those classes facing smaller increases. Based on the evidence of record, we approve the three-phase rate increase methodology contained in the Settlement Agreement and as set forth below: Class Phase 1 Phase 2 Phase 3 Total Residential 3.65% 3.90% 3.90% 11.89% Commercial Lighting Service 2.58% 0.00% 0.00% 2.58% • General Power Service 3.48% 0.86% 0.00% 4.37% Large Power Secondary 5.00% 3.86% 0.00% 9.05% Large Power CP Primary 3.40% 0.78% 0.00% 4.21% Large Power CP Secondary 5.00% 5.00% 1.08% 11.44% Industrial Service-Primary 3.38% 0.75% 0.00% 4.16% Industrial Service CP Primary 2.58% 0.00% 0.00% 2.58% Electric Heating Schools 4.40% 4.40% 4.40% 13.79% General Electric Heating 5.00% 3.52% 0.00% 8.70% Outdoor Lighting Services 4.40% 4.40% 4.40% 13.79% Street Lighting Services 5.00% 3.37% 0.00% 8.54% F. Customer-Specific Contract Tariff. The settling parties agree that RP&L will remove and no longer offer a Customer-Specific Contract tariff. Dr. Boerger testified that no customer currently uses the tariff and that RP&L discourages customers from using the tariff. Based on the evidence of record, we authorize RP&L to remove the Customer-Specific Contract tariff. G. Restricted Fund Requirements.RP&L and the OUCC agreed that RP&L will deposit funds reserved for certain expenses into restricted funds to ensure that those funds are used for the expenses they were reserved for, as described further below. 14 i. Coal Combustion Residual Pond Remediation. The parties agreed that RP&L will deposit an average annual amount of$2,321,930 over six years into a restricted fund for CCR pond remediation expense, resulting in a total fund of $13,931,580 for CCR pond remediation. Because of the phased-in nature of the rates approved above, the parties agreed that, over the three-year phase-in period(years one through three),RP&L will deposit a total of$6,965,790 for CCR pond remediation,but it need not necessarily deposit the same amount in each of those three years. In years four through six, RP&L will deposit $2,321,930 per year into the restricted fund for CCR pond remediation. ii. WWVS Decommissioning. The parties agreed that RP&L will deposit an average annual amount of $953,721 over nine years into a restricted fund for WWVS decommissioning expense. The parties also agreed that the money for this fund will not be included in RP&L's revenue requirement, but will be paid out of the utility's return or other cash resources. Because of the phased-in nature of the rates approved above, the parties agreed that, over the three- year phase-in period (years one through three), RP&L will deposit a total of$2,861,163 for WWVS decommissioning, but it need not necessarily deposit the same amount in each of those three years. In years four through nine, RP&L will deposit $953,721 per year into the restricted fund for WWVS decommissioning. iii. Miscellaneous Substation Modifications. The parties agreed that RP&L will deposit an average annual amount of$200,000 into a restricted fund for miscellaneous substation modifications. The parties also agreed that the money for this fund will not be included in RP&L's revenue requirement, but will be paid out of the utility's return or other cash resources. Because of the phased-in nature of the rates approved above, the parties agreed that, over the three- year phase-in period (years one through three), RP&L will deposit a total of $600,000 for miscellaneous substation modifications, but it need not necessarily deposit the same amount in each of those three years. After year three, for the remaining life of the rates approved in this Order,RP&L will deposit$200,000 per year into the restricted fund for miscellaneous substation modifications. • Based on the evidence of record, we approve the terms of the Settlement Agreement related to the restricted funds for CCR pond remediation, WWVS decommissioning, and miscellaneous substation modifications. H. Capital Improvement Plan. The parties agreed that RP&L's CIP will include $450,000 in funding for system modifications and rebuilds, $521,277 in funding for vehicle acquisition and replacement, and $300,000 in funding for line extensions and new loads. The parties agreed that RP&L will provide an annual report to the Commission and the OUCC which identifies and describes projects it is undertaking for the current year and the following year and which provides information on the status,budget,and expenses of previous,current,and future projects.These reports to the OUCC and the Commission will start on December 31, 2021 and annually thereafter for the duration of the seven-year CIP and will include data for the 12 months preceding the date of the report. Based on the evidence of record, we approve RP&L's proposed CIP and agreed reporting requirements. Beginning on December 31, 2021 and continuing for the duration of the CIP, RP&L will submit an annual report to the OUCC and the Commission under this Cause containing at least the information set forth above. 15 I. EV Program and Reporting Requirements. The parties agreed that RP&L's $100,000 budget for the EV program will not be included in RP&L's revenue requirement, but will be paid out of the utility's return or other cash resources. The parties also agreed that RP&L will report the following information to the OUCC and the Commission starting on December 31, 2021, and annually thereafter, including data for the 12 months preceding the report (except for the first report, which will only contain information from the time in 2021 following this Order): • The number of customers in RP&L's service territory who drive an EV prior to the beginning of the program and annually thereafter; • The number of customers using the RP&L-provided public charging station each day; • The duration of each charge; • The kWh of each charge; • The time of day that charges occurred (or at least off peak vs. on peak); • The approximate location of the customer(i.e., local or out of state); and • The approximate battery level of the EV before and after charging. Based on the evidence of record, we approve RP&L's proposed EV program and tariff, and we also approve the agreed reporting requirements. Beginning on December 31,2021 and continuing until RP&L's next rate case order or until otherwise ordered by the Commission, RP&L will submit an annual report to the OUCC and the Commission under this Cause containing at least the information set forth above. J. RP&L's Next Rate Case. The parties agreed that RP&L will file a new petition for Commission review of RP&L's base rates, which will include a review of the appropriateness of continuing RP&L's restricted fund requirements set forth above, no later than January 1, 2026. Based on the evidence of record, we approve this provision of the Settlement Agreement. K. New ECA Procedures. Based on the evidence of record,we approve RP&L's proposed modifications to its ECA procedures, as described in Ms. Tomczyk's direct testimony. L. Approval of Settlement Agreement.Based on the evidence of record and our discussion above, we find that the Settlement Agreement represents a fair and just resolution of all the issues is this Cause. Having reviewed the Settlement Agreement, we further find that it is in the public interest. The terms of the Settlement Agreement provide sufficient cash flow for RP&L to continue to operate its utility reliably and efficiently and to plan and save for future expenses. At the same time, the Settlement Agreement limits the cost increases to ratepayers and mitigates rate shock by spreading the increase over three years. Therefore, we approve the Settlement Agreement in its entirety. 8. Use of the Settlement Agreement. The parties have agreed that the Settlement Agreement will not constitute nor be cited as precedent by any person or deemed an admission by any settling party in any other proceeding, except as necessary to enforce the terms of the Settlement Agreement. The parties also agreed that the Settlement Agreement is solely the result of compromise in the settlement process and is without prejudice to and will not constitute a waiver of any position 16 • that either settling party may take with respect to any issue in any future regulatory or non-regulatory proceeding. With regard to future citation of the Settlement Agreement, we find that the Settlement Agreement and our approval of it should be treated in a manner consistent with our fmding in Richmond Power &Light, Cause No. 40434 (March 19, 1997). 9. Confidentiality. On March 25, 2020, RP&L filed a Motion for Confidential Treatment, which was supported by the Affidavit of Randall W. Baker, showing that certain information to be submitted to the Commission contained trade secret information that is not known or readily available to persons outside of RP&L. The Presiding Officers issued a Docket Entry on April 6, 2020, finding that this information should be held confidential on a preliminary basis, after which the information was submitted under seal. After reviewing the information, we find this information qualifies as confidential trade secret information pursuant to Ind. Code §§ 5-14-3-4 and 24-2-3-2. This infoiivation will be held as confidential and protected from public access and disclosure by the Commission and is exempted from the public access requirements contained in Ind. Code ch. 5-14-3 and Ind. Code § 8-1-2-29. IT IS THEREFORE ORDERED BY THE INDIANA UTILITY REGULATORY COMMISSION that: 1. The Settlement Agreement between RP&L and the OUCC,a copy of which is attached hereto, is approved in its entirety. 2. RP&L's net revenue requirement of$86,551,153 and a total revenue requirement of $87,582,427 is approved. 3. RP&L is authorized to collect a 4.59%rate of return. 4. RP&L is authorized to implement the rate increases set forth herein and in the Settlement Agreement. Prior to implementing the rates authorized in this Order, RP&L shall file the tariff and applicable rate schedules under this Cause for approval by the Commission's Energy Division. Such rates will be effective on or after the Order date, subject to Energy Division review and agreement with the amounts reflected. 5. The proposed RP&L tariff, as corrected on October 2, 2020, is approved consistent with the Settlement Agreement and this Order. 6. RP&L is authorized to gradually fund reserve accounts for CCR pond remediation and WWVS decommissioning as set forth in the Settlement Agreement and this Order. 7. RP&L is authorized to modify its ECA procedures as described in the Petition in this Cause and Ms. Tomczyk's direct testimony as set forth in the Settlement Agreement and this Order. 8. RP&L is authorized to begin its EV program with annual reporting requirements beginning on December 31, 2021 and continuing until the Commission's final order in RP&L's next base rate case or as otherwise ordered by the Commission, as set forth herein and in the Settlement Agreement. 9. RP&L's proposed CIP is hereby approved. Beginning on December 31, 2021 and continuing through the duration of the CIP, RP&L shall file annual CIP progress reports with the 17 Commission and the OUCC, as set forth herein and in the Settlement Agreement. 10. RP&L is authorized to eliminate the Customer-Specific Contract tariff offering. 11. RP&L shall file a petition to review its base rates no later than January 1, 2026. 12. The information submitted under seal in this Cause pursuant to RP&L's Motion for Confidential Treatment is determined to be confidential trade secret information pursuant to Ind. Code §§ 5-14-3-4 and 24-2-3-2 and will continue to be held as confidential and exempt from public access and disclosure pursuant to Ind. Code §§ 5-14-3-4 and 8-1-2-29. 13. In accordance with Ind. Code § 8-1-2-70, RP&L shall pay the following itemized charges within 20 days from the date of this Order into the Commission public utility fund account described in Ind. Code § 8-1-6-2,through the Secretary of the Commission, as well as any additional costs that were incurred in connection with this Cause: Commission Charges $ 6,956.09 OUCC Charges $ 97,040.81 Legal Advertising Charges $ 324.21 TOTAL $ 104,321.11 14. This Order shall be effective on and after the date of its approval. HUSTON,FREEMAN,KREVDA, OBER,AND ZIEGNER CONCUR: APPROVED: JAN 20 2021 I hereby certify that the above is a true and correct copy of the Order as approved. Mary M. Digitally signed by MaryM. Schneider Schneider _DOS'00'ate:2021.01.2010:12:13 Mary M. Schneider Secretary of the Commission 18 • FILED August 24, 2020 INDIANA UTILITY REGULATORY COMMISSION STATE OF INDIANA INDIANA UTILITY REGULATORY COMMISSION PETITION OF THE CITY OF RICHMOND, ) INDIANA,BY AND THROUGH ITS ) MUNICIPAL ELECTRIC UTILITY, ) RICHMOND POWER AND LIGHT, FOR ) CAUSE NO. 45361 APPROVAL OF A NEW SCHEDULE OF ) RATES AND CHARGES FOR ELECTRIC ) SERVICE AND FOR APPROVAL TO MODIFY ) ITS ENERGY COST ADJUSTMENT ) PROCEDURES ) JOINT STIPULATION AND SETTLEMENT AGREEMENT This Joint Stipulation and Settlement Agreement("Settlement Agreement") is entered into this 24th day of August, 2020, by and between Richmond Power & Light ("RP&L" or"Utility") and the Indiana Office of the Utility Consumer Counselor ("OUCC") (collectively, the "Settling Parties"), who stipulate and agree for purposes of settling all matters in this Cause between them that the terms and conditions set forth below represent a fair, reasonable, and negotiated compromise resolution of all issues in this Cause, subject to their incorporation in a final order of the Indiana Utility Regulatory Commission("Commission"). Terms and Conditions of Settlement Agreement 1. Requested Relief. On March 24, 2020, RP&L initiated this Cause by filing a Petition to adjust its rates and charges for electric service and for authority to modify its energy cost adjustment("ECA")procedures. 2. Prefiled Evidence of Parties. In support of its Petition, RP&L filed the prefiled testimony and exhibits of Randall W. Baker, Laurie A. Tomczyk, Joseph A. Mancinelli and Andrew J. Reger. On July 2, 2020, the OUCC filed the prefiled testimony and exhibits of Kaleb G. Lantrip, Wes R. Blakley, Anthony A. Alvarez, Lauren M. Aguilar, Caleb R. Loveman, and Peter M. Boerger. The case was settled before rebuttal testimony was filed. 3. Settlement. Through analysis, discussion, and extensive negotiation, as aided by their respective technical staff and experts, RP&L and the OUCC have now agreed on the terms and conditions as described herein that resolve all issues between them in this Cause. 4. Revenue Requirement, Rates, and Charges. The Settling Parties agree that RP&L should be authorized to increase its rates and charges for electric service to reflect a total net revenue requirement in the amount of$86,551,153 resulting in a total increase of 7.23% over RP&L's current revenues at existing rates. The Settling Parties further agree that RP&L shall implement its overall 7.23%rate increase over three (3)phases with the first phase ("Phase I") in the amount of 3.72% to be effective upon the issuance of the Commission's final order in this Cause. The second phase ("Phase II") in the amount 2.26% will be effective twelve months after Phase I. The third phase ("Phase III"), in the amount of 1.10%, will be effective twelve months after Phase II. This Revenue Requirement is a decrease of approximately $1.9 Million from the amount originally requested by RP&L. Below is the agreed upon revenue requirement calculation, which is determined in accordance with I.C. § 8-1.5-3-8: Purchased Power Expense $63,409,146 O&M Expense $12,486,349 Depreciation Expense $4,584,845 Amortization Expense $2,321,930 Taxes Other Than Income Taxes $2,348,084 Other Revenue and Interest Income ($156,268) Return on Plant $2,484,616 Revenue Requirement $87,478,702 Plus: URT Amt on Adjustments $81,673 Plus: Uncollectible Amt on Adjustments $22,052 Total Revenue Requirement $87,582,427 Less Other Income ($1,031,274) Net Revenue Requirement $86,551,153 2 All other issues set forth in RP&L's case-in-chief that are not specifically addressed in this Joint Stipulation and Settlement Agreement shall be approved as proposed by RP&L as set forth in its supporting Settlement Testimony. 5. Allocation of Agreed Upon Increase in Operating Revenues. The cost of service study("COSS")prepared by NewGen Strategies&Solutions attached to the Settlement Testimony of Joseph M. Mancinelli was used by RP&L to establish a new schedule of rates and charges implementing the authorized increase in operating revenues. 6. Rate of Return. RP&L will be authorized to earn a return on net utility plant of 4.59%. 7. Mitigation of COSS Cost Allocations. At the as-settled revenue increase, the Parties agree that RP&L's rate increases by class shall be as follows: As-Settled Rate Increases Residential 11.89% Commercial Lighting Service 2.58% General Power Service 4.37% Large Power Secondary 9.05% Large Power CP -Primary 4.21% Large Power CP - Secondary 11.44% Industrial Service - Primary 4.16% Industrial Service CP Primary 2.58% Electric Heating Schools 13.79% General Electric Heating 8.70% Outdoor Lighting Services 13.79% Street Light Services 8.54% System Increase 7.23% 8. Three-Phase Rate Increase Methodology. The Parties agree that RP&L's rate increase will occur in three phases' as set forth below: 1 The phase percentage increases are compounded to result in the total percentage increases. 3 Class Phase 1 Phase 2 Phase 3 Total Residential Electric Service 3.65% 3.90% 3.90% 11.89% Commercial Lighting Service 2.58% 0.00% 0.00% 2.58% General Power Service 3.48% 0.86% 0.00% 4.37% Large Power Service-Secondary 5.00% 3.86% 0.00% 9.05% Large Power Services-Coincident Peak-Primary 3.40% 0.78% 0.00% 4.21% Large Power Services-Coincident Peak-Secondary 5.00% 5.00% 1.08% 11.44% Industrial Service-Primary 3.38% 0.75% 0.00% 4.16% Industrial Service Coincident Peak- 2.58% 0.00% 0.00% 2.58% Electric Heating Schools 4.40% 4.40% 4.40% 13.79% General Electric Heating 5.00% 3.52% 0.00% 8.70% Outdoor Lighting Services 4.40% 4.40% 4.40% 13.79% Street Light Services 5.00% 3.37% 0.00% 8.54% 9. Customer/Facility Charges and Rate Schedules. The Settling Parties agree that the monthly customer/facility charge for the Residential Class shall be increased by seventy-five cents ($0.75) in each of the three phases, for a total increase in the monthly customer/facility charge of two dollars and twenty-five cents ($2.25), resulting in a total residential customer/facility charge not to exceed$12.25. Mr. Mancinelli will present the Rate Design Model in his Settlement Testimony which includes the rate schedules for each class setting forth the monthly customer/facility charges, demand charges and energy charges for each customer class as agreed to by the Settling Parties. Mr. Mancinelli's Settlement Testimony also includes a revenue proof demonstrating that the agreed schedule of rates and charges will produce the annual Revenue Requirement agreed upon herein. The Settling Parties further agree to the Non- Recurring Charges set forth in Mr. Mancinelli's Settlement Testimony. 10. Customer Specific Contract Tariff. The Settling Parties agree that RP&L shall remove and no longer offer a Customer Specific Contract tariff offering. 4 11. Restricted Fund Requirements. The Settling Parties agree that RP&L shall deposit into restricted fund accounts the following amounts (the"Restricted Fund Requirements"). a. Coal Combustion Residual("CCR")Pond. The Parties agree to an average annual amount of$2,321,930, as agreed to as part of the revenue requirement such that at the conclusion of the agreed six-year amortization period,the restricted fund account for the CCR Pond liability will be funded at a total of$13,931,580. Due to the phased-in rate structure, RP&L will fund$6,965,790 into the restricted fund account for the CCR Pond liability over the three-year phase-in period, with the understanding that RP&L will have more cash available to fund the restricted account in later years, so the annual funding levels will not be the same for each year of the three-year phase in period. After the three- year phase in period,the average annual funding level will be$2,321,930. b. WWVS Decommissioning. The Parties agree to an average annual amount of $953,721. This amount is "below-the- line" and not a component of the revenue requirement. Due to the phased-in rate structure, RP&L will fund$2,861,163 into the restricted account over the three-year phase-in period, with the understanding that RP&L will have more cash available to fund this account in later years, so the annual funding levels will not be the same for each year of the three-year phase-in period. After the three-year phase-in period,the average annual funding level for the WWVS decommissioning liability will be $953,721 for the remainder of the agreed nine-year amortization period. c. Miscellaneous Substation Modifications. The Parties agree to an average annual amount of$200,000. This amount is "below-the- line" and not a component of the revenue requirement. Due to the phased-in rate structure, RP&L will fund $600,000 5 into the restricted account over the three-year phase-in period, with the understanding that RP&L will have more cash available to fund this account in later years, so the annual funding levels will not be the same for each year of the three-year phase-in period. After the three-year phase-in period,the average annual funding level for Miscellaneous Substation Modifications will be $200,000 for the remaining life of RP&L's rates set herein. 12. System Modifications and Rebuilds. The Settling Parties agree to a$450,000 funding level amount for System Modifications and Rebuilds, and RP&L shall file annual progress report for these projects and associated expenditures throughout its Seven-Year Capital Improvement Plan. RP&L shall identify and provide the descriptions of the individual System Modifications and Rebuilds projects it is undertaking for the current year and following year in its annual progress report including the corresponding status,budget and expenses of previous, current and future projects. RP&L shall provide project information in a manner that promotes transparency and traceability of these projects in its annual progress report. RP&L's capital plan reports will be filed with the Commission and the OUCC beginning December 31, 2021 for the preceding 12-months, and will occur annually thereafter. 13. Future Base Rate Case Filing. The Settling Parties agree that no later than January 1, 2026, RP&L will file a new petition for Commission review of RP&L's base rates, which shall include a Commission deteiniination of the appropriateness of continuing RP&L's Restricted Fund Requirements set forth above. 14. Electric Vehicle Program. The Settling Parties agree that RP&L's proposed $100,000 budget for the electric vehicle ("BV") program will be removed from its capital budget, which is "below the line" and is not a component of the revenue requirement and that the EV 6 tariff included in Mr. Mancinelli's Settlement Testimony shall be approved. The Settling Parties further agree that RP&L shall annually report the following to the OUCC and the Commission: a. The number of customers in RP&L service territory who drive an EV prior to the beginning of the tariff's effective date, and yearly thereafter; b. The number of customers using the RP&L-provided public station each day; c. The duration of each charge; d. The kWh of each charge; e. The time of day charges occurred(at the very least, off-peak vs. on-peak); f. The general location of the customer(local or out of state) if reasonably discernable by RP&L; and g. The battery level of the EV prior to charging and the charge level at the conclusion(i.e. was the car empty when it started and full when it left) if reasonably discernable by RP&L. RP&L's EV reports will be filed with the Commission and the OUCC beginning December 31, 2021 including data for the preceding 12-months, and will occur annually thereafter. 15. Micro Turbine/Distributed Generation Pilot. The Settling Parties agree that RP&L shall remove the $100,000 budgeted amount for the Micro Turbine/DG Pilot, which is "below the line" and is not a component of the revenue requirement. 16. Vehicle Acquisition and Replacement. The Settling Parties agree to a normalized amount of$521,277 for Vehicle Acquisition and Replacement, which is "below the line" and not a component of the revenue requirement. 17. Line Extensions and New Loads. The Settling Parties agree to a normalized amount of$300,000 for Line Extensions and New Loads, which is "below the line" and not a component of the revenue requirement. 18. Admissibility and Sufficiency of Evidence. The Settling Parties stipulate to the admissibility of the testimony and exhibits presented by the Settling Parties in this proceeding. The Settling Parties agree that the prefiled evidence constitutes substantial evidence sufficient to support this Settlement Agreement and provides an adequate evidentiary basis upon which the 7 Commission can make all findings of fact and conclusions of law necessary for the approval of this Settlement Agreement as filed. 19. Non-Precedential Effect of Settlement. The Settling Parties agree that the facts in this Cause are unique and all issues presented are fact specific. Therefore,the Settlement Agreement shall not constitute nor be cited as precedent by any person or deemed an admission by any Settling Party in any other proceeding except as necessary to enforce its terms before the Commission or any court of competent jurisdiction. This Settlement Agreement is solely the result of compromise in the settlement process, and is without prejudice to and shall not constitute a waiver of any position that either Settling Party may take with respect to any issue in any future regulatory or non-regulatory proceeding. The Settlement Agreement provides the Settling Parties with certain agreed upon benefits without the uncertainty, risk, and expense of further protracted litigation. 20. Authority to Execute. The undersigned hereby represent and agree that they are fully authorized to execute the Settlement Agreement on behalf of their designated clients who will hereafter be bound thereby. 21. Proposed Order. The Settling Parties hereby agree to submit a proposed final order for issuance by the Commission which the Settling Parties will file after the evidentiary hearing in this matter. 22. Approval of Settlement Agreement in its Entirety. As a condition of this Settlement,the Settling Parties specifically agree that if the Commission does not approve this Joint Stipulation and Settlement Agreement in its entirety, the entire Settlement Agreement shall be null and void and deemed withdrawn, unless otherwise agreed to in writing by the Settling Parties. The Settling Parties further agree, unless otherwise separately agreed to in writing by the Settling Parties,that in the event the Commission does not issue a Final Order in the form 8 that reflects the Agreement described herein, the matter should promptly proceed to a litigated hearing, and the Commission should thereafter rule based on the litigation evidence of record in this proceeding. The Settling Parties agree that, in such event, the evidence of record and any post-hearing filings should be considered by the Commission as if no settlement had been reached, unless otherwise agreed by all Settling Parties in a writing that is filed with the Commission. All settlement discussion shall be treated as privileged and confidential. The Settling Parties represent that there are no other agreements in existence between them relating to matters covered by this Settlement Agreement. 23. Confidentiality. The parties recognize that certain confidential information has been shared through discovery in this matter. Such information includes (but is not limited to) the confidential Revenue Requirement Study and the confidential electronic Cost of Service Study performed by NewGen Strategies and Solutions, which includes customer-specific proprietary usage data. The OUCC has entered into a confidentiality agreement with RP&L and the parties shall treat all such confidential information as confidential information in accordance with such agreement(s). ACCEPTED AND AGREED: RICHMOND POWER & LIGHT INDIANA OFFICE OF THE UTILITY CONSUMER COUNSELOR 0414 /4111Ma{ Kristina Kern Wheeler Tiffany Murray Nikki Gray Shoultz Randall Helmen Bose McKinney &Evans LLP Office of Utility Consumer Counselor 111 Monument Circle, Suite 2700 115 West Washington Street, Suite 1500 S Indianapolis, IN 46204 Indianapolis, IN 46204 Phone: (317) 684-5000 Phone: (317) 232-2786 kwheeler@boselaw.com timurray@oucc.IN.gov nshoultz@boselaw.com rhelmen@ourcc.in.gov 3915877_1 9