The URL can be used to link to this page

Home My Public Portal About001-2022 - RPL Traffic with Rates 1 RESOLUTION 1-2022 A RESOLUTION OF THE UTILITY SERVICE BOARD OF THE CITY OF RICHMOND,INDIANA RECOMMENDING THE APPROVAL OF NEW RATES AND CHARGES FOR RICHMOND POWER&LIGHT TO IMPLEMENT THE REPEAL OF THE UTILITY RECEIPTS TAX ON JULY 1,2022 WHEREAS;the City of Richmond, Indiana ("City"), by and through its Utility Service Board ("Board"), owns and operates a municipal electric utility for the purpose of distributing electricity in said City and surrounding areas; and WHEREAS,the rates and charges of Richmond Power&Light("RP&L"or"Utility")are subject to the jurisdiction of the Common Council("Council") and the Indiana Utility Regulatory Commission("Commission"); and WHEREAS,the existing rates and charges for electric services provided by the Utility were placed into effect following approval by the Commission in Cause No. 45361 in a Final Order dated January 20,2021; and WHEREAS, on March 15, 2022, Governor Eric Holcomb signed House Bill 1002 ("HB 1002"), which effective July 1, 2022, repeals the Utility Receipts Tax (found at Indiana Code 6- 2.3 et seq.) ("URT"), a tax that is built into RP&L's rates and recovered through the Utility's Commission approved revenue requirement; and WHEREAS, BB 1002 requires that RP&L file, by May 1, 2022, a new tariff with the Commission that reflects lower customer rates as a result of the URT repeal, and RP&L has retained a consultant to develop those new rates; and WHEREAS,the Board and its advisors believe the Council should adopt a Rate Ordinance approving a new schedule of rates and charges for services provided by the Utility that: (i)replace existing rates and decrease electric operating revenues by approximately 1.4%per year as a result of the URT repeal; and (ii) the proposed rates and charges are still designed so that they are 1 f y nondiscriminatory"reasonable and just charges" for electric service within the meaning of IC 8- 1.5-3-8; and the rate design should be modified accordingly; and WHEREAS,the Board and Utility management have developed revised schedules of rates and charges for electric service based upon the assistance and advice of the consultant, which schedule of rates and charges are attached hereto as Exhibit A; 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, rates and charges for services rendered by the Utility must be approved by the Common Council of the City of Richmond, Indiana, and the Indiana Utility Regulatory Commission. NOW, THEREFORE, BE IT RESOLVED by the Utility Service Board that the attached schedule of rates and charges should be recommended for approval by the Common Council by Rate Ordinance. BE IT FURTHER RESOLVED subject to Common Council approval of such revised rates and charges by the adoption of an Ordinance, that the necessary and appropriate officials of the Utility should be authorized to file with the Commission a"30-day filing" seeking approval of a new schedule of electric rates and charges to reflect the repeal of the Utility Receipts Tax. PASSED AND ADOPTED BY THE BOARD OF DIRECTORS OF RICHMOND POWER&LIGHT THIS a DAY OF �?G c� ,2022. BOARD OF DIRECTORS OF RICHMOND POWER&LIGHT By: 5- Chairman Attest. 2 I I i 1 Exhibit A New Tariff of Rates and Charge for Richmond Electric Light&Power i i i IL RICHMOND POWER AND LIGHT RATES AND CHARGES FOR ELECTRIC SERVICE RICHMOND,INDIANA PURUSUANT TO IURC FINAL ORDER IN CAUSE NO. 45361 EFFECTIVE: JANUARY 20,2022 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. r a T a 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) 35 General Electric Heating(GEH) 36 Electric Vehicle Charging Program—Public Location(EV PP) 38 Rider NM—Net Metering 40 Rider ED—Economic Development 44 Rider QF—Qualifying Facilities 46 Rider IS—PJM-DRS-Emergency 54 2 f 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 i ECA Adjustment __ ; Bihing Unit R $X.XXXXX Per kWh CL $X.XXXXX Per kWh EHS $X.XXXXX 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.XXXXX Per kWh ISP $X.XX Per kVA $X.XXXXX Per kWh ISP Coincident $X.XX Per kW $X.XXXXX Per kWh LS $X.XXXXX 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 T • 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 20,2022 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 2 Phase 3 Facilities Charge $/Month $11.34 $12.08 Energy Charge: Tier 1 for the first 350 kWh $/kWh $0.10010 $0.10050 Tier 2 for the next 1150 kWh $/kWh $0.09625 $0.10050 Tier 3 for all kWh above 1500 kWh $/kWh $0.09271 $0.10050 * 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 2 Effective:January 20,2022 Phase 3 Effective: January 20,2023 S � 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 2 Phase 3 _ Facilities Charge $/Month $20.46 $20.46 Energy Charge $/kWh $0.11957 $0.11957 * 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 2 Effective: January 20,2022 Phase 3 Effective:January 20,2023 J • 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 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 2 Phase 3 Facilities Charge $/Month $71.99 $71.99 Energy Charge: Tier 1 for the first 500 kWh $/kWh $0.07495 $0.07495 Tier 2 for the next 1,500 kWh $/kWh $0.07495 $0.07495 Tier 3 for the next 3,000 kWh $/kWh $0.07495 $0.07495 Tier 4 for all kWh above 5,000 kWh $/kWh $0.07495 $0.07495 Demand Charge: Tier 1 for up to 25 kW $/kW $6.41 $6.41 Tier 2 for each kW of demand in excess of 25 kW $/kW $6.41 $6.41 * 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. 8 Phase 2 Effective: January 20,2022 Phase 3 Effective: January 20,2023 r 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 $0.46 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. 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 9 Phase 2 Effective: January 20,2022 Phase 3 Effective:January 20,2023 ' 1 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 2 Effective: January 20,2022 Phase 3 Effective: January 20,2023 1 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 2 Phase 3 Facilities Charge $/Month $192.56 $192.56 Energy Charge $/kWh $0.03466 $0.03466 Demand Charge $/kVA $24.66 $24.66 * 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 2 Effective: January 20,2022 Phase 3 Effective: January 20,2023 A TERMS AND CONDITIONS FOR RENDERING 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 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 2 Phase 3 -; Facilities Charge $/Month $192.56 $192.56 Energy Charge $/kWh $0.03271 $0.02830 Billing Demand Charge $/kW $25.02 $26.53 Transmission and Distribution Demand Charge(in addition to Billing Demand and Energy Charge) $/kVA $4.41 $5.52 * 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 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 2 Effective:January 20,2022 Phase 3 Effective:January 20,2023 i S 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 Power Service Primary Units Phase 2 Phase 3 Facilities Charge $/Month $192.56 $192.56 Energy Charge $/kWh $0.03512 $0.03499 Demand Charge $/kVA $22.67 $22.81 * 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 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 2 Effective: January 20,2022 Phase 3 Effective: January 20,2023 3 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 2 Phase 3 Facilities Charge $/Month $192.56 $192.56 Energy Charge $/kWh $0.02857 $0.02857 Billing Demand Charge $/kW $25.98 $25.98 Transmission and Distribution Demand Charge(in addition to Billing Demand and Energy Charge) $/kVA $3.68 $3.68 * 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 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 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 2 Phase 3 Facilities Charge $/Month $192.56 $192.56 Energy Charge $/kWh $0.03393 $0.03393 Demand Charge $/kVA $24.66 $24.66 * 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 requirements of the Customer.Not more than one such transformation will be installed at the Utility's expense for any one Customer. 19 Phase 2 Effective: January 20,2022 Phase 3 Effective:January 20,2023 1 i 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 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 2 _ Phase 3 Facilities Charge $/Month $192.56 $192.56 Energy Charge $/kWh $0.02652 $0.02464 Billing Demand Charge $/kW $25.02 $26.53 Transmission and Distribution Demand Charge (in addition to Billing Demand and Energy Charge) $/kVA $4.41 $5.52 * 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 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 21 Phase 2 Effective: January 20,2022 Phase 3 Effective: January 20,2023 o � r r 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 2 Effective: January 20,2022 Phase 3 Effective: January 20,2023 f 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 2 Phase 3 Facilities Charge $/Month $192.56 $192.56 Energy Charge $/kWh $0.03324 $0.03324 Demand Charge $/kVA $23.67 $23.67 * 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 2 Effective: January 20,2022 Phase 3 Effective: January 20,2023 I 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 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 2 Phase 3 Facilities Charge $/Month $192.56 $192.56 Energy Charge $/kWh $0.02599 $0.02414 Billing Demand Charge $/kW $25.88 $25.98 Transmission and Distribution Demand Charge (in addition to Billing Demand and Energy Charge) $/kVA $3.08 $3.68 * 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 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 25 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.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 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 2 Phase 3 Facilities Charge $/Month $192.56 $192.56 Energy Charge $/kWh $0.02710 $0.02710 Demand Charge $/kVA $21.70 $21.70 * 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 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 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 2 Phase 3 Facilities Charge $/Month $192.56 $192.56 Energy Charge $/kWh $0.02710 $0.02710 Billing Demand Charge $/kW $25.20 $25.20 Transmission and Distribution Demand Charge(in addition to Billing Demand and Energy Charge) $/kVA $1.99 $1.99 * 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 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 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. RATES 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: 100 W Sodium Vapor OL $5.80 $6.06 150 W Sodium Vapor OL $6.37 $6.65 175 W Mercury Vapor OL $8.40 $8.77 31 Phase 2 Effective: January 20,2022 Phase 3 Effective: January 20,2023 250 W Metal Halide Flood OL $9.20 $9.61 250 W Mercury Vapor OL $10.47 $10.94 250 W Sodium Vapor Flood OL $8.99 $9.39 250 W Sodium Vapor OL $11.92 $12.45 400 W Metal Halide Flood OL $10.78 $11.25 400 W Mercury Vapor OL $12.59 $13.15 400 W Sodium Vapor Flood OL $10.68 $11.14 50 W LED (100W HPS Equiv) $8.12 $8.12 111 W LED (250W HPS Equiv) $11.10 $11.10 243 W LED (400W HPS Equiv) $15.30 $15.30 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____ _ 100 W Sodium Vapor-UG-Fiber $7.83 $7.83 100 W Sodium Vapor-UG-Metal $7.83 $7.83 150 W Sodium Vapor-OH-Metal $12.62 $12.62 150 W Sodium Vapor-OH-Metal-T $16.81 $16.81 150 W Sodium Vapor-OH-Wood $8.23 $8.23 150 W Sodium Vapor-UG-Metal $16.83 $16.83 150 W Sodium Vapor-UG-Metal-T $21.12 $21.12 175 W Metal Hal-UG-Metal-C-S $9.06 $9.06 175 W Metal Hal-UG-Metal-C-T $12.46 $12.46 175 W Metal Halide-UG-Metal $16.78 $16.78 175 W Mercury Vapor UG-Metal $18.30 $18.30 175 W Mercury Vapor-UG-Metal-S $8.86 $8.86 175 W Mercury Vapor-UG-Wood $13.16 $13.16 250 W Mercury Vapor-OH-Metal $13.57 $13.57 250 W Sodium Vapor-OH-Metal $13.61 $13.61 32 Phase 2 Effective: January 20,2022 Phase 3 Effective: January 20,2023 S p Street Lighting and Area Lighting ryaswy 4 q 7x 250 W Mercury Vapor-OH-Wood $9.45 $9.45 250 W Sodium Vapor-OH-Wood $9.45 $9.45 250 W Sodium Vapor-OH-Metal-T $17.81 $17.81 250 W Mercury Vapor-UG-Metal-S $18.91 $18.91 250 W Sodium Vapor-UG-Metal $18.91 $18.91 250 W Sodium Vapor-UG-Metal-T $22.45 $22.45 400 W Sodium Vapor-OH-Wood $31.05 $31.05 400 W Metal Hal-UG-Metal-C-S $10.68 $10.68 400 W Sodium Vapor-UG-Metal $32.91 $32.91 1000 W Metal Halide-UG-Metal-T $36.18 $36.18 150 Sodium Vapor-UG-Metal $25.07 $25.07 2-400 W Sodium Vapor-UG-Met-N $42.84 $42.84 4-400 W Mercury Vapor-UG-Met-N $46.78 $46.78 400 W Sodium Vapor-UG-Metal-N $31.11 $31.11 70 W Sodium Vapor-UG-Metal $21.86 $21.86 70 W-Sodium Vapor-UG-Metal-T $31.11 $31.11 SL<400W-OH-Wood $11.80 $11.80 72 W LED (100 W HPS Equiv.)-UG-Metal Post $19.54 $19.54 72 W LED (100 W BPS Equiv.)-UG-Decorative Post $24.04 $24.04 71 W LED (150 W HPS Equiv.)-OH-Wood Single Pendant $17.15 $17.15 111 W LED(250 W BPS Equiv.)-OH-Wood Single Pendant $18.93 $18.93 278 W LED(400 W HPS Equiv.)-OH-Wood Single Pendant $23.12 $23.12 71 W LED (150 W BPS Equiv.)-OH-Metal Single Pendant $21.11 $21.11 111 W LED(250 W HPS Equiv.)-OH-Metal Single Pendant $22.89 $22.89 278 W LED(400 W HPS Equiv.)-OH-Metal Single Pendant $27.09 $27.09 71 W LED (150 W BPS Equiv.)-UG-Metal Single Pendant $22.50 $22.50 111 W LED(250 W HPS Equiv.)-UG-Metal Single Pendant $24.27 $24.27 278 W LED(400 W HPS Equiv.)-UG-Metal Single Pendant $28.46 $28.46 71 W LED (150 W BPS Equiv.)-OH-Metal Twin Pendant $23.94 $23.94 111 W LED(250 W BPS Equiv.)-OH-Metal Twin Pendant $26.60 $26.60 33 Phase 2 Effective:January 20,2022 Phase 3 Effective:January 20,2023 _ Street Lighting-and Area Lighting -s'7' y/ ✓ '' i'S'' ,F ems# p3cr `zfwr x+ + tYfykf.f�,�na493,� -�xp,', ' Yd7 .c '"r ae�, ... c. 278 W LED (400 W HPS Equiv.)-OH-Metal Twin Pendant $31.26 $31.26 71 W LED (150 W HPS Equiv.)-UG-Metal Twin Pendant $25.31 $25.31 111 W LED (250 W HPS Equiv.)-UG-Metal Twin Pendant $27.97 $27.97 278 W LED (400 W HPS Equiv.)-UG-Metal Twin Pendant $32.63 $32.63 111 W LED (250 W HPS Equiv.)-UG-Metal Decorative $45.54 $45.54 242 W LED(400 W HPS Equiv.)-UG-Metal Decorative $49.66 $49.66 * 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 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. 34 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.2 Phase 3 Facilities Charge $/Month $47.98 $71.99 Energy Charge $/kWh $0.09624 $0.09940 * 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. 35 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 2 Phase 3__ Facilities Charge $/Month $50.79 $50.79 Energy Charge: Tier 1 for the first 170 kWh or less used per month $/kWh $0.09855 $0.09855 Tier 2 for the next 30 kWh used per month $/kWh $0.09855 $0.09855 Tier 3 for the next 6,800 kWh used per month $/kWh $0.07883 $0.07883 Tier 4 for all over 7,000 kWh used per month $/kWh $0.07883 $0.07883 Demand Charge: Tier 1 for up to 30 kW $/kW $6.41 $6.41 Tier 2 for all over 30 kW used per month $/kW $6.41 $6.41 * 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 a suitable indicating or recording type meter. Where energy is delivered through more than one 36 Phase 2 Effective: January 20,2022 Phase 3 Effective: January 20,2023 • 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. 37 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 2 Phase 3 Energy Charge: $/kWh $0.18032 $0.21436 * 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 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 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 38 Phase 2 Effective: January 20, 2022 Phase 3 Effective: January 20,2023 • 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. 39 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 normal 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 40 Effective: January 20,2021 A 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). 41 Effective:January 20,2021 • M - r 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 42 Effective: January 20,2021 M f 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. 43 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% 44 Effective: January 20,2021 j T 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(ISS- COIN) Industrial Service Primary(ISP) Industrial Service Primary—Optional Coincident Peak(ISP-COIN) Transmission Service(TS) Transmission Service—Optional Coincident Peak(TS-COIN) 45 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 46 Effective: January 20, 2021 i 3 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 47 Effective: January 20, 2021 r a 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 attomey'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. 48 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". WITNES SETH: 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 49 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'sT 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 Utilityls'Tariff, or (c) the Generation Facilities interfere with the operation of Utility's electric systems/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 50 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 terms 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. 51 Effective: January 20, 2021 9. Termination 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 Majeure, 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 perform; 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. 52 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: 53 Effective: January 20,2021 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 54 Effective: January 20,2021 n p 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 PIM.These tests must be conducted for one hour on a .weekday between noon and 8. p.m., Eastern Prevailing Time, from June•l 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 IMPA,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 55 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) Finn 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 Finn 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). 56 Effective: January 20,2021 ib I, 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,EVIPA 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 57 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 CID 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 58 Effective: January 20,2021