The Public Utilities Article, Annotated Code of Maryland, provides that the Commission shall have the power to make such reasonable regulations as it deems necessary to carry out the provisions of this law and any other law relating to the Commission. Application. These regulations apply to any electric utility operating within the State, under the jurisdiction of the Public Service Commission. Purpose. These regulations are intended to promote safe and adequate service to the public, to provide standards for uniform and reasonable practices by utilities, and to outline the responsibility of the public in requesting and receiving service from the utilities. Exemption. If unreasonable hardship to a utility or to a customer results from the application of any of these regulations, application may be made to the Commission for the modification of the regulation or for temporary or permanent exemption from its requirements. Modification. The adoption of these regulations does not preclude the Commission from altering or amending them, or from making such modifications with respect to their application as may be found necessary to meet exceptional conditions. Duties Under Other Statutes. These regulations do not relieve any utility from any of its duties under the laws of this State. In this subtitle, the following terms have the meanings indicated. Terms Defined. “Abandoned call” means a telephone call in which the customer has elected to speak to a customer service representative but the call is terminated before the customer service representative answers. “All-in vegetation management cost” means all vegetation management capital and operation and maintenance expenditures, including: All direct contractual costs and internal staffing associated with yearly scheduled cyclical trimming and all corrective work; and All indirect costs associated with vegetation management staff, supplies, and equipment. Answer. “Answer” means rendering assistance to a telephone caller or accepting information necessary to process a telephone call by a customer service representative or an automated voice response system. “Answer” does not include an acknowledgement that a telephone caller is waiting on the line. “Baseline annual usage” means: The total of an eligible customer-generator’s previous 12 months of electric energy use in kilowatt hours at the time of the installation or upgrade of an eligible customer-generator’s generating system; or An estimate of 12 months electric use in kilowatt hours based on a methodology approved by the Commission for an eligible customer-generator that does not have 12 months of electric energy use in kilowatt hours at the time of the installation or upgrade of an eligible customer-generator’s generating system. “Billing period” means the period of time covered by a bill issued by an electric company. “Bordering jurisdiction” means the District of Columbia, Delaware, Pennsylvania, Virginia, and West Virginia. “Commission” means the Public Service Commission of Maryland. “Contact voltage” means a voltage condition that may result in an object or surface being inadvertently energized. “Contact voltage risk zone (CVRZ)” means the portions of each electric company’s service territory that: Are served by an underground electric distribution plant; and Have substantial pedestrian traffic or population density, whether permanent, seasonal or varying by time of day. “Contact voltage survey” means a survey performed by an electric company to detect contact voltage consistent with the company’s Commission-approved voltage survey plan. “Corrective maintenance” means maintenance performed to correct system equipment or component conditions that render them incapable of performing their designed function. “Critical facilities” means a utility-specific list of electric system customers essential for public health and safety requiring restoration priority as determined in consultation with State and local jurisdictions. “Cultural control practices” means control of vegetation through the establishment of compatible stable plant communities or the use of crops, pastures, mulching, or other managed landscapes. “Customer” means a person, partnership, association, corporation, or governmental agency being supplied with electric service by a utility. “Customer average interruption duration index (CAIDI)” means the system average interruption duration index (SAIDI) divided by the system average interruption frequency index (SAIFI). “Customers experiencing multiple interruptions (CEMIn)” means the ratio of individual customers experiencing n or more sustained interruptions to the total number of customers served. “Customer interruption hours” means an amount of time calculated by multiplying a sustained interruption duration by the total number of customers affected by the sustained interruption. “Distribution transformer” has the meaning stated in 10 CFR §431.192, as amended, which is incorporated by reference. “Electric company” has the meaning stated in Public Utilities Article, §1-101, Annotated Code of Maryland. “Electric distribution” plant means all electric company plant used to distribute electricity to its customers, including covers and protective structures and excluding customer meters and meter enclosures. “Electric plant” means a plant and property owned by an electric utility, used in its business operations of providing electric service to its customers. “Eligible customer-generator” has the meaning stated in Public Utilities Article, §7-306, Annotated Code of Maryland. Environmental surcharge means the charge in dollars and cents billed by an electric company under Public Utilities Article, §7-203, Annotated Code of Maryland. “Excess generation” means the amount of electricity produced by an eligible customer-generator that exceeds the electricity used by the eligible customer-generator in a monthly billing period. “Feeder” means an electric plant that emanates from a substation, serves customers, and is normally electrically isolated at all endpoints. “Global ETR” means a single estimated time for restoration for the entire service territory or the area of the service territory affected by the major outage event and should represent the time when at least 90 percent of all affected customers will have been restored. “Government emergency responder” means fire and police personnel and government employees who: Are working at the direction of fire, police, or 911 emergency dispatcher personnel to respond to an emergency; or Have been identified by fire, police, or 911 dispatcher personnel as responding to an emergency. “Hazard tree” means a structurally unsound tree or tree limb that could strike poles, substations, or energized overhead electric plant when it falls. “Institute of Electrical and Electronics Engineers (IEEE) major event day” means a day determined to be a major event day using the IEEE method of determining excludable data for calculation of reliability indices under IEEE Std 1366TM 2003. “Interruption duration” means the period of time, truncated or rounded to the nearest minute, during which a sustained interruption occurs. “Maintenance” means an inspection, diagnostics test, and or physical maintenance performed with the intent of assessing or predicting equipment failure before it occurs or improving equipment condition and thus preventing an equipment component or sub-component performance failure. “Major outage event” means an event when the following occurs: Before January 1, 2020: More than 10 percent or 100,000, whichever is less, of the electric utility’s Maryland customers experience a sustained interruption of electric service and restoration of electric service to any of these customers takes more than 24 hours; or The federal, State, or local government declares an official state of emergency in the utility’s service territory and the emergency involves interruption of electric service; or Beginning January 1, 2020: More than 10 percent or 100,000, whichever is less, of the electric utility’s Maryland customers experience a sustained interruption of electric service; and Restoration of electric service to any of these customers takes more than 24 hours. “Major outage event interruption data” means all electric customer interruption occurrence and duration information collected by the utility during a major outage event. “Mature tree” means a tree, whether or not previously pruned by the utility, that is well-established with a defined crown and that is at least 20 feet tall or 6 inches in diameter at breast height. Mature tree does not include a hazard tree. “Meter” means unless otherwise qualified, a device of the utility used in measuring watts, watt-hours, vars, var-hours, volt-amperes, or volt-ampere-hours. “Micro combined heat and power” has the meaning stated in Public Utilities Article, §7-306, Annotated Code of Maryland. “Momentary average interruption frequency index (MAIFIE)” means the ratio of the total number of customer momentary interruption events divided by the total number of customers served. Momentary Interruption. “Momentary interruption” means the loss of electric service of a duration limited to the time required to restore electric service by: Automatic or supervisory-controlled switching operations; or Manual switching at locations where an operator is immediately available. “Momentary interruption” does not include a loss of electric service which takes more than 5 minutes to restore. “Net energy metering” has the meaning stated in Public Utilities Article, §7-306, Annotated Code of Maryland. “Net Excess Generation” has the meaning stated in Public Utilities Article, §7-306, Annotated Code of Maryland. “Normal conditions” means conditions other than a major outage event. “Number of customer interruptions” means the number of customers without electric service during a sustained interruption. “Off right-of-way tree” means a tree or part of a tree where the utility does not typically perform routine tree trimming maintenance and may not have the rights to perform tree trimming to improve electric service reliability. “On right-of-way tree” means a tree or part of a tree where the utility typically performs routine tree trimming maintenance and may or may not have the rights to perform tree trimming to improve electric service reliability. “Operating district” means a distinct geographic area for which a cooperatively owned electric utility provides customer services from a decentralized office. Outside Assistance. “Outside assistance” means resources not routinely used by a utility for service restoration. “Outside assistance” does not include resources transferred among utility operating areas. “PJM” has the meaning stated in COMAR 20.52.01.02B. “Premises” means a tract of land or real estate, including buildings and other appurtenances on it. “Primary distribution system” means the alternating current distribution lines supplying the primaries of distribution transformers. “Protective devices” means substation breakers and reclosers, line reclosers, line sectionalizing equipment, and line fuses. “Resilience plan” means a plan or plans to prepare for and recover from pandemics, physical attacks, cyber attacks, electric supply shortages, weather events, significant infrastructure failures, and other credible disturbances with the potential to lead to large and widespread electric outages or loss of critical facilities essential for public health and safety. “Secondary distribution system” means the alternating current system which connects the secondaries of distribution transformers to the customers' services. “Sustained interruption” means the loss of electric service that is not classified as a momentary interruption. “System average interruption duration index (SAIDI)” has the meaning stated in Public Utilities Article, §7-213(a)(2), Annotated Code of Maryland. “System average interruption frequency index (SAIFI)” has the meaning stated in Public Utilities Article, §7-213(a)(3), Annotated Code of Maryland. “Test current” means the current marked on the nameplate of a watt-hour meter by the manufacturer (identified as “TA” on meters manufactured since 1960). This is the current in amperes which is used as the base for adjusting and determining the accuracy of a watt-hour meter at heavy and light loads. “Time-varying rate” means a base or commodity rate structure that includes more than one rate, each of which is applicable to a different time period during the billing cycle and excludes hourly priced rates for which the rate is derived from hourly energy costs from the PJM market. “Total number of customers served” means the number of customers provided with electric service by the distribution facility on the last day of the time period for which a reliability index is being calculated. “Utility” means an electric company as defined in Public Utilities Article, §1-101, Annotated Code of Maryland. ” Utility crew” means personnel and equipment routinely used by a utility for service restoration. “Voltage survey plan” means an electric company plan approved by the Commission governing the electric company’s contact voltage detection and testing equipment and voltage detection and testing procedures to be used when conducting contact voltage surveys. “Vulnerable individual” means a customer who is certified to the utility as having a serious illness or the need for life support pursuant to COMAR 20.31.03.01. “Zonal ETR” means the estimated time for restoration when at least 90 percent of all affected customers in the sub-area will have been restored to service. If an electric company itemizes the environmental surcharge on a customer's bill, the electric company shall bill the environmental surcharge to each customer as required by Public Utilities Article, §7-203, Annotated Code of Maryland. An electric company shall remit to the State Comptroller the amount equal to the environmental surcharge billed under §A of this regulation. When calculating the amount billed to a customer for the environmental surcharge in a billing period, an electric company shall follow the following rounding practices: If the amount calculated using the environmental surcharge rate and total kilowatt hour usage for the billing period results in an amount ending in $0.005 or greater, the amount shall be rounded up to the next whole cent; and If the amount calculated using the environmental surcharge rate and total kilowatt hour usage for the billing period results in an amount ending in less than $0.005, the amount shall be rounded down to the next whole cent. The Commission may waive a regulation in this subtitle for good cause shown. Public Utilities Article, §§2-113, 2-121, 5-101, 5-303, and 7-213, Annotated Code of Maryland Effective date: May 22, 1942 (Order No. 38330) Chapter revised effective May 18, 1960 (Order No. 54348) Chapter revised effective June 1, 1965 (Order No. 55819) Regulation .03 amended effective September 16, 2024 (51:18 Md. R. 810) Regulation .03B amended effective April 15, 2002 (29:7 Md. R. 622); July 2, 2007 (34:13 Md. R. 1152); September 21, 2009 (36:19 Md. R. 1438); November 28, 2011 (38:24 Md. R. 1503); February 20, 2012 (39:3 Md. R. 260); May 28, 2012 (39:10 Md. R. 661); December 2, 2019 (46:24 Md. R. 1104); August 21, 2023 (50:16 Md. R. 728); Regulation .04 adopted effective July 2, 2007 (34:13 Md. R. 1152) Regulation .05 adopted effective February 20, 2012 (39:3 Md. R. 260) The electric plant of the utility shall be constructed, installed, maintained, and operated in accordance with accepted good engineering practice in the electric industry to assure, as far as reasonably possible, continuity of service, uniformity in the quality of service furnished, and the safety of persons and property. Unless otherwise specified by the Commission, the utility shall use the applicable provisions in the latest revised version of the incorporated by reference publications listed below as standards of accepted good engineering practice in this subtitle: National Electrical Safety Code, ANSI C2 — 2017; National Electrical Code, ANSI/NFPA 70 — 2020; American National Standard for Electric Meters — Code for Electricity Metering, ANSI C12.1 — 2014; American Standard Requirements, Terminology and Test Code for Instrument Transformers, ANSI/IEEE C57.13 — 2016; Standard for Interconnection and Interoperability of Distributed Energy Resources with Associated Electric Power Systems Interfaces, IEEE 1547-2018; Standard for Interconnection and Interoperability of Distributed Energy Resources with Associated Electric Power Systems Interfaces, IEEE 1547-2018 Amendment 1 (IEEE Std. 1547a-2020); Errata to Standard for Interconnection and Interoperability of Distributed Energy Resources with Associated Electric Power Systems Interfaces, IEEE 1547-2018; IEEE 1547.1-2020, Standard Conformance Test Procedures for Equipment Interconnecting Distributed Energy Resources with Electric Power Systems and Associated Interfaces; UL Standard for Inverters, Converters, Controllers and Interconnection System Equipment for Use With Distributed Energy NEMA Standards Publication TP 1 — 2002; Guide for Electric Power Distribution Reliability Indices, IEEE Standard 1366 — 2003, 4.5 Major event day classifications; Institute of Electrical and Electronic Engineers Standard 1695 — 2016 — IEEE Guide to Understanding, Diagnosing, and Mitigating Stray and Contact Voltage; Interconnection Requirements for Onboard, Grid Support Inverter Systems, SAE J3072, Revision 3, June 10, 2024; Electric Vehicle Supply Equipment, UL 2594, Edition 3, December 15, 2022; and Electric Vehicle Power Export Equipment (EVPE), UL 9741, September 29, 2023. The generating capacity of the utility's plant, supplemented by the electric power regularly available from other sources, shall be sufficiently large to meet all normal demands for service and provide a reasonable reserve for emergencies. Each utility shall adopt written operation and maintenance procedures for its electric plant in order to determine the necessity for replacement and repair. The frequency of the various procedures shall be based on the utility's experience and accepted good practice. Each utility shall keep sufficient records to give evidence of compliance with its operation and maintenance procedures. When the National Electrical Safety Code and the National Electric Code, which are incorporated by reference in Regulation .02 of this chapter, call for different standards or requirements for installations that are under the exclusive control of the utility and located in legally established easements or rights-of-way, or located pursuant to agreements recognized by the Commission such as a utility tariff, the utility shall use the standard or requirement of the National Electrical Safety Code. Utilities shall maintain the vertical clearances of overhead electric supply lines that cross water surfaces suitable for sailboating in accordance with the values specified by Rule 232 of the National Electrical Safety Code. Scope. This regulation does not apply to an electric cooperative that supplies electricity to fewer than 60,000 electric meters in the State. Purchase of Liquid-Immersed Distribution Transformers. Beginning January 1, 2009, a utility shall use the life-cycle cost methodology contained in NEMA Standards Publication TP 1-2002, which is incorporated by reference under COMAR 20.50.02.02, when selecting any liquid-immersed distribution transformer for purchase. Evaluation of Distribution Transformer Models. Within each capacity class or type of liquid-immersed distribution transformer, a reasonable number of commercially available models shall be evaluated, and, except as provided §B(2)(b) of this regulation, a utility shall select for purchase the model in each capacity class or type with the lowest total owning costs as determined by the life-cycle cost methodology. If a utility is soliciting bids to supply multiple capacity classes or types of liquid-immersed distribution transformers under a single contract, models offered by a supplier in more than one capacity class or type may be combined for purposes of life-cycle cost evaluation. A utility shall select for purchase the aggregation of models offered by a supplier in the combined classes or types with the lowest total owning cost as determined by the life-cycle cost methodology in §B(2)(b) of this regulation. Under this section, a utility shall use: The values for load losses and no-load losses as determined by the “Uniform Test Method for Measuring the Energy Consumption of Distribution Transformers”, Appendix A to Subpart K of 10 CFR Part 431, as amended, which is incorporated by reference; and The estimated value of energy and capacity from the most current year available at the time of any bid solicitation. This regulation does not require a utility to purchase any liquid-immersed distribution transformer that fails to meet federal energy efficiency standards specified in 10 CFR Part 431, as amended, which is incorporated by reference. Each utility shall keep sufficient records to give evidence of compliance with this regulation. Public Utilities Article, §§2-113, 2-121, 5-101, 5-303, and 7-213, Annotated Code of Maryland Effective date: May 22, 1942 (Order No. 38330) Chapter revised effective May 18, 1960 (Order No. 54348) Chapter revised effective June 1, 1965 (Order No. 55819) Regulation .02 amended effective January 23, 1981 (8:2 Md. R. 117); March 27, 2006 (33:6 Md. R. 580); June 9, 2008 (35:8 Md. R. 808); September 21, 2009 (36:19 Md. R. 1438); May 28, 2012 (39:10 Md. R. 661); October 8, 2018 (45:20 Md. R. 920); March 20, 2023 (50:5 Md. R. 183); August 21, 2023 (50:16 Md. R. 728) Regulation .02K, L amended effective July 7, 2025 (52:13 Md. R. 657) Regulation .02M—O adopted effective July 7, 2025 (52:13 Md. R. 657) Regulation .04 amended effective April 15, 2002 (29:7 Md. R. 622); May 28, 2012 (39:10 Md. R. 661) Regulation .05 adopted effective March 27, 2006 (33:6 Md. R. 580) Regulation .05 amended effective June 9, 2008 (35:8 Md. R. 808) Regulation .06 adopted effective September 21, 2009 (36:19 Md. R. 1438) Regulation .06D adopted effective December 2, 2019 (46:24 Md. R. 1104) All records required by these regulations or necessary for the administration thereof shall be available for examination by the Commission or its authorized representatives. All records required by these regulations shall be preserved for the period of time specified in 18 CFR 125, as amended, which is incorporated by reference, unless otherwise specified by the Commission. Each utility shall file with the Commission a copy of its tariff which shall include: Rates. Each schedule of rates for service together with the applicable riders. Rules. The utility's rules, or terms and conditions, describing the utility's policies and practices in rendering service. These rules shall include: Extension Plan. The utility's plan for the installation of extensions of main and service lines where these facilities are in excess of those included in the regular rates for service and for which the customer shall be required to pay all or part of the cost. The customer's payments under this plan should be related to the investment that the utility prudently can make in consideration of the probable revenue. Voltages. A list of available voltages. Material Furnished by Utility. A list of the items which the utility furnishes, owns, and maintains on the customer's premises, such as meters, meter sockets, service entrances, etc. Billing Period. A statement indicating the minimum and maximum number of days for which the utility will bill a customer at its regular monthly rates for service. Payment Period. A statement indicating the minimum number of days allowed for payment of the gross amount of the customer's bill before service will be terminated for non-payment. Wastage of Electricity. A general statement of the utility's policy in making adjustments for wastage of electricity when an accidental ground exists without the knowledge of the customer. Special Contracts. Each utility shall file with the Commission a copy of each contract for service not covered by the utility's filed tariff. Installation Rules. Each utility shall file with the Commission a copy of the utility's rules, if any, designed by the utility for the use of engineers, architects, electrical contractors, etc., covering meter and service installations. Bill Forms. Each utility shall file with the Commission a sample of each type of customer bill form, which shall include the information normally shown on a customer's bill for service. Map of System. Each utility shall file with the Commission a map showing the utility's operating area. This map shall be revised annually unless the revision is unnecessary, in which event the utility shall notify the Commission that the map on file is current. If practicable, the map should show: Generating stations; Transmission lines with voltages; Primary distribution lines; State boundary crossings; and Territorial boundary. Persons to Contact. Each utility shall notify Commission staff, within 30 days of a change, of the name, title, address, telephone number, and email address of the person who should be contacted in connection with: General electric distribution management duties; Customer relations (complaints); Electric distribution operations; Electric distribution planning; Meter tests and repairs; Emergencies during non-office hours; Cybersecurity; and Regulatory contact for general inquiries. Fatal Accident Notice. In the event of a fatal accident, prompt notice shall be given to the Commission by telephone or email. Accident Notice. Each utility shall file with the Commission an “Accident Notice” report, on forms provided by the Commission, within 30 days after the end of any month during which an accident occurred. Line Support Identification. Each. Public Utilities Article, §§2-121, 4-202, 5-101, 5-302, and 6-203—6-210; State Government Article, §7-207(a); Annotated Code of Maryland Effective date: May 22, 1942 (Order No. 38330) Chapter revised effective May 18, 1960 (Order No. 54348) Chapter revised effective June 1, 1965 (Order No. 55819) Regulation .02 amended effective January 1, 1972 (Order No. 59734); March 12, 2007 (34:5 Md. R. 561) Regulation .04 amended effective September 21, 2009 (36:19 Md. R. 1438); December 2, 2019 (46:24 Md. R. 1104); August 21, 2023 (50:16 Md. R. 728) Regulation .04H amended effective September 18, 1989 (16:18 Md. R. 2024) System Maps or Records. Each utility shall maintain up-to-date maps, plans, or records of its entire transmission and distribution system, with such other information as may be necessary to enable the utility to advise prospective customers, and others entitled to the information, as to the facilities available for serving a locality. Selecting Rate Schedule. Each utility shall assist the customer or prospective customer in selecting the most economical rate schedule. Notifying Customers. Each utility shall notify customers affected by a change in rates or schedule classification. Tariff Notice. A utility shall post a notice in a conspicuous place in each office of the utility where applications for service are received, informing the public that a copy of its tariff, as filed with the Commission, is available for inspection. A utility shall post its tariff and pending tariff changes on its website. After Commission acceptance of a tariff change, a utility shall update the tariff posted on its website not later than 3 business days after the date of acceptance. Meter Reading Instruction. Upon request, each utility shall inform its customers as to the method of reading meters. Other Information. Each utility shall furnish such additional information as the customer may reasonably request. A utility may accept either written or verbal applications for service. Each verbal application for service shall be promptly confirmed in writing by the utility. A utility may require an applicant to sign and return a copy of the written confirmation. The application shall include the: Name, address, home and work telephone numbers, and employer of the customer of record; Address of the premises for which electric service is requested; Mailing address and telephone number of the customer of record if he is not an occupant of the premises for which service is requested; and Customer of record's former electric service address and the date customer moved, if applicable. A utility may require an applicant to sign and return a copy of the written confirmation before providing service. Upon request of the applicant, an electric utility shall accept more than one individual customer name on applications for service. All persons named on an account shall be customers of record. When the name of the person applying for service is different from the name of the applicant, when more than one name is to be on an account, or when there is a reasonable basis for questioning the authority of a person requesting service in the name of the applicant, the utility may request that the applicant or applicants appear at the utility's designated office, present satisfactory identification, and execute a written application for service. Customer Identification. A utility may require a customer to provide a written, signed statement attesting to an order, decree, or agreement formalizing a name change, but may not request a copy of the actual order, divorce decree, or separation agreement. Payment of Outstanding Bills. Except as prohibited by State or federal law, a utility may refuse to provide service for a former customer unless the customer has paid, or has made satisfactory arrangements to pay, any outstanding bill, or undisputed portion of a disputed bill, for prior residential service. A utility may not refuse service to a customer for nonpayment of an outstanding bill that is over 7 years old, unless the: Customer signed an agreement to pay the outstanding bill before the expiration of this period; or Outstanding bill is for service obtained by the customer in any manner described in COMAR 20.31.02.03D or COMAR 20.31.02.04A(1)—(4). Refusal to Connect Service. A utility may refuse to connect service if an attempt to secure service is made in any manner described below. If application is made: In a fictitious name; In the name of an individual who is not an occupant of the premises, without disclosure of the individual's actual address; In the name of a third party without disclosing that fact or without bona fide authority from the third party; Without disclosure of a material fact or by misrepresentation of a material fact; For connection of service to a residence where there are co-occupants, if a service account for that dwelling unit was previously maintained in a current co-occupant's name during a period of co-occupancy with the applicant and the co-occupant has failed to pay or make satisfactory arrangements to pay an outstanding bill or undisputed portion of a disputed bill for service at the dwelling unit, the collection of which is not barred under applicable State or federal law; For connection of service to a dwelling unit where there are co-occupants, if the service account of a prior dwelling unit of the applicant was listed in a current co-occupant's name and the co-occupant has failed to pay or to make satisfactory arrangement to pay an outstanding bill or undisputed portion of a disputed bill for service at the prior dwelling unit, the collection of which is not barred under applicable State or federal law; or By an individual for the purpose of assisting another occupant of a dwelling unit to avoid payment of that occupant's prior outstanding bill. For purposes of §B, “co-occupants” means two or more adults who occupy the same dwelling unit as their primary domicile, or legal residence within the State. For purposes of this regulation, a utility may provide service conditionally for not more than 30 days after the date of application. If, during this time, a utility discovers that an application has been made in one of the manners enumerated in this regulation, it may disconnect service in accordance with §§E and F. If a utility denies or disconnects service pursuant to this regulation, the utility shall notify the individual in writing of the reason for the denial or disconnection including the facts or circumstances upon which the utility bases its determination that service should be denied or disconnected. An individual who disputes the proposed denial or disconnection shall do so in accordance with the provisions of COMAR 20.32.01. The Commission’s Consumer Affairs Division may direct a utility to connect service, if deemed safe, in a customer’s name during the pendency of an investigation if a utility denies an application for service due to an unpaid arrearage for unauthorized use or tampering with equipment furnished and owned by the utility but does not provide the amount necessary to reconnect service within 3 business days of a filed complaint, provided that the applicant makes a payment to the utility: In an amount that represents 2/12 of the estimated charges for service for the ensuing 12 months; and Of any outstanding prior bill or in accordance with an alternate payment plan as described in COMAR 20.31.01.08 and agreed to by the utility. Each utility may require from a customer a deposit to be applied against any unpaid balance due the utility for service at the time service is terminated, in accordance with the provisions of Subtitle 30 of this title. The bill forms shall show: The readings of all meters used for billing purposes at the end of the period for which the bill is rendered; The meter reading date; The number and kind of units metered; The applicable rate schedule, including any seasonal or time differential in base rates for the billing period in which the differential is applicable, or identification of the applicable rate schedule; Any State or local surcharges; The applicable late payment charge, if any, separately stated or labelled a late payment charge, or a statement that the total amount due includes: A late payment charge, An explanation of the calculation, and The date of applicability of the late payment charge; The total due, including any prior unpaid amount but excluding the current late payment charge; The date by which the customer shall pay the bill in order to avoid a late payment charge; A distinct marking to identify an estimated bill; Information concerning the customer's electricity usage during the same billing period in the prior year; The utility's appropriate business address and telephone number for billing inquiries; and Any conversions from meter reading units to billing units, or any calculations to determine billing units from recording or other devices, and any other factors used in determining the bill. Rate Schedule. If the actual rates are not shown on the bill form as required in §A(4), the bill shall carry a statement to the effect that the applicable rate schedule, including the actual seasonal, or time differential, the fuel rate and the customer charge will be furnished on request. The Commission may, for good cause, grant a waiver or exemption from provisions in this regulation. A utility may request a waiver of exemption by filing an application with the Commission which sets forth the facts and reasons for the waiver or exemption. Retention of Records. The utility shall retain customer billing records for the length of time necessary to permit the utility to comply with Regulation .05, of this chapter, but not less than 3 years. Records For Demand Charge Customers. Records for customers whose billing includes a separate charge for a measured demand shall show: KWH meter reading; KWH consumption; KW meter reading; KW measured demand; KW billing demand; Net amount of the bill. Fast Meters. Whenever a meter is tested and found to have over-registered more than 2 percent, the utility shall recalculate the bills for service of the last customer of record receiving service through the meter and shall make a refund if the amount of the adjustment exceeds $1. The refund shall be for the period that the customer received service through the meter, but for not more than the periods established below: Known Date of Error. If the date on which the error first developed or occurred can be established, the bills for service shall be recalculated from that time. Unknown Date of Error. If the time at which the error first developed or occurred cannot be established, it shall be assumed that the over-registration existed for a period of 3 years or a period equal to one-half of the time since the meter was last tested, whichever is less. Slow Meters. Whenever a meter is found to be more than 2 percent slow, the utility may bill the customer one-half of the unbilled error for a period of 12 months, unless the meter has been tested within that 12-month period, in which event the utility may bill the customer one-half the unbilled error for the period since the meter was last tested. If the amount of under-registration is less than $5, the utility may not adjust the bill. Accuracy Calculation. Billing adjustments due to fast or slow meters shall be calculated on the basis that the meter should be 100 percent accurate. For watthour meters, the average accuracy shall be the arithmetic average of the percentage registration at light load and at heavy load, giving the heavy load registration a weight of 4. Overcharge—Undercharge Adjustment. When a customer has been overcharged or undercharged for services because of incorrect application of the rate schedule, incorrect calculation of charges, or other similar reasons, the amount of overcharge or undercharge adjustment shall be determined separately during the period of time the discrepancy occurred, in accordance with the following: Overcharge Adjustment. The total overcharge for the period the discrepancy occurred shall be refunded or credited to the customer, except for an overcharge resulting from an incorrect reading of the meter when the amount shall automatically be corrected in a subsequent billing based on the correct meter reading. Undercharge Adjustment. Unless authorized by the Commission, retroactive billing may not be for undercharging which occurred more than 12 months before the discovery of the error. A utility may seek the Commission's authorization for retroactive billing for undercharges which occurred more than 12 months but not more than 3 years before the discovery of the error if the customer knew, or reasonably should have known, that the bills were in error. The utility's request to the Commission shall be in writing and shall explain the factual basis for the request to the customer with a notice of the customer's right to write to the Commission, within 20 days, if the customer is in opposition to the request. If the total undercharge is more than 35 percent of the customer's average monthly bill during the preceding 3 months, the customer shall be allowed to enter into an installment plan to pay the total retroactive billing, without interest. In such a plan the monthly payments against the undercharge may not exceed 35 percent of the customer's average monthly bill during the preceding 3 months. However, if the installment plan will not recover within a 12-month period the total undercharge, the monthly payment may be equal to the total undercharge divided by 12 or a number greater than 12. Unless otherwise authorized by the Commission, the utility may deny service for nonpayment only for that portion of the undercharge applicable to the 4 months immediately before the discovery of the error. If requested by a customer, a utility shall provide means by which any undercharge may be paid in installments over a reasonable period of time, but not less than the same period in which any undercharges were incurred. Theft of Service. If a meter is found not to register, in whole or in part, due to tampering or interference with the company’s material, equipment, or facilities, the utility may issue an estimated bill. The company shall retain all information relied on to calculate the estimated bill for not less than 3 years or until the conclusion of a Commission investigation, whichever is longer. If local authorities require an inspection of a customer's wiring, the utility may not provide a customer with new or upgraded electric service until the inspecting authority certifies that the wiring conforms to the applicable code. The utility shall investigate promptly and thoroughly any complaint concerning its charges, practices, facilities, or service. The utility shall keep such records of customer complaints as will enable it to review and analyze its procedures and actions as an aid in rendering improved service. Public Utility Companies Article, §§2-113, 2-121, 4-202, 5-101, 7-203, and 7-305, Annotated Code of Maryland Effective date: May 22, 1942 (Order No. 38330) Chapter revised effective May 18, 1960 (Order No. 54348) Chapter revised effective June 1, 1965 (Order No. 55819) Regulation .01D amended effective September 21, 2009 (36:19 Md. R. 1438) Regulation .01-1 adopted effective November 18, 1985 (12:23 Md. R. 2224); amended effective July 28, 1986 (13:15 Md. R. 1736) Regulation .01-2 adopted effective April 21, 1986 (13:8 Md. R. 904); amended effective July 28, 1986 (13:15 Md. R. 1736) Regulation .01-2A amended effective May 10, 1993 (20:9 Md. R. 780) Regulation .01-2G adopted effective August 29, 2016 (43:17 Md. R. 957) Regulation .02 superseded effective May 28, 1970 (Order No. 58089, affecting residential customers) and October 20, 1978 (Order No. 63400, affecting all nonresidential customers) Regulation .02 amended effective January 23, 1981 (8:2 Md. R. 117) Regulation .03 amended effective November 18, 1985 (12:23 Md. R. 2224) Regulation .05 amended effective November 18, 1985 (12:23 Md. R. 2224); April 21, 1986 (13:8 Md. R. 904) Regulation .05A, B amended effective October 1, 1967 (Order No. 56893) Regulation .05F adopted effective August 29, 2016 (43:17 Md. R. 957) Regulations .06—.08 repealed effective October 14, 1991 (18:20 Md. R. 2200) Regulation .09 amended effective June 2, 1997 (24:11 Md. R. 794) Customer Use. All electricity sold by a utility shall be on the basis of meter measurement, except for installations where the usage is constant and the consumption may readily be computed, or as provided for in its filed rates. Utility Use. Wherever practicable, consumption of electricity within the utility itself, or by administrative units associated with it, shall be metered, except for installations where the usage is constant and the consumption may readily be computed. Condition. A meter may not be installed if it is mechanically or electrically defective, has incorrect constants, or has not been tested in accordance with the requirements of COMAR 20.50.02.02. Capacity. The capacity of the metering installation and the index mechanism should be consistent with the electrical requirements of the customer. If it is necessary to apply a multiplier to a meter reading, the multiplier shall be marked on the face of the meter register. Demand meter installations for billing purposes should be designed, where practicable, so that the highest annual demand reading used for billing should appear in the upper half of the meter's range. Meters shall be read at approximate monthly intervals, unless otherwise authorized by the Commission. The meter reading records from which bills are prepared shall show: Customer's name, address, and rate schedule; Identifying number or description of the meter; Meter readings; Date of meter reading; If the reading has been estimated; Any applicable multiplier or constant. Each utility shall maintain records of each meter and associated metering device which will identify each item as to its design, capacity, and application. The identifying information may include, as applicable: manufacturer, number, type, voltage, amperes, phase, number of wires, number of stators, disk constant (Kh), demand interval, and ratio. Each utility shall maintain records for each meter and associated metering device which shall show the dates of installation and removal from service, together with the location. Each utility shall maintain test records for each meter which shall include the following: The date and reason for the test; The reading of the meter before making the test; The accuracy “as found” at light and heavy loads; and The accuracy “as left” at light and heavy loads. Public Utility Companies Article, §§2-121, 5-101, 7-301, and 7-302, Annotated Code of Maryland Effective date: May 22, 1942 (Order No. 38330) Chapter revised effective May 18, 1960 (Order No. 54348) Chapter revised effective June 1, 1965 (Order No. 55819) Regulation .02A amended effective June 2, 1997 (24:11 Md. R. 795) Regulation .06 amended effective June 2, 1997 (24:11 Md. R. 795) Meter Shop. A utility shall maintain its own meter shop or use an outside meter shop, including one operated by a meter manufacturer, for testing, inspecting, or repairing a meter. A meter shop used by a utility for testing, inspecting, or repairing meters shall be approved by the Commission and be open for inspection upon request by an authorized representative of the Commission during normal business hours. Available Voltage. Each meter shop shall have a 3-phase voltage supply, one phase of which shall be variable from 0 volts to not less than 270 volts. Test Table. Each meter shop shall have a test table, test bench, or other facility which will serve as a mounting for the meter test equipment and for the meter or meters under test. Requirements. Each utility shall have the following standard watt-hour meters for the purposes indicated: Secondary Standard. Each utility shall have at least one portable secondary standard watt-hour meter to be used to check the accuracy of the working standard watt-hour meters. Working Standard. Each utility shall have at least one portable working standard watt-hour meter to be used to check the accuracy of watt-hour meters. Accuracy. Each portable secondary and working standard watt-hour meter shall have a correction of not more than 0.5 percent at commonly used loads. If the correction percentage varies between successive tests by more than 0.25, a complete check shall be made to determine the cause of the variation. If the cause of variation cannot be corrected, the use of the instrument should be discontinued. Calibration. The accuracy of the standard watt-hour meters shall be checked as indicated below: Secondary Standards. Secondary standards shall be checked at intervals not exceeding 12 months at the National Institute of Standards and Technology (NIST) or at a laboratory acceptable to the Commission. Working Standards. Working standards shall be checked at intervals not to exceed 12 months by comparison with a secondary standard in the utility's meter shop or other meter shop approved by the Commission. Certificates. Each standard shall be accompanied at all times by a certificate or calibration card, duly signed and dated, on which are recorded the corrections required to compensate for errors found at the customary test points at the time of the last previous test. Care In Handling. Extreme care shall be exercised in the use and handling of standards to assure that their accuracy is not disturbed. Procedure. The following procedures shall apply to the testing and adjusting of meters and associated devices: General. The test of any unit of metering equipment shall consist of a comparison of its accuracy with the accuracy of a standard. Adjusted to Zero. All meters and associated devices, when tested, shall be adjusted as closely as practicable to the condition of zero error. Use of Tolerances. All tolerances are to be interpreted as maximum permissible variations from the condition of zero error. In making adjustments, no advantage of the prescribed tolerance limits shall be taken. Creep. Meters may not creep, that is, there shall be no continuous rotation of the moving element of a meter at a speed in excess of one revolution in 5 minutes when the meter load wires have been removed and voltage is applied to the potential elements of the meter. Watt-Hour Meters. Watt-hour meters shall be tested at the loads and adjusted to the tolerances prescribed below: Shop Tests. Field Tests. Block Interval Demand Meters. Block interval demand meters shall be tested and adjusted as prescribed below: Test of Indicating Type. Demand meters shall be tested at a load point not less than 50 percent of full scale. However, they may be tested at a lower scale point if conditions warrant. Tests shall be continuous for at least one demand interval, or subinterval in the case of programmable demand register-equipped meters, and shall be started simultaneously with the demand interval of the demand meter. Test of Pulse-Operated Type. Demand meters which are actuated by pulses shall be tested by transmitting enough pulses to cause the meter to register at a load point not less than 50 percent of full scale. If a pulse actuated demand meter is equipped with a device which records the number of pulses received by the meter, and if there is frequent and accurate comparison of the record with the number of kilowatt hours registered on the associated watt-hour meter, then it is not necessary to make a periodic field test of the demand meter. Check of Pulse Devices. Pulse devices associated with demand meters shall be checked for proper operation. Accuracy. The demand meter shall have an accuracy of within 1 percent of full scale. Time Interval Accuracy. The total time interval, including reset time, shall be accurate within 0.5 percent, except that when a timing element also serves to keep a record of the time of day at which the demand occurs, it shall be adjusted if it is found to be in error by more than 2 minutes per day. Adjusted to Zero. Demand meters shall be adjusted to indicate zero under no-load conditions, and shall be checked to ascertain that the meter resets to zero. Lagged-Demand Meters. Lagged-demand meters shall be tested and adjusted as prescribed below: Test Points. Lagged-demand meters shall be tested initially at 50 and 90 percent of full scale. Subsequent tests shall be at not less than 50 percent of full scale. Accuracy. The lagged-demand meter shall have an accuracy within 2 percent of full scale. Time Interval Accuracy. The interval rating of lagged-demand meters shall be checked before installation, and the time required for the demand meter to reach 90 percent of final indication, with a constant load suddenly applied, may not vary from the rated demand interval by more than 2 percent. Adjusted to Zero. Lagged-demand meters shall be adjusted to indicate zero under no-load conditions. Instrument Transformers. The following procedures and requirements shall apply to instrument transformers used for billing purposes: Standard for Testing. Unless otherwise specified by the Commission, all current and potential transformers shall be tested in accordance with the procedures prescribed in American Standard Requirements, Terminology and Test Code for Instrument Transformers, ANSI C57.13. Test Facilities. Any utility unable to perform the above test due to a lack of proper equipment may have its instrument transformers tested by another utility or approved meter shop whose testing equipment conforms to the requirements of the Commission. Test. In lieu of utility testing of instrument transformers, the Commission will accept the certificate of test as furnished by the manufacturer. Accuracy. Current or potential transformers may not be installed if their accuracy does not fall within the 0.6 accuracy class as defined in ANSI C57.13. Meters For Measurement of Purchased Electricity. Utilities purchasing electricity from non-utilities or from utilities outside the State shall see that the instruments and meters which are necessary to furnish complete and accurate information as to the energy purchased are installed and tested in accordance with the requirements of the Commission. Authorization by Commission. A meter may be installed for use for revenue-billing purposes if it meets the following conditions: Approved Type. Its type and design meet the requirements of COMAR 20.50.02.02. Accuracy. The registration of the meter is within the tolerances specified in Regulation .03 of this chapter. A representative of the Commission will check the condition of meters in the meter shop of the utility from time to time by testing random samples of meters ready for installation. Test Required. Each meter and associated metering device shall be inspected and tested in the meter shop of the utility, or sample tested by the utility if 100 percent tested by the manufacturer, before being placed in service, except for instrument transformers tested in accordance with Regulation .03E(3) of this chapter. Reinstallation. When a meter is removed from service, it shall be adjusted if necessary in order to conform to the accuracy tolerances specified in Regulation .03 of this chapter before being placed in service again. However, it may be retired without test or returned to service without being tested if it is covered by an in-service sample or periodic test plan. Post-installation inspections on new or upgraded service installations which incorporate instrument transformers to determine proper operation and wiring connections shall be made within 60 days after installation by a qualified person who shall be someone other than the original installer. Request For Test. Upon request by a customer and at no charge, the utility shall test the accuracy of the meter serving the customer. A utility may not perform a customer-requested meter test more than once during an 18-month period. A customer-requested test may be performed at: The metering location; The utility's meter shop; or An approved meter shop. Customer May Observe. The customer, or his representative, may be present when the meter is tested. Report to Customer. A report of the results of the test shall be made to the customer within a reasonable time after the completion of the test, and a record of the report, together with a complete record of the test, shall be kept on file at the office of the utility for at least 3 years. Application for Test. Upon written application to the Commission by a customer or a utility, a test will be made of the customer's meter as soon as practicable by a representative of the Commission. Deposit for Test. The application shall be accompanied by a deposit as indicated below: Watt-hour meter --------------------------------------------- $10; Combination watt-hour and demand meter -------------- $20. Notice to Utility. On receipt of the request from a customer, the Commission will notify the utility and the utility may not knowingly remove or adjust the meter until instructed by the Commission. The utility shall furnish to the Commission's representative such reasonable assistance as may be required to make the test. Customer May Observe. The customer, or his representative, may be present when the meter is tested. Report to Customer. A written report of the results of the test will be sent to the customer and to the utility. Disposition of Deposit. If the meter is found to over-register more than 2 percent, calculated in accordance with COMAR 20.50.04.05C, the deposit shall be refunded by the Commission and the utility billed the amount of the deposit. If the meter is found to be not more than 2 percent fast, the deposit will be retained and disposed of according to law. Each meter shall be tested before the meter is adjusted or repaired. Test Program. In-service performance tests shall be made in accordance with the requirements of COMAR 20.50.02.02. Location of Tests. In-service performance tests may be made on the customer's premises, in the utility's meter shop, or in an approved meter shop. Tests for Other Purposes. Tests, such as request or referee tests, which are made for purposes other than to determine the in-service performance of a group of meters, may not be counted as in-service performance tests, except for those groups of meters being tested under the Periodic Test Schedule. Periodic Test Schedule. Periodic tests shall be scheduled in accordance with the requirements of COMAR 20.50.02.02. Preinstallation Test. All instrument transformers used for billing purposes shall conform to the requirements of Regulation .03E of this chapter before being placed in service. Current Transformers. Current transformers should be tested with a suitable variable burden device to determine if the windings of the secondary circuit have developed an open circuit, short circuit, or unwanted grounds. Potential Transformers. Potential transformers should be tested by measuring the secondary voltage to reveal defects in the transformer or secondary circuit which appreciably affect accuracies. Performance Test. If there is any evidence that an instrument transformer is inaccurate or has been damaged to the extent that its performance has been impaired, it shall be tested to determine whether it should be replaced. Generator output watt meters and watt-hour meters in the utility's generating station shall be tested according to a suitable schedule by comparison with the utility's standards but may not exceed the appropriate test intervals as required under COMAR 20.50.02.02. Public Utilities Article, §§2-121, 5-101, 7-301, and 7-302, Annotated Code of Maryland Effective date: May 22, 1942 (Order No. 38330) Chapter revised effective May 18, 1960 (Order No. 54348) Chapter revised effective June 1, 1965 (Order No. 55819) Regulations .04A and .07F amended effective October 1, 1967 (Order No. 56893) Regulation .04 amended effective January 23, 1981 (8:2 Md. R. 117) Regulation .07B amended effective September 2, 1991 (18:17 Md. R. 1921) Chapter revised effective June 2, 1997 (24:11 Md. R. 795) The standard frequency for alternating current distribution systems shall be either 60 cycles per second or 25 cycles per second. Secondary Voltages. The voltage at the utility's service terminals, as installed for each customer, shall be maintained within the Limits specified in the table below. If a utility adopts any standard voltage not included in the table, it shall advise the Commission in order that the Commission may establish appropriate voltage limits. When 3-phase service is provided, the utility shall exercise reasonable care to assure that the phase voltages are balanced. Primary Voltages. The following limits shall apply where the utility supplies service at primary voltage: Industrial Customers. For service rendered principally for industrial or power purposes, the voltage may not exceed 7-1/2 percent above or 7-1/2 percent below the standard nominal voltages as filed in the utility's rules. Sales For Resale. For service rendered to public utilities and others for resale, the nominal voltage shall be as mutually agreed upon by the parties concerned. The allowable voltage may not exceed 7-1/2 percent above or 7-1/2 percent below the agreed upon nominal voltage without the express approval of the Commission. Special Contract Exceptions. The limitations in §§B(1) and B(2), of this regulation, do not apply to special contracts in which the customer specifically agrees to accept service with unregulated voltage. Exceptions to Voltage Requirements. It will not be considered a violation when voltages outside of the prescribed limits are caused by any of the following: Action of the elements; Service interruptions; Temporary separation of parts of the system from the main system; Infrequent fluctuations not exceeding 5 minutes' duration; or Other causes beyond the control of the utility. Requirements. Each utility shall have the following voltmeters for the purposes indicated: Secondary Standard. Each utility shall have at least one secondary standard indicating voltmeter to be used in checking the accuracy of working standard voltmeters. Working Standards. Each utility shall have at least two working standard indicating voltmeters to be used in checking the voltage on the utility's electric system and in checking the accuracy of recording voltmeters. Recording Voltmeters. Each utility shall have at least two portable recording voltmeters to be used to record the voltage on the utility's electric system. Accuracy. The voltmeters shall be of sufficient quality to meet the accuracy standards prescribed below: Secondary Standard. The secondary standard indicating voltmeter shall have a stated accuracy within 0.25 percent of full scale. This instrument shall be maintained within its stated accuracy. Working Standards. The working standard indicating voltmeters shall have a stated accuracy within 0.75 percent of full scale. Recording Voltmeters. The portable recording voltmeters shall have a stated accuracy within 1.5 percent of full scale. Calibration. The accuracy of the voltmeters shall be checked as indicated below: Secondary Standard. Secondary standards shall be checked at intervals not exceeding 3 years at the National Bureau of Standards, or at a laboratory acceptable to the Commission. Working Standards. Working standards shall be checked at intervals not exceeding 3 years by comparison with a secondary standard in the utility's meter shop. Certificates. Each standard shall be accompanied at all times by a certificate or calibration card, duly signed and dated, on which are recorded the corrections required to compensate for errors found at the customary test points at the time of the last calibration test. Care In Handling. Extreme care shall be exercised in the handling of standards and other instruments to assure that their accuracy is not disturbed. Voltage Surveys. Each utility shall make voltage measurements, using recording voltmeters, in order to determine if voltages are in compliance with the requirements contained in Regulation .02. Point of Measurement. Voltage measurements shall be made at the utility's service terminals. For single phase service, the measurement shall be made between the grounded conductor and the ungrounded conductors. For 3 phase service, the measurement shall be made between the phase wires. Voltage Records. All voltmeter records obtained under §A, above, shall be retained by the utility for at least 2 years and shall be available for inspection by the Commission's representatives. Notations on each chart shall indicate the following: Location where the voltage was taken; Time and date of the test; Results of the comparison of the recording voltmeter with an indicating voltmeter. Record of Corrective Action. If action is taken to correct the voltage conditions, the chart which records the voltage subsequent to the change shall be attached to the first chart so that the conditions before and after the change may be reviewed. Endeavor to Avoid Interruptions. Each utility shall make reasonable efforts to avoid interruptions of service, but when interruptions occur, service shall be re-established within the shortest time practicable, consistent with safety. Report to Commission. Each utility shall promptly report to the Commission's Engineering Division and Consumer Affairs Division: The onset of a major outage event; A sustained interruption, to firm-service customers, initiated by the utility in response to unacceptable system voltages; and A sustained interruption, to firm-service customers, initiated by the utility in response to thermal overloads of electric plant. The utility's report required by §B(1) of this regulation shall include a general description of the areas experiencing a sustained interruption and the expected system restoration times, if available. The utility making the report required by §B(1) of this regulation shall also provide periodic updates to the Consumer Affairs Division. Planned Interruptions. Planned interruptions shall be made at a time that will not cause unreasonable inconvenience to customers and shall be preceded, if feasible, by adequate notice to those who will be affected. Record of Interruptions. Each utility shall keep records of interruptions of service on its primary distribution system and shall make an analysis of the records for the purpose of determining steps to be taken to prevent recurrence of the interruptions. The records should include the following information concerning the interruptions: Cause; Date and time; and Duration. Momentary Interruption Record. A utility shall maintain information which it collects on momentary interruptions for 5 years. Unattended Substations. The record for each unattended substation shall show interruptions which required attention to restore service, with the estimated time of interruption. Public Utilities Article, §§2-121, 5-101, and 5-303, Annotated Code of Maryland Effective date: May 22, 1942 (Order No. 38330) Chapter revised effective May 18, 1960 (Order No. 54348) Chapter revised effective June 1, 1965 (Order No. 55819) Regulation .03C amended effective June 6, 2005 (32:11 Md. R. 983) Regulation .05 amended effective April 15, 2002 (29:7 Md. R. 622) Regulation .05B amended effective May 28, 2012 (39:10 Md. R. 661) Regulation .06 adopted effective April 15, 2002 (29:7 Md. R. 622) Regulation .06 repealed effective May 28, 2012 (39:10 Md. R. 661) Regulation .07 adopted effective April 15, 2002 (29:7 Md. R. 622) Regulation .07 repealed effective May 28, 2012 (39:10 Md. R. 661) Exercise Reasonable Care. Each utility shall exercise reasonable care to reduce the hazards to which its employees, its customers, and the general public may be subjected. Investigation by Commission. The utility shall give reasonable assistance to the Commission in the investigation of the cause of accidents and in the determination of suitable means of preventing accidents. Record of Accidents. Each utility shall maintain a summary of all reportable accidents arising from its operations. Adopt Safety Program. Each utility shall adopt and execute a safety program, fitted to the size and type of its operations. Use Suitable Tools and Equipment. Each utility should require its employees to use suitable tools and equipment in order that they may perform their work in a safe manner. Promote Safe Work Methods. Each utility should instruct its employees in safe methods of performing their work. Instruct In Artificial Respiration. Each utility should instruct its employees who, in the course of their work, are subject to the hazard of electrical shock or drowning, in accepted methods of artificial respiration. Standard Codes. Each utility shall use the applicable provisions in the National Electrical Safety Code and the National Electrical Code, which have been incorporated by reference in COMAR 20.50.02.02, for the grounding of secondary circuits and equipment. Testing Grounds. Artificial grounds not connected to a multigrounded system shall be tested for ground resistance at the time of installation. Records of Tests. Records shall be kept of all ground resistance tests made in accordance with §B, above. Inspection of Grounds. The utility shall establish a program of inspection to insure that artificial grounds are in good mechanical and electrical condition. State Government Article, §7-207; Public Utilities Article, §§2-113, 2-121, 5-101, 5-303, and 5-304; Annotated Code of Maryland Effective date: May 22, 1942 (Order No. 38330) Chapter revised effective May 18, 1960 (Order No. 54348) Chapter revised effective June 1, 1965 (Order No. 55819) Regulation .03A amended effective March 12, 2007 (34:5 Md. R. 562) This chapter applies to a small generator facility seeking to interconnect and operate in parallel with the electric distribution system. All small generator facilities shall interconnect under requirements in this chapter or under the physical interconnection requirements of the PJM Interconnection, LLC under the authority of FERC. A small generator facility seeking to interconnect and operate in parallel with the electric distribution system under this chapter shall meet one of the following criteria: The small generator facility is a qualifying facility pursuant to the Public Utility Regulatory Policies Act that intends to make sales at a rate approved by the Maryland Commission; The small generator facility is not a qualifying facility pursuant to the Public Utility Regulatory Policies Act and does not intend to make sales of wholesale electric energy through the PJM Interconnection, LLC; The small generator facility intends to make sales of wholesale electric energy through the PJM Interconnection, LLC at an electric distribution interconnection facility where there has been no prior FERC jurisdictional service; The small generator facility intends to make sales of wholesale electric energy through the PJM Interconnection, LLC only at an electric distribution interconnection facility through participation in a distributed energy resource aggregation; or The small generator facility will be interconnected to an electric distribution circuit and its energy will not be transmitted across state lines for a wholesale customer other than the electric distribution owner. Market processes under FERC jurisdiction that are administered by the PJM Interconnection, LLC may not impede the interconnection timeline requirements in this chapter unless the utility has good cause to believe that equipment upgrades exceeding minor equipment modifications and related modifications to the interconnection agreement will be needed to facilitate these market processes. In these cases, the utility shall notify the interconnection customer in writing of their rationale to delay approval of the interconnection request until the conclusion of the PJM Interconnection, LLC's market process study. In situations where an interconnected small generator facility project intends to change their energy sales strategy from market processes under FERC jurisdiction to retail processes under this chapter, the small generator facility shall submit an interconnection request. In this chapter, the following terms have the meanings indicated. Terms Defined. “AC EVSE” means supply equipment that passes alternating current to the EV with conversion between AC and DC accomplished onboard the EV. “Adverse system impact” means a negative effect, due to technical or operational limits on conductors or equipment being exceeded, that may compromise the safety or reliability of the electric distribution system. “Affected system” means a utility electric system that is affected by the interconnection of a small generator facility to another utility’s electric distribution system. “Aggregate generation” means the aggregated net system capacities of all small generator facilities across multiple points of common coupling. “Applicant” means a person who has submitted an interconnection request to interconnect a small generator facility to a utility's electric distribution system. “Area network” means a type of electric distribution system served by multiple transformers interconnected in an electrical network circuit, often used in large, densely populated metropolitan areas. “Bidirectional electric vehicle” has the meaning stated in Public Utilities Article, §7-1001(c), Annotated Code of Maryland. “Certificate of completion” means a certificate provided by a utility to an applicant containing information about the interconnection equipment used, its installation, and local inspections. “Closed circuit” means an electric distribution system circuit with no available hosting capacity. “Commissioning test” means one of several tests applied to a small generator facility by the applicant after construction is completed to verify that the small generator facility does not create adverse system impacts, including the test specified in Section 5.4 of IEEE Standard 1547. “DC EVSE” means supply equipment that passes direct current to or from the EV, with the EVSE accomplishing conversion between AC and DC. “Default utility required inverter settings profile” means a utility set of default smart inverter settings optimized for use across a utility’s service territory. “Distributed energy resource” means any geographically dispersed energy resource located on an electric distribution system that produces electricity or offsets electrical demand including small generator facilities, energy storage devices, energy efficiency devices, and demand response devices. “Distribution upgrade” means a required addition or modification to the utility electric distribution system, excluding the interconnection facilities, necessary to accommodate the interconnection of a small generator facility. “Draw-out type circuit breaker” means a molded case switching device that: Can be inserted into or removed from its enclosure during no-load conditions; and Is capable of making, carrying, and breaking currents under normal and abnormal circuit conditions. Electric Distribution System. “Electric distribution system” means the facilities and equipment used to transmit electricity generally at less than 69 kV to ultimate usage points such as homes and industries from interchanges with higher voltage transmission networks that transport bulk power over longer distances. “Electric distribution system” has the same meaning as the term Area EPS as defined in Section 3.1.6.1 of IEEE Standard 1547. “Electric vehicle” or “EV” means a vehicle that employs electrical energy as a primary or secondary mode of propulsion and is capable of charging the onboard battery from an external supply of electricity. “Electric vehicle supply equipment” or “EVSE” means a device or system designed and used specifically to transfer electrical energy between an electric vehicle and the electric grid. “Energy Storage Device” means a piece of equipment that captures energy produced at one time, stores that energy for a period of time, and delivers that energy as electricity at a future time. “Fault current” means the electrical current that flows through a circuit during an electrical fault condition, such as when one or more electrical conductors contact ground or each other. “Grid support services” means compensated or uncompensated services unrelated to wholesale markets provided by a small generator facility that support the safety, stability, reliability, or economics of the electric grid. “Hosting capacity” means the amount of aggregate generation that can be accommodated on an electric distribution system or area, or a system component, without requiring infrastructure upgrades. “Hosting capacity reporting system” means the information available on a utility website providing reports, tabular data, or maps of hosting capacity available on the electric distribution system. “Hosting capacity upgrade plan” means a utility plan to promote clean energy interconnection for a particular area or a proposal to open multiple restricted and closed circuits or areas on an electric system in the aggregate through proactive distribution system investments that includes a cost allocation and recovery proposal, under conditions that are approved by the Commission. “IEEE Standard 1547” means the standard incorporated by reference in COMAR 20.50.02.02. “IEEE Standard 1547.1” means the standard incorporated by reference in COMAR 20.50.02.02. “Inadvertent export” means the unscheduled export of power from a small generator facility, beyond a specified magnitude and for a limited duration, generally due to fluctuations in load-following behavior. “Interconnection agreement” means an agreement that contains details regarding the proposed interconnection equipment and its operation to ensure the reliability and safety of the grid, including schedules, rights, obligations, and terms and conditions that become effective on the date the agreement is executed by the utility and the interconnection customer. “Interconnection customer” means an entity that proposes to interconnect or has interconnected a small generator facility to an electric distribution system. Interconnection Equipment. “Interconnection equipment” means a group of components or an integrated system connecting an electric generator with a local electric power system, or an electric distribution system. “Interconnection equipment” means all interface equipment including switchgear, protective devices, inverters, or other interface devices. “Interconnection equipment” includes equipment installed as part of an integrated equipment package that includes a generator or other electric source. Interconnection Facilities. “Interconnection facilities” means facilities and equipment required by the utility to accommodate the interconnection of a small generator facility. “Interconnection facilities” includes all facilities and equipment between the small generator facility and the point of interconnection, and modifications, additions, or upgrades that are necessary to physically and electrically interconnect the small generator facility to the electric distribution system. “Interconnection facilities” includes any distribution upgrade. “Interconnection facility cost sharing” means the allocation of distribution interconnection facility upgrade costs among multiple small generator facility projects that utilize the hosting capacity created by an interconnection facility upgrade. “Interconnection request” means an applicant's request for the interconnection of a small generator facility, or to increase the capacity or operating characteristics of a small generator facility that is already interconnected with the utility's electric distribution system. “Interconnection study” means an interconnection feasibility study, interconnection system impact study, or interconnection facilities study as described in Regulation .12 of this chapter. “Limited export agreement” means an agreement for energy supplied to the grid by an interconnection customer that may be managed to specified ramp rates and generation levels for operating conditions, as specified in the interconnection agreement or in a separate limited export agreement. “Line section” means that portion of a utility electric distribution system connected to an interconnection customer, bounded by automatic sectionalizing devices, or the end of the distribution line. Local Electric Power System. “Local electric power system” means those facilities that deliver electric power to a load that are contained entirely within a single premises or group of premises. “Local electric power system” has the same meaning as the term local electric power system as defined in Section 3.1.6.2 of IEEE Standard 1547. “Meter collar adapter” means an electronic device that is installed between a residential electric meter and the meter socket, for the purpose of facilitating the deployment of customer-owned or customer-leased technology. “Minor equipment modification” means a change to the proposed small generator facility that does not have a significant impact on safety or reliability of the electric distribution system. “Minor system modification” means a change to the distribution system: Located between the service tap on the distribution circuit and the meter serving the applicant; or That the utility estimates will entail less than 4 hours of work and less than $1,500 in materials. “Nameplate capacity” means the maximum rated output of a generator at a point of common coupling of all electric power production equipment or energy storage devices under specific conditions designated by the manufacturer that is usually listed on a nameplate physically attached to the equipment. “Nationally recognized testing laboratory (NRTL)” means a qualified private organization recognized by the Occupational Safety and Health Administration to perform independent safety testing and product certification. “Net system capacity” means the total export capacity at a point of common coupling of a small generator facility as measured by the nameplate capacities of all power production units and energy storage devices minus their consumption of electrical power, if applicable, as limited through the use of a control system, power relays, or other similar device settings or adjustments. “Parallel operation” means the sustained state of operation over 100 milliseconds which occurs when a small generator facility is connected electrically to the electric distribution system, and thus has the ability for electricity to flow from the small generator facility to the electric distribution system. “Permission to operate notice” means the written permission provided by a utility in the form of an email or letter authorizing an interconnection customer to interconnect and operate its small generator interconnection facility. “Point of common coupling” means the point of interconnection where the small generator facility is electrically connected to the electric distribution system. “Point of interconnection” has the same meaning as the term “point of common coupling”. “Primary line” means a distribution line rated at greater than 600 volts. “Primary voltage hosting capacity upgrade cost” means the equipment upgrade costs of all interconnection equipment, interconnection facilities, protective devices and associated communications systems, and other upgrades that directly increase hosting capacity for multiple primary voltage and secondary voltage interconnection customers while excluding equipment upgrade costs that solely benefit a single interconnection customer, to the extent practicable and material. “Primary voltage interconnection customer” means an interconnection customer with a point of interconnection at greater than 600 nominal volts. Proposed Use. “Proposed use” means the operational control modes of a small generator facility upon which the applicant’s technical review is based and under which the small generator facility is bound to operate upon the execution of the interconnection agreement. “Proposed use” for a small generator facility includes a combination of electric generators and energy storage devices operating in specified operational control modes during specified time periods. “Queue position” means the order of a completed interconnection request, relative to all other pending completed interconnection requests, that is established based upon the date and time of receipt of the completed interconnection request by the utility. “Radial distribution circuit” means a circuit configuration in which independent feeders branch out radially from a common source of supply. “Reserve hosting capacity” means the amount of hosting capacity reserved for small generator facilities on an electric distribution system circuit. “Restricted circuit” means an electric system distribution circuit with reserve hosting capacity. “Rightsizing” means to increase the size, scope, and cost of an electric utility hosting capacity upgrade project, following a distributed energy resource interconnection request, to account for both the immediate interconnection customer’s needs and future hosting capacity needs that are identified by the electric utility through a distributed energy resource forecast. “Scoping meeting” means a meeting between the applicant and utility conducted for the purpose of discussing alternative interconnection options, exchanging information, including any electric distribution system data and earlier study evaluations that would be reasonably expected to impact interconnection options, analyzing information, and determining the potential feasible points of interconnection. “Secondary line” means a service line subsequent to the primary line that is rated for 600 volts or less, also referred to as the customer's service line. “Secondary voltage hosting capacity upgrade cost” means the costs of all primary voltage and secondary voltage interconnection equipment upgrades that directly increase secondary voltage hosting capacity available to multiple secondary voltage interconnection customers while excluding all primary voltage and secondary voltage interconnection equipment upgrade costs that solely benefit a single interconnection customer, to the extent practicable and material. “Secondary voltage interconnection customer” means an interconnection customer with a point of interconnection at less than or equal to 600 nominal volts. “Shared transformer" means a transformer that supplies secondary source voltage to more than one customer. “Site-specific utility required inverter settings profile” means a set of smart inverter settings optimized for use at a specific site on a utility’s electric system. Small Generator Facility. “Small generator facility” means the equipment used to generate or store electricity that operates in parallel with the electric distribution system. “Small generator facility” includes an electric generator, a prime mover, energy storage device, and the interconnection equipment required to safely interconnect with the electric distribution system or local electric power system. “Smart Inverter” means any inverter hardware system certified to be compliant with IEEE 1547-2018 or subsequent revisions to these standards. Spot Network. “Spot network” means a type of electric distribution system that uses two or more inter-tied transformers to supply an electrical network circuit. “Spot network” is generally used to supply power to a single customer or a small group of customers. “Spot network” has the same meaning as the term is defined in 4.1.4 of IEEE Standard 1547. “Statewide utility required inverter settings profile” or “grid code” means a set of smart inverter settings optimized for use Statewide that can be used by utilities and manufacturers in establishing defaults. “Technical interconnection requirement” or “TIR” means a public-facing document available on an electric company's website that specifies interconnection technical review criteria and distributed energy resource functional settings. “Utility monitoring and control plan” means a plan to monitor and control, in the aggregate, a set of small generator facilities in multiple locations that includes a cost recovery method, under conditions that are approved by the Commission. “Utility required inverter settings profile” means smart inverter settings for a small generator facility that are established by a utility. “V1G or managed charging” means a range of approaches from utility programs and rate design to incentivize ratepayers for varying the time or rate at which an electric vehicle is charged. “V1G Ready EVSE” is an EVSE that is capable of controlled charging rate operation but is either not certified for or is certified for but not programmed or configured for bidirectional operation. “V2G or vehicle-to-grid” means the ability for an EVSE connected to a bidirectional electric vehicle to operate in parallel to the grid and both receive and feed power to the point of interconnection between the EVSE and the grid. “V2G Ready EVSE” is an AC EVSE or DC EVSE, is certified for and programmed or configured for bidirectional operation as part of a V2G system in parallel with the electric grid. “V2G System” is a combination of hardware and software in or around the EVSE and EV for the purposes of communication with and programmed flow of energy into and out of the vehicle battery in support of electrical loads or systems offboard the EV, including the electric grid. “Witness test” means, for lab-certified or field-approved equipment, verification either by an on-site observation or review of documents by the utility that the interconnection installation evaluation required by Section 5.3 of IEEE Standard 1547 and the commissioning test required by Section 5.4 of IEEE Standard 1547 have been adequately performed. The technical standard to be used in evaluating all interconnection requests under Level 1, Level 2, Level 3, and Level 4 reviews, unless otherwise provided for in this chapter, is IEEE Standard 1547. Applicants seeking to interconnect a small generator facility shall submit an interconnection request to the utility that owns the electric distribution system to which interconnection is sought. An interconnection request shall be in the form and format specified by the utility that owns the electric distribution system to which interconnection is sought and shall include the following information and any additional information that may be reasonably requested by the utility: Contact information for the interconnection customer; Existing utility account information; Location information for the small generator facility; Contact information for the interconnection customer’s equipment and electrical contractors; Information on the manner in which the interconnection customer intends to use the small generator facility; Requested review level for interconnection request; Technical information regarding the generator and prime mover; Technical information regarding the interconnection components and system or systems; Location and other information regarding disconnect switch for small generator facility; Details regarding any plans to export power to the electric distribution system; and Any other item specified by the Commission. Each utility shall make reasonable efforts to align the content of its interconnection request form with those forms provided by other utilities in Maryland. Each utility shall establish a process that allows an applicant and an applicant’s authorized designee to: Sign and submit an interconnection request electronically on the utility’s website; Track the status of the interconnection request electronically; and Conduct electronically any other process that can reasonably occur in that manner. A utility may only charge a small generator interconnection request fee for a Level 2, Level 3, or Level 4 interconnection request. A utility may not charge interconnection request fees for interconnection requests determined to be under PJM Interconnection, LLC jurisdiction pursuant to Regulation .01 of this chapter. The utility shall specify the interconnection [processing] request fees charged under this regulation in its tariff. For small generator facilities at a site for which the applicant seeks a single point of interconnection, the interconnection request shall be evaluated for total exports on the basis of the net system capacity. An interconnection request is required for the interconnection of a new small generator facility, or to increase the total exports, change the energy sales strategy pursuant to Regulation .01C of this chapter, or change the proposed use of an existing small generator facility. Any time a new interconnection request is processed for an existing small generator facility, the utility will apply any standards in effect at the time of the interconnection request and, if approved, a new interconnection agreement will be required. The interconnection request shall be evaluated on the basis of the total net system capacity of the small generator facility. Utility Provided Information. A utility shall designate a contact person, and provide contact information on its website and for the Commission's website for submission of all interconnection requests, and from whom information on the interconnection request process and the utility's electric distribution system can be obtained. The information provided by the utility on its website shall include studies and other materials useful to an understanding of the feasibility of interconnecting a small generator facility on the utility electric distribution system, except to the extent providing the materials would violate security requirements or confidentiality agreements, or be contrary to law. For projects with a nameplate capacity over 20kW, the utility shall: Provide the applicant an opportunity to request a pre-application report, which may require payment of a fee listed in the utility’s tariff; Publicly post the fee amount on the utility’s website; and Provide the pre-application report within 20 business days, once the fee is paid. The pre-application report shall rely largely on pre-existing utility data and shall, at a minimum, include the following items: Initial proposed point of interconnection of the small generator facility, including address or GIS coordinates; Closest electrical facilities to the initial proposed point of interconnection of the small generator facility, including voltage level, feeder identification, substation, and including distance to that substation; Amount of generation hosting capacity available on the closest feeder, if this information is in possession of or easily obtainable by the utility; and Any other items specified by the Commission. In appropriate circumstances, the utility may require an applicant to execute an appropriate confidentiality agreement prior to release or access to confidential or restricted information. If an interconnection request is determined to be complete, any material modification, other than a minor equipment modification, that is not agreed to in writing by the utility, shall require submission of a new interconnection request. If an applicant is not currently a customer of the utility at the location for the proposed small generator facility, upon request from the utility, the applicant shall provide proof of site control evidenced by a property tax bill, deed, lease agreement, contract, or other acceptable document. Connection of Multiple Small Generator Facilities by Single Interconnection. To minimize the cost of interconnecting multiple small generator facilities, the utility or the applicant may propose a single point of interconnection for multiple small generator facilities located at a single site. If an applicant rejects a utility proposal for a single point of interconnection, the applicant shall pay any additional cost of providing separate points of interconnection for each small generator facility. If a utility unreasonably rejects a customer proposal for a single point of interconnection without providing a written technical explanation, the utility shall pay any additional cost of providing separate points of interconnection for each small generator facility. Electrical Isolation of a Small Generator Facility. A small generator facility shall be capable of being isolated from the utility electric distribution system. For a small generator facility interconnecting to a primary or secondary line, the isolation shall be by means of a lockable, visible-break isolation device accessible by the utility. The isolation device shall be installed, owned, and maintained by the interconnection customer for the small generator facility, and located electrically between the small generator facility and the point of interconnection. A draw-out type circuit breaker with a provision for padlocking at the draw-out position satisfies the requirement for an isolation device. Use of Lockbox for Access to Isolation Device. An interconnection customer may elect to provide the utility access to an isolation device that is contained in a building or area that may be unoccupied and locked or not otherwise readily accessible to the utility, by installing a lockbox provided by the utility that shall allow ready access to the isolation device. The lockbox shall be in a location that is readily accessible by the utility, and the interconnection customer shall permit the utility to affix a placard in a location of its choosing that provides clear instructions to utility operating personnel on access to the isolation device. In the event the interconnection customer fails to comply with the terms of this section and the utility needs to gain access to the isolation device, the utility may not be held liable for any damages resulting from any necessary utility action to isolate the small generator facility. Metering. Any metering necessitated by a small generator facility interconnection shall be installed, operated, and maintained in accordance with the applicable utility tariff. Any small generator facility metering requirements shall be clearly identified as part of the interconnection agreement executed by the interconnection customer and the utility. Utility Monitoring and Control of Small Generator Facility. Utility monitoring or control of a small generator facility shall be permitted subject to the conditions in §J of this regulation. Any utility monitoring or control requirements shall be: Consistent with the utility published requirements, as available on the utility’s website; and Clearly identified in an interconnection agreement executed by the interconnection customer and the utility. For a small generator facility under a nameplate capacity of 2 MW, utility monitoring or control is not permitted unless: The Commission approves a utility monitoring and control plan addressing such facilities in the aggregate; or The interconnection customer consents to utility monitoring or control. Equipment certified under the latest published editions of IEEE 1547, IEEE 1547.1, and UL 1741 shall be permitted to be used for monitoring or control upon mutual agreement of the utility and the interconnection customer. A utility monitoring and control plan submitted to the Commission pursuant to §J(3)(a) of this regulation shall include: Technical requirements; Cost; Benefits; Comparison to IEEE 1547-2018 compliant monitoring and control alternatives, if applicable; Customer permissions plan; and Project management plan. Good Small Generator Facility Cybersecurity Practice. A small generator facility’s cybersecurity shall be: Designed; Installed; Maintained; and Operated to the extent reasonable and practical, in accordance with accepted industry standards and meet utility cybersecurity requirements Witness Test of Small Generator Facility. The utility shall have the option of performing a witness test after construction of the small generator facility is completed. The applicant shall provide the utility at least 5 business days notice of the planned commissioning test for the small generator facility. If the utility elects to perform a witness test, the utility shall contact the applicant to schedule the witness test at a mutually agreeable time within 10 business days of the scheduled commissioning test. If the utility does not perform the witness test within 10 business days of the commissioning test, the witness test is considered waived unless the utility and applicant agree to extend the time for conducting the witness test. If the results of the witness test are not acceptable to the utility, the applicant shall address and resolve any deficiencies within 30 calendar days, which may be extended upon the request of the applicant prior to the expiration of the 30-calendar-day period. A request for extension may not be unreasonably denied by the utility. If the applicant fails to address and resolve the deficiencies to the satisfaction of the utility, the interconnection request shall be considered withdrawn. If a witness test is not performed by the utility or an entity approved by the utility, the applicant shall satisfy the interconnection test specifications and requirements specified in Section 8 of IEEE Standard 1547.1-2020. For interconnection equipment that has not been certified or approved under Regulation .07 of this chapter, the witness test may also include the verification by the utility specified in Section 8 of IEEE Standard 1547.1-2020. All tests verified by the utility shall be performed in accordance with the test procedures specified in Section 8 of IEEE Standard 1547.1-2020. The applicant shall, if requested by the utility, provide a copy of all documentation in its possession regarding testing conducted under Section 8 of IEEE Standard 1547.1-2020. The applicant shall demonstrate that it meets the smart inverter requirements of §O of this regulation, if applicable. Interconnection Studies and Applicant Information. If requested by the applicant, the utility shall provide the applicant copies of any interconnection studies performed in analyzing an interconnection request. An applicant may provide any other prospective applicant copies of interconnection studies to aid in streamlining a future utility review. Queue position for all small generator facilities shall be prioritized based on the date the interconnection request is submitted. Each utility shall publicly and electronically provide an interconnection queue, updated monthly, that includes the following information about each interconnection request for any small generator facility with a nameplate capacity greater than 500 kW: Size (MW or kW); Proposed circuit number and substation; County and zip code; Interconnection request received date; Queue position on the system’s proposed circuit number and substation; Review status; Interconnection request approved date; and Any other information requested by the Commission. A small generator facility shall remain on the list for at least 3 years after the interconnection request was approved by the utility, unless subsequently cancelled or removed from the interconnection queue pursuant to §N of this regulation. A utility may provide any additional information to a prospective applicant if the utility determines that doing so would streamline the utility’s review of an interconnection request. A utility has no obligation to provide any prospective applicant any information regarding prior interconnection requests, including a prior applicant's name, copies of prior interconnection studies performed by the utility, or any other information regarding a prior applicant or request. Validity of Conditional Approval. A project participating as a community solar energy generating system under COMAR 20.62 is not subject to this section. The notice of conditional approval shall clearly identify the applicable deadline and the consequences of failing to either deliver the certification of completion or request an extension by the deadline. Once the utility delivers notice of conditional approval to the applicant, the applicant shall deliver the certification of completion within the following time frames: For an application for a small generator facility with a nameplate capacity smaller than or equal to 100 kW, the applicant: Shall deliver the certification of completion within 6 months; Shall receive a 6-month extension of the specified deadline, upon request; and May receive one or more additional extensions of at least 6 months upon good cause shown after an initial 6-month extension; and For an application for a small generator facility with a nameplate capacity larger than 100 kW, the applicant: Shall deliver the certification of completion within 12 months; Shall receive a 6-month extension of the specified deadline, upon request; and May receive one or more additional extensions of at least 6 months upon good cause shown after an initial 6-month extension. A project participating in the Community Solar pilot program under COMAR 20.62 is not subject to this section. Smart Inverters. After January 1, 2024, any small generator facility requiring an inverter that submits an interconnection request shall use a smart inverter with either a default or a site-specific utility required inverter settings profile, as determined by a utility. Any small generator facility may replace an existing inverter with a similar spare inverter that was purchased prior to January 1, 2024, for use at the small generator facility. This requirement does not apply to inverter replacements conducted under manufacturer warranty. Prior to January 1, 2024, all utilities will establish default utility required inverter settings profiles for smart inverters pursuant to §O(5) of this regulation. A utility with a total number of less than 150,000 customers served in Maryland may use a Statewide utility required inverter settings profile as their default utility required inverter settings profile. To the extent reasonable, pursuant to any modifications required by §O(5) of this regulation, all utility required inverter setting profiles shall be consistent with applicable smart inverter recommendations from PJM Interconnection, LLC that are applicable. A default utility required inverter settings profile shall be established by a utility to optimize the safe and reliable operation of the electric distribution system, and shall serve the following objectives: The primary objective is to incur no involuntary real power inverter curtailments incurred during normal operating conditions and minimal real power involuntary curtailments during abnormal operating conditions. The secondary objective is to enhance electric distribution system hosting capacity and to optimize the provision of grid support services. A site-specific utility required inverter settings profile may be established by a utility as necessary to optimally meet the objectives established in §O(5) of this regulation. All default and site-specific utility required inverter settings profiles shall be documented in interconnection agreements. A default utility required inverter settings profile shall be published on the utility’s website. A utility with a total number of 150,000 or more customers served in Maryland shall: File an initial default utility required inverter settings profile with the Commission for approval by October 1, 2023 to be effective by January 1, 2024. File any changes to its established default utility required inverter settings profile with the Commission for approval. Commission Staff shall file any changes to the established statewide utility required inverter settings profile with the Commission for approval. A utility required inverter settings profile or statewide utility required inverter settings profile shall be deemed approved within 90 days upon filing, unless directed otherwise by the Commission. Flexible Interconnection Options. Utilities shall approve interconnection requests while considering flexible interconnection options under a limited export agreement or, for inadvertent export, net system capacity and a proposed use subject to the requirements of this section. Inadvertent Export for Energy Storage Devices. Small generator facilities using Level 3 interconnection requests are non-exporting systems and are not allowed to utilize inadvertent exports. A utility may not approve an inadvertent export option if the interconnection customer lacks the appropriate standardized controls to ensure that the small generator facility operates as agreed upon in interconnection agreements. Small generator facilities may inadvertently export power of a magnitude and duration as evaluated and allowed by the utility and as specified in their interconnection agreement. Thirty seconds shall be used as a default inadvertent export duration unless the utility determines that this level duration violates utility evaluation criteria. There are no limits on the number of times inadvertent exports occur in any given customer billing cycle. Small generator facilities may not have total inadvertent exports greater than the generating facility nameplate capacity multiplied by 1 hour per customer in each billing cycle. In the event that a small generator facility exceeds approved inadvertent export magnitude or duration limits, the small generator facility shall immediately cease to export power to the grid until acceptable output control has been reestablished. Net System Capacity and Proposed Use. An interconnection customer may request that its interconnection request be based on the proposed use of the small generator facility and the impact of its proposed use on net system capacity. A utility may not approve a proposed use if the interconnection customer lacks the appropriate standardized controls to ensure that the small generator facility operates as agreed upon in interconnection agreements. In the event that a small generator facility exceeds the approved net system capacity for the proposed use, the small generator facility shall immediately cease to export power to the grid until acceptable output control has been reestablished. Limited Export Agreements. By January 1, 2025, a utility shall publish on its interconnection website a description of their limited export agreement policies and provide a process for interconnection customers to request these agreements to avoid the need for a hosting capacity upgrade project to accommodate an interconnection request, including the following: Limited export agreements shall be made available upon request only to Level 2 and Level 4 interconnection customers; Limited export agreement terms shall be mutually agreed upon between a utility and an interconnection customer for operating conditions as specified in the interconnection agreement or in a separate limited export interconnection customer agreement; and The method of implementation and control of the limited export agreement terms shall be mutually agreed upon between a utility and the interconnection customer and specified in the interconnection agreement or in a separate limited export interconnection customer agreement. A utility may not approve a limited export agreement if the interconnection customer lacks the appropriate standardized controls to ensure that the small generator facility operates as agreed upon in interconnection agreements. In the event that a small generator facility does not curtail and exceeds the approved limited export parameters stated in the interconnection agreement or a separate limited export interconnection customer agreement, the small generator facility shall immediately cease to export real power to the grid until acceptable output control has been reestablished. If required by the utility, the small generator facility shall be subject to a verification reporting plan to monitor the small generator facility’s compliance with any flexible interconnection option limits involving net system capacity, inadvertent export, proposed use, and limited export agreement requirements as documented in the interconnection agreement. A verification reporting plan may include periodic reports, online monitoring, or other verification methods, or it may be waived as agreed upon by the utility and interconnection customer. Utilities may include a recurring administrative fee in utility tariffs as a term in flexible interconnection option agreements to reimburse the utility for estimated additional costs to administer these agreements and the stated limiting conditions. Failure of a small generator facility to demonstrate compliance with the facility’s verification reporting plan may result in the suspension of utility approvals in this section until the small generator facility agrees and implements an acceptable corrective action plan with the utility within 30 calendar days of notification by the utility. A small generator facility shall cease to export power if it fails to provide an acceptable corrective action plan to the utility, pursuant to §P(7) of this regulation. Hosting Capacity. Utilities shall establish hosting capacity policies subject to the following requirements: A utility shall designate a circuit a closed circuit if there is no remaining hosting capacity. A utility shall designate a circuit a restricted circuit if only reserve hosting capacity is available. A utility shall determine the amount of reserve hosting capacity on a restricted circuit based on a circuit-specific assessment of distributed energy resource forecasts or other factors, including customer density, type of area served, and customer demographics of the circuit. A utility may determine the aggregate generation of a small generator facility permitted to use an electric distribution circuit’s reserve hosting capacity and publish this information on their website. A utility shall report their closed circuits, restricted circuits, and reserve hosting capacity in their hosting capacity reporting system. A utility may submit for the Commission’s review and approval a hosting capacity upgrade plan or multiple plans to address or otherwise increase the utility’s existing distribution aggregate circuit hosting capacity limits across the system, or in a specific area of an electric utility’s system, that are forecasted to be congested in the future if the utility’s forecast of distributed energy resource growth exceeds existing hosting capacity. These plans may be considered by the Commission if primary voltage hosting capacity upgrade fees, pursuant to §R of this regulation, exceed a threshold of the utility’s average cost per kilowatt for their aggregate customer funded hosting capacity upgrade projects completed in the previous year, unless good cause exists for a utility to request a waiver of this requirement. Hosting capacity upgrade plans that are submitted by a utility shall include: A description of the electric system areas to be included in the hosting capacity upgrade plan at the feeder and substation level; A description of the assumptions used for establishing and prioritizing the area covered by the hosting capacity upgrade plan and associated forecasts and timeline for hosting capacity utilization; A description of the assumptions used for modeling and establishing the cost of the hosting capacity upgrade plan; If the plan proposes that ratepayers bear any costs that would not be paid by future interconnection customers, a justification for the percentage cost allocation proposed between interconnection customers and ratepayers, including descriptions of: How the proposed cost allocation was developed and what alternatives were considered, explaining and quantifying the benefits ratepayers are expected to receive from the upgrade; and How the utility engaged with stakeholders, particularly the ratepayer advocate’s office, the Maryland Office of People’s Counsel, in the development of the utility’s cost allocation proposal; A description of the proposed cost allocation method in terms of dollars per kilowatt for a primary voltage hosting capacity fee for an interconnection customer; A description of the proposed cost allocation to ratepayers and the risks to ratepayers of unallocated hosting capacity upgrade costs if the hosting capacity upgrade does not become fully utilized; and A proposal for utility cost recovery that describes how hosting capacity upgrade costs shall be offset by future utility revenues from interconnection customers. A utility shall have a procedure for calculating hosting capacity accounting for either gross peak or gross minimum loading based on good engineering practice. The utility shall perform a representative sample of hosting capacity calculation validation checks at least annually, or more frequently in areas experiencing significant growth or distributed energy resource penetration. The hosting capacity calculation validation check frequency shall account for the utility's experience, good engineering practices, and judgment. Maryland Cost Allocation Method. Within 1 year of the effective date of this regulation, electric utilities shall submit an electric utility service tariff for Commission approval for a primary voltage hosting capacity cost sharing and allocation methodology for interconnection customers, as follows: The default hosting capacity cost sharing and allocation methodology for primary voltage interconnection customers shall be based on locational pricing to incentivize interconnection in areas with higher available hosting capacity and disincentivize interconnection in areas with lower available hosting capacity. A utility may petition the Commission to implement a hosting capacity cost sharing and allocation methodology for primary voltage interconnection customers that is not locationally based for “good cause” in their tariff filing. An interconnection request shall be eligible for hosting capacity cost sharing and allocation under this section unless they are exempted for the following reasons: The interconnection request is subject to the PJM Interconnection, LLC Tariff; The interconnection request is in an area with its cost allocation governed by a hosting capacity upgrade plan approved by the Commission; The interconnection is on a dedicated primary voltage feeder that may not benefit any other interconnection customer; The interconnection is on a dedicated secondary voltage facility that may not benefit any other interconnection customer; The interconnection request is on an AC distribution grid or spot network; or Other good cause as documented by the utility and reported, pursuant to Regulation .14 of this chapter. If an interconnection request is exempted, pursuant to §R(1)(c) of this regulation, the interconnection customer shall pay all interconnection costs as determined by the utility, unless the interconnection request is subject to the PJM Tariff or the interconnection request is in an area with its cost allocation governed by a hosting capacity upgrade plan approved by the Commission. If sufficient hosting capacity is not available at a point of interconnection for a primary voltage interconnection customer, an electric utility may propose a hosting capacity upgrade project to the interconnection customer or customers, as follows: The utility shall charge the primary voltage interconnection customer a hosting capacity fee for its share of the primary voltage hosting capacity upgrade cost proportional to the interconnection customer’s utilization of hosting capacity. If more than one interconnection request exists in the interconnection queue that shall benefit from the electric utility proposed hosting capacity upgrade project, these interconnection customers shall be clustered together for the purpose of calculating hosting capacity fees. Hosting capacity fees for clustered interconnection customers shall be calculated proportional to each interconnection customer’s utilization of the hosting capacity created by the hosting capacity upgrade project. All hosting capacity upgrade costs in excess of hosting capacity fees collected shall be accumulated in a separate unallocated primary voltage hosting capacity upgrade cost account for future allocation to primary voltage interconnection customers. Unallocated hosting capacity upgrade costs for primary voltage interconnection customers shall be shared and allocated to other primary voltage interconnection customers using a primary voltage hosting capacity cost sharing and allocation methodology in an electric utility service tariff approved by the Commission. Within 1 year of the effective date of this regulation, electric utilities shall submit an electric utility service tariff for Commission approval for a secondary voltage cost sharing and fee for both residential and commercial interconnection customers, as follows: If sufficient hosting capacity is not available at a point of interconnection for a secondary voltage interconnection customer, an electric utility may construct a hosting capacity upgrade project for the interconnection customer or customers. All secondary voltage hosting capacity upgrade costs shall be accumulated in separate unallocated accounts for both residential and commercial secondary voltage interconnection customers for future allocation in hosting capacity fees. Unallocated hosting capacity upgrade costs for both residential and commercial secondary voltage interconnection customers shall be shared and allocated to other secondary voltage interconnection customers using a hosting capacity cost sharing and allocation fee in an electric utility service tariff approved by the Commission. Hosting capacity fees for primary voltage interconnection customers shall be reset using a cost sharing and allocation methodology approved by the Commission in an electric utility service tariff filing whenever a change in methodology is proposed, unless the fee is zero or the fee change is less than $1 per kilowatt. Hosting capacity fees for secondary voltage interconnection customers shall be reset annually using a cost sharing and allocation methodology approved by the Commission unless the fee is zero or the fee change is less than $1 per kilowatt from the current fee in the electric utility’s service tariff. A utility may submit for Commission approval an administrative charge in its service tariff to recover its administrative costs for managing the cost sharing and allocation methodology for primary and secondary voltage interconnection customers. A utility shall describe all hosting capacity upgrade project rightsizing projects describing their forecasts, inputs, and assumptions in their next rate case to assist stakeholders in a prudency review. Vehicle to Grid Interconnection. A V2G System shall meet the following requirements: The interconnection customer for a V2G system shall submit an interconnection request pursuant to Regulation .04 of this chapter. A V2G system interconnection shall be valid only at a single point of interconnection specified in the interconnection agreement. Additional locations shall require additional interconnection reviews and associated interconnection agreements. An electric company shall consider a V2G system to be an energy storage device pursuant to Regulation .02B of this chapter for the purpose of evaluating the electrical performance requirements applicable to an interconnection request. Characteristics of energy storage systems that do not and cannot apply to the use of EVs as connected energy storage units shall not be required of V2G systems operated as energy storage. A V2G system shall not be authorized in bidirectional mode while in parallel operation with the local electric power system unless an interconnection agreement is in place between the interconnection customer and the relevant electric utility and the interconnection customer has received a permission to operate from the electric company. An electric company may delay interconnection of a V2G system to provide adequate time to ensure electric distribution system safety and reliability in advance of vehicle-to-grid interconnections pursuant to applicable requirements in Regulation .09 of this chapter for Level 1 Review, Regulation .10 of this chapter for a Level 2 Review, Regulation .11 of this chapter for a Level 3 Review, and Regulation .12 of this chapter for a Level 4 Review. To ensure safety, reliability and V2G functionality for DC EVSE V2G Systems, the interconnection agreement shall require adherence to UL 1741 incorporated by reference in COMAR 20.50.02.02(I). To ensure safety, reliability and V2G functionality for AC EVSE V2G Systems there are two acceptable certification pathways for which only one certification pathway shall be required in an interconnection agreement: Certification pathway 1 is as follows: UL 1741 incorporated by reference in COMAR 20.50.02.02(I) and UL 2594 incorporated by reference in COMAR 20.50.02.02(N) for a V2G Ready EVSE; and SAE J3072 incorporated by reference in COMAR 20.50.02.02(O) for a bidirectional electric vehicle. Certification pathway 2 is as follows: UL 9741 incorporated by reference in COMAR 20.50.02.02(M) for V2G Ready EVSE; and UL 1741 SB under the QIKP Grid Interconnection Performance Certification for a bidirectional electric vehicle and V2G Ready EVSE. If applicable, certifications pursuant to Regulation .06S(4) of this chapter are not available or safety, reliability, and V2G functionality cannot be ensured: The utility may require reasonable alternative methods such as protective relaying equipment, a power control system, or other alternative methods in an interconnection agreement; or If safety, reliability and V2G functionality cannot be ensured through certifications or reasonable alternative methods, an electric company shall deny the interconnection request. A V1G System shall meet the following requirements. An interconnection request, interconnection agreement, and an electric company permission to operate is not required for a V1G Ready EVSE provided that the V1G Ready EVSE is configured to only allow V1G operation in compliance with relevant standards. A V2G System that operates as a V1G Ready EVSE shall be accepted by an electric company using a method for notification form submittal as determined by the electric company. The notification form used by the electric company shall only require information required to attest to V1G operation and not duplicate an interconnection request. A V1G Ready EVSE shall not be changed to a V2G Ready EVSE without first receiving an interconnection request and permission to operate from the utility. Only the EVSE manufacturer or a manufacturer approved third party entity may reprogram or reconfigure an EVSE to bidirectional operation. After January 1, 2024, any small generator facility inverter for which an interconnection request is submitted shall be deemed certified and approved if it meets the requirements of IEEE Standard 1547-2018 and UL Standard 1741-SB, except for inverters purchased pursuant to Regulation .06N(2) of this chapter. After January 1, 2024, any small generator facility shall be deemed approved if the interconnection equipment including interface components such as switchgear, multifunction relays, or other interface devices are compatible with the interconnection equipment, pursuant to witness test requirements pursuant to Regulation .06L of this chapter. An electric utility shall approve a meter collar adapter model for installation in its Maryland service area for specific compatible meter configurations and customer applications, provided that the meter collar adapter model meets the following criteria: The meter collar adapter model is approved or listed by a nationally recognized testing laboratory; The meter collar adapter model is approved for use in utility service areas, unless sufficient rational for disapproval is provided by an electric utility; All meter collar model installations, access, testing, inspections, servicing, and removals shall only be performed by a qualified person as agreed between the utility and the meter collar manufacturer; The meter collar adapter model design does not impede access to the sealed meter socket compartment, or to the meter itself by a qualified person; The meter collar adapter model is compatible with the National Electric Code; and The meter collar adapter model is compatible to the specific meter configurations and customer applications to ensure that the meter collar adapter is capable of being safely and reliably inserted into a meter socket to maintain a secure connection with both the meter socket and the utility meter. An electric utility shall approve or disapprove a meter collar adapter model for installation in its service area no later than 90 days after a meter collar manufacturer submits a request for approval of the meter collar adapter, and a utility’s procedures shall be updated within 90 days of utility approval. An electric utility shall provide an explanation to the requesting meter collar manufacturer explaining the reasons any meter collar adapter model application was denied. A requesting meter collar adapter manufacturer may appeal the utility decision to the Commission using the dispute resolution process in Regulation .13 of this chapter. An electric utility shall provide public notice of all decisions approving a meter collar adapter model by posting the information on the utility’s website. An electric utility shall authorize the installation and operation of a utility-approved meter collar adapter for a customer installation, provided the meter collar adapter meets the following criteria: The meter collar adapter is qualified to be connected to the supply side of the service disconnect, pursuant to the applicable provisions of the National Electric Code; The meter collar adapter is rated for the meter socket into which it is intended to be installed; The meter collar adapter does not exceed the weight bearing limits of a meter socket; Multiple meter collar adapters are not stacked in a meter socket; and The meter collar adapter does not disable this excessive heating detection capability of AMI meters. A utility shall uninstall an approved meter collar adapter in the aggregate if any deficiencies are found after installation that result in safety or operational concerns, if these concerns cannot be remediated by a customer for a specific installation or by a meter collar adapter manufacturer, in the aggregate. The determination of violations in this regulation and the assessment of related civil penalties and corrective action plans shall be delegated to the Engineering Division. A utility shall determine within 10 business days the interconnection jurisdiction pursuant to Regulation .01 of this chapter and the level of utility review required for an interconnection request based on nameplate capacity. A utility shall use a Level 1 procedure to evaluate an interconnection request to connect an inverter-based small generator facility when the small generator facility, or multiple small generator facilities interconnecting at a point of common coupling, has a nameplate capacity of 20kW or less. A utility shall use a Level 2 procedure to evaluate an interconnection request when: The following criteria are met: The small generation facility, or multiple small generator facilities interconnecting at a point of common coupling, has a nameplate capacity of 2 MW or less; The interconnection equipment is lab-certified or field-approved; and The proposed interconnection is to a radial distribution circuit, or a spot network limited to serving one customer; or Alternatively, the small generator facility was reviewed under Level 1 review procedures but not approved, and the applicant has submitted a new interconnection request for consideration. A utility shall use a Level 3 procedure to evaluate an interconnection request to area networks and radial distribution circuits when electric power is not exported to the electric distribution system based on the following criteria: For interconnection requests to the load side of an area network: The nameplate capacity of the small generator facility, or multiple small generator facilities interconnecting at a point of common coupling, is less than or equal to 50 kW; The proposed small generator facility utilizes a lab-certified inverter-based equipment package; The small generator facility utilizes reverse power relays, other protection functions, or both, that prevent the export of power into the area network; The aggregate generation on the area network does not exceed the smaller of 5 percent of an area network's maximum load or 50 kW; and Construction of facilities by the electric distribution company is not required to accommodate the small generator facility; or For interconnection requests to a radial distribution circuit: The small generator facility has a nameplate capacity of 10 MW or less; The aggregate generation on the circuit, including the proposed small generator facility, is 10 MW or less; The small generator facility will use reverse power relays or other protection functions that prevent power flow onto the electric distribution system; The small generator facility is not served by a shared transformer; and Construction of facilities by the utility on its own electric distribution system is not required to accommodate the small generator facility. A utility shall use the Level 4 procedures for evaluating interconnection requests if: The interconnection request cannot be approved under a Level 1, Level 2, or Level 3 review, and the applicant has submitted an interconnection request for consideration under a Level 4 study review; and The interconnection request does not meet the criteria for qualifying for a review under Level 1, Level 2, or Level 3 review procedures. The utility shall evaluate a Level 1 small generator facility for the potential for adverse system impacts using net system capacity, pursuant to Regulation .06A and B of this chapter, unless nameplate capacity is specifically required using the following: For interconnection of a proposed small generator facility: To a radial distribution circuit, the aggregate generation on the circuit, including the proposed small generator facility, may not exceed 15 percent of the line section annual peak load as most recently measured at the substation or calculated for the line section; or To a spot network: On the load side of spot network protectors, the proposed small generator facility shall utilize an inverter-based equipment package; The interconnection equipment proposed for the small generator facility is lab-certified; and The aggregate generation of all interconnected small generator facilities may not exceed 5 percent of the spot network's maximum load if the spot network serves more than one customer; When a proposed small generator facility is to be interconnected on a single-phase shared secondary line, the aggregate generation on the shared secondary line, including the proposed small generator facility, may not exceed 20 kW; When a proposed small generator facility is single-phase and is to be interconnected on a center tap neutral of a 240 volt service, its addition may not create an imbalance between the two sides of the 240 volt service of more than 20 percent of the nameplate rating of the service transformer; As an alternative non-mandatory method to evaluate the adverse system impacts of a proposed Level 1 small generator facility on the distribution system, as described in §A(1)—(3) of this regulation, or as a mandatory next step prior to rejecting an interconnection request, pursuant to §E of this regulation, for Level 1 Review Failure, a utility may use a power-flow based analysis system with modeling of IEEE 1547-2018 inverter capabilities as follows, if its use may change the analysis result as determined by the utility: For primary voltage systems, within 6 months of the effective date of this regulation; and For secondary voltage systems, within 2 years of the effective date of this regulation; Modification or construction of additional interconnection facilities by the utility on its distribution system, except for metering or a minor system modification, is not required to accommodate the small generator facility; and If the proposed interconnection requires a minor system modification, the utility shall notify the applicant of that requirement when it provides the Level 1 evaluation result, as follows: The applicant shall inform the utility within 10 business days if the applicant elects to continue the application; If the applicant makes such an election, the utility shall provide an interconnection agreement, along with a non-binding good faith cost estimate and construction schedule for those upgrades, to the applicant within 30 calendar days after the utility receives such an election; and The applicant shall have 30 calendar days, or other mutually agreeable time frame after receipt of the interconnection agreement, to sign and return such agreement. The utility in conducting a Level 1 interconnection review shall: Within 5 business days after receipt of the interconnection request, inform the applicant that the interconnection request is: Complete; or Incomplete and what materials are missing; and Within 15 business days after the utility notifies the applicant that the application is complete under §B(1) of this regulation, verify that the small generator facility can be interconnected safely and reliably under §A of this regulation. Unless the utility determines and demonstrates that a small generator facility cannot be interconnected safely or reliably to its electric distribution system, the utility shall approve the interconnection request and provide a permission to operate notice within 20 business days of receipt of acceptable documents, subject to the following conditions: The small generator facility has been approved by local or municipal electric code officials with jurisdiction over the interconnection; A certificate of completion has been returned to the utility; The witness test has been successfully completed or waived by the utility; and The applicant has signed an interconnection agreement. If an applicant does not sign the interconnection agreement within 30 calendar days after receipt from the utility, the interconnection request is considered withdrawn unless the applicant requests to have the deadline extended. A request for extension may not be unreasonably denied by the utility. Level 1 Review Failure. If the small generator facility is not approved under a Level 1 review, the utility shall provide the applicant a letter explaining its reasons for denying the interconnection request. If a small generator facility fails a Level 1 review, the utility may approve the interconnection request if the small generator facility can be interconnected safely and reliably to the utility’s electric distribution system. When a small generator facility is not approved under a Level 1 review, the applicant may submit a new interconnection request for consideration under Level 2, Level 3, or Level 4 procedures. The utility shall evaluate a Level 2 small generator facility for the potential for adverse system impacts using net system capacity, pursuant to Regulation .06A and B of this chapter, unless nameplate capacity is specifically required using the following: For interconnection of a proposed small generator facility: To a radial distribution circuit, the aggregate generation on the circuit, including the proposed small generator facility, may not exceed 15 percent of the line section annual peak load most recently measured at the substation or calculated for the line section; or To a spot network: When the interconnection of a proposed small generator facility is to the load side of spot network protectors, the proposed small generator facility shall utilize an inverter-based equipment package; The applicant's interconnection equipment proposed for the small generator facility shall be lab-certified or field-approved; and A small generator facility, when aggregated with other generation, the aggregate generation on the spot network, may not exceed 5 percent of a spot network's maximum load if the spot network serves more than one customer; For fault current limitations: The nameplate capacity of the proposed small generator facility, in aggregation with other generation and energy storage devices on the distribution circuit, may not contribute more than 10 percent to the electric distribution circuit's maximum fault current at the point on the primary line nearest the point of interconnection; The nameplate capacity of the proposed small generator facility, in aggregation with other generation and energy storage devices on the distribution circuit, may not cause any distribution protective devices and equipment including substation breakers, fuse cutouts, and line reclosers, or other customer equipment on the electric distribution system to be exposed to fault currents exceeding 90 percent of the short circuit interrupting capability; and The interconnection request may not request interconnection on a circuit that already exceeds 90 percent of the short circuit interrupting capability; The proposed small generator facility's point of interconnection may not be on a transmission line; When a small generator facility is to be connected to 3-phase, 3-wire primary utility distribution lines, a 3-phase or single-phase generator shall be connected phase-to-phase; When a small generator facility is to be connected to 3-phase, 4-wire primary utility distribution lines, a 3-phase or single-phase generator will be connected line-to-neutral and will be effectively grounded; When the proposed small generator facility is to be interconnected on single-phase shared secondary line, the aggregate generation on the shared secondary line, including the proposed small generator facility, may not exceed 20 kW; When a proposed small generator facility is single-phase and is to be interconnected on a center tap neutral of a 240 volt service, its addition may not create an imbalance between the two sides of the 240 volt service of more than 20 percent of the nameplate rating of the service transformer; A small generator facility, in aggregate with other generation and energy storage devices interconnected to the distribution side of a substation transformer feeding the circuit where the small generator facility proposes to interconnect, the aggregate generation may not exceed 10 MW in an area where there are known or posted transient stability limitations to generating units located in the general electrical vicinity; As an alternative non-mandatory method to evaluate the adverse system impacts of a proposed Level 2 small generator facility on the distribution system, as described in §A(1)—(8) of this regulation, or as a mandatory next step prior to rejecting an interconnection request, pursuant to §F of this regulation, for Level 2 Review Failure, a utility may use a power-flow based analysis system with modeling of IEEE 1547-2018 inverter capabilities as follows, if its use may change the analysis result as determined by the utility: For primary voltage systems, within 6 months of the effective date of this regulation; and For secondary voltage systems, within 2 years of the effective date of this regulation; Except as permitted by an additional review in §G of this regulation, no modification or construction of additional facilities by a utility of its distribution system, with the exception of metering or a minor system modification, shall be required to accommodate the small generator facility; and If the proposed interconnection facility requires a site-specific utility required inverter settings profile review or a minor system modification without further study review needed, the utility shall notify the applicant of that requirement when it provides the Level 2 evaluation result, as follows: The applicant must inform the utility within 10 business days if the applicant elects to continue the application; If the applicant makes such an election, the utility shall provide an interconnection agreement, along with a non-binding good faith cost estimate and construction schedule for any minor system modifications to the applicant within 30 calendar days after the utility receives such an election; and The applicant shall have 30 calendar days, or other mutually agreeable time frame after receipt of the interconnection agreement, to sign and return such agreement. A utility shall, within 5 business days after receipt of the interconnection request, inform the applicant that the interconnection request is: Complete; or Incomplete and what materials are missing; Queue Position. When an interconnection request is complete, the utility shall assign a queue position. The queue position of the interconnection request shall be used to determine the potential adverse system impact of the small generator facility based on the relevant screening criteria. The utility shall notify the applicant of any other higher queue position applicants on the same line section or spot network for which interconnection is sought. Queue position may not be forfeited or otherwise impacted by the submission of a dispute under the provisions of Regulation .13 of this chapter. When a utility determines additional information is required to complete an evaluation: The utility shall request the information; The time necessary to complete the evaluation may be extended, but only to the extent of the delay required for receipt of the additional information; and When additional information is required, the utility may not revert to the start of the review process or alter the applicant's queue position. Within 20 business days after the utility notifies the applicant it has received a completed interconnection request, the utility shall: Evaluate the interconnection request using the Level 2 screening criteria; Review the applicant's analysis, if provided by applicant, using the same criteria; Provide the applicant with the utility's evaluation, including a comparison of the results of its own analyses with those of applicant, if applicable; and When a utility does not have a record of receipt of the interconnection request and the applicant can demonstrate that the original interconnection request was delivered, expedite its review to complete the evaluation of the interconnection request within 20 business days. Failure to Meet Level 2 Criteria. Additional review may be appropriate when a small generator facility has failed to meet one or more of the Level 2 criteria of §A of this regulation. A utility shall: Within 30 calendar days, offer to perform additional review to determine whether minor system modifications or a site-specific utility required inverter settings profile would enable the interconnection to be made consistent with safety, reliability, and power quality criteria; Provide the applicant with a nonbinding, good faith estimate of the costs of the additional review and minor system modifications; and Advise the applicant if a limited export customer agreement could be used to facilitate reliable and safe interconnection to the electric distribution system. The utility shall undertake the additional review only if the applicant agrees within 10 business days to pay for the cost of the review, which may be extended at the request of the applicant. A request for extension may not be unreasonably denied by the utility. If the review identifies the need for modifications to the distribution system, the utility shall make the necessary modifications only if the interconnection customer agrees to pay for the cost of the modifications. Interconnection Agreement. When a utility determines that the interconnection request passes the Level 2 screening criteria, or fails one or more of the Level 2 screening criteria but determines that the small generator facility can be interconnected safely and reliably, the utility shall provide the applicant an interconnection agreement within 5 business days after the determination. The applicant shall have either 30 calendar days, or another mutually agreeable time frame after receipt of the interconnection agreement, to sign and return the interconnection agreement. If the applicant does not sign the interconnection agreement within 30 calendar days, the request shall be considered withdrawn unless the applicant and utility mutually agree to extend the time period for executing the interconnection agreement prior to the expiration of the 30-calendar-day calendar period. A request for extension may not be unreasonably denied by the utility. After the interconnection agreement is signed by the applicant and utility, interconnection of the small generator facility shall proceed according to any milestones agreed to by the applicant and utility in the interconnection agreement. The utility shall approve the interconnection request and provide a permission to operate notice within 20 business days of receipt of acceptable documents, subject to the following conditions: All milestones agreed to in the interconnection agreement are satisfied; The small generator facility is approved by electric code officials with jurisdiction over the interconnection; The applicant provides a certificate of completion to the utility; Upon request of the utility, the applicant provides one or more photographs of the small generator facility site location, components, metering equipment, and other related facilities and equipment; and There is a successful completion of the witness test, if conducted by the utility. Level 2 Review Failure. If the small generator facility is not approved under a Level 2 review, the utility shall provide the applicant written notification explaining its reasons for denying the interconnection request. The applicant may submit a new interconnection request for consideration under a Level 3 or Level 4 interconnection review; however, the queue position assigned to the Level 2 interconnection request shall be retained provided the request is made within 15 business days of notification that the current Level 2 interconnection request is denied. The utility shall use the Level 3 review procedure for an interconnection request that meets the Level 3 criteria in Regulation .08 of this chapter. Queue Position. Once the interconnection request is considered complete by the utility, the utility shall assign a queue position based upon the date and time the interconnection request is determined to be complete. The queue position of each interconnection request shall be used to determine the potential adverse system impact of the small generator facility based on the relevant screening criteria. The utility shall notify the applicant of any other higher queue position applicants on the same radial line or area network that the applicant is seeking to interconnect to. Queue position may not be forfeited or otherwise impacted by any pending dispute submitted under the provisions of Regulation .13 of this chapter. Interconnection requests meeting the requirements set forth in Regulation .08 of this chapter for nonexporting small generator facilities interconnecting to an area network shall be presumed by the utility to be appropriate for interconnection. The utility shall process the interconnection request to area networks using the following procedures: The utility shall evaluate the interconnection request under Level 2 interconnection review procedures as set forth in Regulation .10 of this chapter, except that the utility shall have 25 business days to conduct an area network impact study to determine any potential adverse system impact of interconnecting to the utility's area network; If the area network impact study identifies potential adverse system impacts, the utility may determine at its sole discretion that it is inappropriate for the small generator facility to interconnect to the area network, in which case the interconnection request shall be denied; however, the applicant may elect to submit a new interconnection request for consideration under Level 4 procedures, in which case the queue position assigned to the Level 3 interconnection request will be retained provided the request is made within 15 business days of notification that the current application is denied; The utility shall conduct the area network impact study at its own expense; and In the event the utility denies the interconnection request, the utility shall provide the applicant with a copy of its area network impact study and written justification for denying the interconnection request. When an interconnection request meets the requirements of Regulation .08 of this chapter for nonexporting small generator facilities interconnecting to a radial distribution circuit, the utility shall: Evaluate the interconnection request using the Level 2 review in Regulation .10 of this chapter; and Approve the interconnection request if all of the applicable Level 2 screens are satisfied, except that the peak line section value indicated in Regulation .10A(1)(a) shall be 25 percent instead of 15 percent. Interconnection Agreement. If a small generator facility satisfies the criteria in §C or D of this regulation, the utility shall approve the interconnection request and provide an interconnection agreement for the applicant to sign. The applicant shall have 30 calendar days, or other mutually agreeable time frame after receipt of the interconnection agreement, to sign and return the interconnection agreement. If the applicant does not sign the interconnection agreement within 30 calendar days, the interconnection request shall be considered withdrawn unless the applicant and utility mutually agree to extend the time period for executing the interconnection agreement prior to the expiration of the 30-calendar-day period. A request for extension may not be unreasonably denied by the utility. After the interconnection agreement is signed by the applicant and utility, interconnection of the small generator facility shall proceed according to any milestones agreed to by the applicant and utility in the interconnection agreement. The utility shall approve the interconnection request and provide a permission to operate notice within 20 business days of receipt of acceptable documents, subject to the following conditions: All milestones agreed to in the interconnection agreement are satisfied; The small generator facility is approved by electric code officials with jurisdiction over the interconnection; The applicant provides a certificate of completion to the utility; Upon request of the utility, the applicant provides one or more photographs of the small generator facility site location, components, metering equipment, and other related facilities and equipment; and There is a successful completion of the witness test, if conducted by the utility. Level 3 Review Failure. If the small generator facility is not approved under a Level 3 review, the utility shall provide the applicant written notification explaining its reasons for denying the interconnection request. If the small generator facility is not approved under a Level 3 review, the applicant may submit a new interconnection request for consideration under the Level 4 procedures; however, the queue position assigned to the Level 3 interconnection request shall be retained provided the request is submitted within 15 business days of the notice that the current Level 3 request was not approved. A utility shall use the Level 4 study review procedure for an interconnection request that meets the Level 4 criteria in Regulation .08 of this chapter. Interconnection Request. Within 5 business days from receipt of an interconnection request, the utility shall notify the applicant whether the request is Complete; or Incomplete. If the interconnection request is not complete: The utility shall provide the applicant a written list detailing information that shall be provided to complete the interconnection request; The applicant shall have 10 business days, which may be extended at the request of the applicant and not unreasonably denied by the utility, to provide appropriate data in order to complete the interconnection request, or the interconnection request shall be considered withdrawn; and The interconnection request shall be considered complete: If the required information has been provided by the applicant; or The utility and applicant have agreed that the applicant may provide additional information at a later time. Queue Position. When an interconnection request is complete, the utility shall assign a queue position. The utility shall use the queue position of an interconnection request to determine the cost responsibility necessary for the facilities to accommodate the interconnection. The utility shall notify the applicant of other higher-queued applicants on the same line section of the new interconnection request. Any required interconnection studies may not begin until the utility has completed its review of all other interconnection requests that have a higher queue position. Queue position is not forfeited or otherwise impacted by any pending dispute submitted under the provisions of Regulation .13 of this chapter. Scoping Meeting. By mutual agreement of the utility and applicant, the scoping meeting may be waived and the interconnection feasibility study, interconnection impact study, or interconnection facilities studies provided for in a Level 4 review and discussed in this section may be waived or combined. If agreed to by the utility and applicant, a scoping meeting shall be held within 10 business days, or other mutually agreed to time, after the utility has notified the applicant that the interconnection request is considered complete, or the applicant has requested that its interconnection request proceed after failing the requirements of a Level 2 review or Level 3 review. The purpose of the meeting is to review the interconnection request, existing studies relevant to the interconnection request, and the results of the Level 1, Level 2, or Level 3 screening criteria. If the utility and applicant agree at a scoping meeting that an interconnection feasibility study shall be performed, the utility shall provide to the applicant, not later than 5 business days after the scoping meeting: An interconnection feasibility study agreement; An outline of the scope of the study; and A nonbinding, good faith estimate of the cost to perform the study. If the applicant and utility agree at a scoping meeting that an interconnection feasibility study is not required, the utility shall provide to the applicant, not later than 5 business days after the scoping meeting: An interconnection system impact study agreement; An outline of the scope of the study; and A nonbinding, good faith estimate of the cost to perform the study. If the utility and applicant agree at the scoping meeting that an interconnection feasibility study and system impact study are not required, the utility shall provide to the applicant, not later than 5 business days after the scoping meeting: An interconnection facilities study agreement; An outline of the scope of the study; and A nonbinding, good faith estimate of the cost to perform the study. Interconnection Feasibility, Interconnection System Impact, and Interconnection Facilities Studies. Interconnection Feasibility Study. An interconnection feasibility study shall include any necessary analyses for the purpose of identifying a potential adverse system impact to the utility's electric distribution system that would result from the interconnection from among the following: Initial identification of any circuit breaker short circuit capability limits exceeded as a result of the interconnection; Initial identification of any thermal overload or voltage limit violations resulting from the interconnection; Initial review of grounding requirements and system protection; and Description and nonbinding estimated cost of facilities required to interconnect the small generator facility to the utility's electric distribution system in a safe and reliable manner. If an applicant requests that the interconnection feasibility study evaluate multiple potential points of interconnection, additional evaluations may be required. Additional evaluations shall be conducted at the expense of the applicant. An interconnection system impact study is not required if the interconnection feasibility study concludes there is no adverse system impact, or if the study identifies an adverse system impact and the utility is able to identify a remedy without the need for an interconnection system impact study. The utility and applicant shall use an interconnection feasibility study agreement form. The utility shall avoid duplicating previously conducted interconnection studies to the extent possible. The utility may require a study deposit of the lesser of 100 percent of estimated nonbinding good faith study costs or $1,000. The interconnection feasibility study shall be completed and the results shall be transmitted to the interconnection customer within 30 calendar days after the interconnection feasibility study agreement is signed by the parties. Interconnection System Impact Study. A distribution interconnection system impact study shall be performed when a potential distribution system adverse system impact is identified in the interconnection feasibility study. Scope of Interconnection System Impact Study. An interconnection system impact study shall evaluate the impact of the proposed interconnection on both the safety and reliability of the utility's electric distribution system. The interconnection system impact study shall identify and detail the system impacts that result when a small generator facility is interconnected without project or system modifications, focusing on the adverse system impacts identified in the interconnection feasibility study, or potential impacts including those identified in the scoping meeting. The interconnection system impact study shall consider all small generator facilities that, on the date the interconnection system impact study is commenced, are directly interconnected with the utility's electric distribution system, have a pending higher queue position to interconnect to the system, or have signed an interconnection agreement. As part of its impact study, the utility shall agree to evaluate and consider any separate studies prepared by the applicant that evaluate alternatives for interconnecting the small generator facility, including the applicant's assessment of potential impacts of the small generator facility on the electric distribution system. The utility shall provide the applicant with the utility's final impact study evaluation, including a comparison of the results of its own analyses with those provided by the applicant. Within 5 business days of transmittal of the interconnection feasibility study report, the utility shall send the applicant: An interconnection system impact study agreement using a form; An outline of the scope of the interconnection system impact study; and A good faith estimate of the cost to perform the study. The interconnection system impact study shall include any necessary elements from among the following: A load flow study; Identification of affected systems; An analysis of equipment interrupting ratings; A protection coordination study; Voltage drop and flicker studies; Protection and set point coordination studies; Grounding reviews; and Impact on system operation. An interconnection system impact study shall consider any necessary criteria from among the following: A short circuit analysis; A stability analysis; Alternatives for mitigating adverse system impacts on affected systems; Voltage drop and flicker studies; Protection and set point coordination studies; and Grounding reviews. The final interconnection system impact study shall provide the following: The underlying assumptions of the study; The results of the analyses; A list of any potential impediments to providing the requested interconnection service; Required distribution upgrades; and A nonbinding good faith estimate of cost and time to construct any required distribution upgrades. The utility may require a study deposit of the lesser of 50 percent of estimated nonbinding good faith study costs or $3,000. The interconnection system impact study, if required, shall be completed and the results transmitted to the interconnection customer within 45 calendar days after the interconnection system impact study agreement is signed by the parties. Interconnection Facilities Study. Within 5 business days of completion of the interconnection system impact study, the utility shall provide to the applicant: A report of the interconnection system impact study; An interconnection facilities study agreement; An outline of the scope of the interconnection facilities study; and A nonbinding good faith estimate of the cost to perform the facilities study. The interconnection facilities study shall identify: The electrical switching configuration of the equipment, including transformer, switchgear, meters, and other station equipment; The nature and estimated cost of the utility's interconnection facilities and distribution upgrades necessary to accomplish the interconnection, including engineering, procurement, construction, and overhead; and An estimate of the time required to complete the construction and installation of the facilities. Third-Party Design or Construction of Interconnection Facilities. The applicant and utility may agree to permit an applicant to separately arrange for a third party to design and construct the required interconnection facilities. The utility may review and approve the design of the facilities under the interconnection facilities study agreement. If the applicant and utility agree to separately arrange for design and construction, the utility, consistent with security and confidentiality requirements, shall make all relevant information and required specifications available to the applicant to permit the applicant to obtain an independent design and cost estimate for the interconnection facilities. The interconnection facilities shall be built in accordance with the specifications in the interconnection facilities study. Upon completion of the interconnection facilities study, and with the agreement of the applicant to pay for the interconnection facilities and distribution upgrades identified in the interconnection facilities study, the utility shall provide the applicant with an interconnection agreement within 5 business days. The utility may require a study deposit of the lesser of 50 percent of estimated nonbinding good faith study costs or $10,000. In cases where no interconnection upgrades are required, the interconnection facilities study shall be completed and the results shall be transmitted to the interconnection customer within 30 calendar days after the agreement is signed by the parties. In cases where interconnection upgrades are required, the interconnection facilities study shall be completed and the results shall be transmitted to the interconnection customer within 45 calendar days after the agreement is signed by the parties. Interconnection Agreement. When a utility determines, as a result of the interconnection studies conducted under a Level 4 review, that it is appropriate to interconnect the small generator facility, the utility shall provide the applicant with an interconnection agreement. The applicant shall have either 30 calendar days, or another mutually agreeable time frame after receipt of the interconnection agreement, to sign and return the interconnection agreement. If the applicant does not sign the interconnection agreement within 30 calendar days, the request shall be considered withdrawn unless the applicant and utility mutually agree to extend the time period for executing the interconnection agreement prior to the expiration of the 30-calendar-day period. A request for extension may not be unreasonably denied by the utility. After the interconnection agreement is signed by the applicant and utility, interconnection of the small generator facility shall proceed according to any milestones agreed to by the applicant and utility in the interconnection agreement. The utility shall approve the interconnection request and provide a permission to operate notice within 20 business days of receipt of acceptable documents, subject to the following conditions: All milestones agreed to in the interconnection agreement are satisfied; The small generator facility is approved by electric code officials with jurisdiction over the interconnection; The applicant provides a certificate of completion to the utility; Upon request of the utility, the applicant provides one or more photographs of the small generator facility site location, components, metering equipment, and other related facilities and equipment; and There is a successful completion of the witness test, if conducted by the utility. Level 4 Review Failure. If the interconnection request is denied, the utility shall provide the applicant a letter explaining the reasons for denying the interconnection request. The applicant and utility shall attempt to resolve all disputes regarding interconnection as provided in this regulation promptly, equitably, and in a good faith manner. Dispute Resolution Before the Commission. If a dispute arises, the applicant or utility may seek immediate resolution through the procedures of COMAR 20.32.01. Dispute resolution shall be conducted in an informal, expeditious manner to reach resolution with minimal costs and delay. If a dispute arises involving technical matters regarding the interconnection process, dispute resolution shall be delegated to the Commission’s Engineering Division. Pursuit of dispute resolution may not affect an applicant with regard to consideration of an interconnection request or an applicant's queue position. Any deadline imposed by the regulations in this chapter, which is directly affected by any issue in dispute, shall be suspended until resolution of the dispute. If a satisfactory resolution is not achieved between the applicant and utility, the applicant or utility may request a hearing, pursuant to Public Utilities Article, §3-102, Annotated Code of Maryland. A utility shall retain records of the following for a minimum of 7 years: The total number nameplate capacity and total fees charged for the interconnection requests received, approved, and denied under Level 1, Level 2, Level 3, and Level 4 reviews; The number of evaluations of interconnections requests approved and denied using any alternate process under Level 1, Level 2, Level 3, and Level 4 reviews; The fuel type, if appropriate, total number, and nameplate capacity of small generator facilities approved in each of the following categories: Net metering; Emergency standby capable of operating in parallel; Behind the meter load offset; Combined heat and power; Energy storage devices; and Other; The number of interconnection requests that were not processed within the deadlines established for Level 1, Level 2, Level 3, and Level 4 reviews in this chapter; The number of scoping meetings held, the number of feasibility studies, impact studies, and facility studies performed, and the fees charged for these studies; The justifications for the actions taken to deny interconnection requests; The number of interconnection requests that were not processed within the deadlines established for Level 1, Level 2, Level 3, and Level 4 reviews in this chapter due to a PJM Interconnection, LLC market process study; and Any special operating requirements required in interconnection agreements, which are permitted only for generating facilities with a nameplate capacity greater than 2 MW, that are not part of the utility's standard operating procedures applicable to small generator facilities. A utility shall retain records of interconnection studies it performs to determine the feasibility, system impacts, and facilities required by the interconnection of any small generator facility for a minimum of 7 years. A utility shall file not later than April 1 of each year a report entitled “Annual Small Generator Interconnection Report” to the Commission containing the following information for the preceding calendar year: The total number of interconnection requests received, approved, and denied under Level 1, Level 2, Level 3, and Level 4 reviews; The fuel type, or energy storage type, total number, and total nameplate capacity of small generator facilities approved in each of the following categories: Net metering; Emergency standby capable of operating in parallel; Behind the meter load offset; Combined heat and power; Energy storage devices; V2G Systems – DC EVSE; V2G Systems – AC EVSE; and Other; The number of interconnection requests that were not processed within the deadlines established for Level 1, Level 2, Level 3, and Level 4 reviews and permission to operate notices in this chapter; The total number of interconnection requests denied and the reason for each denial; Each interconnection request for a proposed small generator facility that received a cost estimate or incurred an actual cost of at least $10,000 for interconnection facilities or distribution upgrades and was completed during the reporting year, which shall include: A list of the nameplate capacity of the proposed small generator facility; Cost variance; Variance percentage; and If required, a summary explanation on why the actual cost of facilities or upgrades was at least 10 percent greater than the cost estimate provided; The number of scoping meetings held, the number of feasibility studies, impact studies, facility studies, and combined studies performed and the total fees charged for these studies; For each interconnection request for a proposed small generator facility that failed to meet Level 2 criteria according to Regulation .10F of this chapter, a list of the queue number, reason for failure to meet Level 2 criteria, if the applicant requested additional review, whether the additional review was completed within 30 calendar days, or if the applicant decided to request interconnection under Level 4 criteria; The current utility status and future plans and schedule for implementation of hosting capacity reporting systems or improvements to existing hosting capacity reporting systems; Beginning April 1, 2021, a utility shall also report annually for the previous year: The total number of restricted circuits and the total number of closed circuits; The number of interconnection requests totaled for Level 1, Level 2, Level 3, and Level 4 that were denied due to restricted circuits and the total number that were denied due to closed circuits; The number of interconnection requests for inadvertent export totaled for Level 1, Level 2, Level 3, and Level 4 that were approved, denied, or suspended due to non-compliance; The number of interconnection requests for flexible interconnection options totaled for Level 1, Level 2, Level 3, and Level 4 that were approved, denied, or suspended due to non-compliance; The number of cancelled small generator facility projects that result in interconnection costs to subsequent small generator facility projects in the same interconnection queue; and The number of small generator facility projects that delay payment for a distribution system upgrade until the time a first higher small generator facility project in an interconnection queue is ready to interconnect; Beginning April 1, 2024, if Volt-Watt control is implemented in a utility’s default utility required inverter settings profile, a utility shall also report for the electric distribution system annually for the previous year: Number of total interconnection customer complaints about smart inverter related curtailments; Number of smart inverter related curtailment interconnection customer complaints resolved by utility; Number of smart inverter related curtailment interconnection customer complaints resolved by customer; and Number of smart inverter related interconnection customer curtailment complaints unresolved; and Beginning April 1, 2025, an electric utility shall report exemptions to Regulation .06R of this chapter annually for the previous year, including: The number of interconnection requests subject to the PJM Interconnection, LLC Tariff; The number of interconnection requests in an area governed by a hosting capacity upgrade plan approved by the Commission; The number of interconnection requests on a dedicated primary voltage feeder that may not benefit any other interconnection customer; The number of interconnection requests on a dedicated secondary voltage facility that may not benefit any other interconnection customer; The number of interconnection requests on an AC distribution grid or spot network; The number of interconnection requests exempted for other good cause; and The reason for good cause for each interconnection request exempted from Regulation .06R of this chapter. The utility shall file a notice with the Commission describing any interconnection equipment the utility has considered field-approved for its distribution system within 90 days after granting approval for the interconnection of a small generator facility using the field-approved interconnection equipment. For any small generator facility receiving an interconnection impact study, the utility shall list and explain any study for which the cost of the actual upgrade exceeded the impact study’s estimate by at least 25 percent. For any small generator facility receiving an interconnection facilities study, the utility shall list and explain any study for which the cost of the actual upgrade exceeded the impact study’s estimate by at least 10 percent. Public Utilities Article, §§2-113, 2-121, 5-101, 5-303, 7-306, and 7-306.2, and 7-1004, Annotated Code of Maryland Effective date: June 9, 2008 (35:8 Md. R. 808) Regulation .01 amended effective October 8, 2018 (45:20 Md. R. 920); April 20, 2020 (47:8 Md. R. 436) Regulation .01B amended effective March 20, 2023 (50:5 Md. R. 183) Regulation .02B amended effective October 8, 2018 (45:20 Md. R. 920); April 20, 2020 (47:8 Md. R. 436) Regulation .03 amended effective October 8, 2018 (45:20 Md. R. 920) Regulation .04 amended effective October 8, 2018 (45:20 Md. R. 920) Regulation .04E repealed effective April 20, 2020 (47:8 Md. R. 436) Regulation .05 amended effective April 20, 2020 (47:8 Md. R. 436) Regulation .06 amended effective October 8, 2018 (45:20 Md. R. 920); April 20, 2020 (47:8 Md. R. 436); March 20, 2023 (50:5 Md. R. 183) Regulation .07B amended effective April 20, 2020 (47:8 Md. R. 436) Regulation .08 amended effective October 8, 2018 (45:20 Md. R. 920); April 20, 2020 (47:8 Md. R. 436) Regulation .09 amended effective April 20, 2020 (47:8 Md. R. 436) Regulation .09A, E amended effective October 8, 2018 (45:20 Md. R. 920) Regulation .10 amended effective October 8, 2018 (45:20 Md. R. 920) Regulation .10A, G amended effective April 20, 2020 (47:8 Md. R. 436) Regulation .11 amended effective October 8, 2018 (45:20 Md. R. 920) Regulation .11E amended effective April 20, 2020 (47:8 Md. R. 436) Regulation .12 amended effective October 8, 2018 (45:20 Md. R. 920) Regulation .12E, F amended effective April 20, 2020 (47:8 Md. R. 436) Regulation .13C amended effective October 8, 2018 (45:20 Md. R. 920) Regulation .14 amended effective October 8, 2018 (45:20 Md. R. 920); April 20, 2020 (47:8 Md. R. 436) Regulation .14C amended effective March 20, 2023 (50:5 Md. R. 183) Chapter revised effective December 12, 2024 (Md. R. 51:24 1082) Regulation .02B amended effective July 7, 2025 (52:13 Md. R. 657) Regulation .06N amended effective July 7, 2025 (52:13 Md. R. 657) Regulation .06S adopted effective July 7, 2025 (52:13 Md. R. 657) Regulation .14C amended effective July 7, 2025 (52:13 Md. R. 657) Net Energy Metering. An electric company shall provide net metering of electric service to eligible customer-generators using a meter capable of net energy metering until the rated generating capacity of all eligible customer-generators in the State reaches 1,500 megawatts. Maximum Size of Electric Generating System — Net Metering. An electric company may not provide net energy metering to an eligible customer-generator operating an electric generating system that has a rated capacity of more than 2 megawatts. Micro Combined Heat and Power Electric Generating System. An electric company may not provide net energy metering to an eligible customer-generator operating a micro combined heat and power electric generating system that has a rated capacity of more than 30 kilowatts. Qualifying for Net Energy Metering. In order to initially qualify for net energy metering: An eligible customer-generator shall comply with the provisions of COMAR 20.50.09; and The eligible customer-generator’s proposed electric generating system may not exceed 200 percent of the eligible customer-generator’s baseline annual usage. Upgraded Electric Generating Systems. When an eligible customer-generator receiving net energy metering proposes an upgrade to an existing electric generating system, an electric company shall re-evaluate the baseline annual usage to determine whether the electric generating system continues to meet the requirements of §D(1)(b) of this regulation. If the eligible customer-generator’s upgraded electric generating system does not meet the requirements of §D(1)(b) of this regulation, an electric company may discontinue net energy metering. An electric company shall ensure that a meter installed for net energy metering is capable of measuring the flow of electricity in two directions. An electric company shall offer net energy metering service to an eligible customer-generator under a Commission-approved standard contract or tariff. An electric company’s tariff or contract for net metering shall contain an energy rate, a rate structure, and any monthly charge identical to the monthly contract or tariff charge paid by a customer of the rate class in which the eligible customer-generator would be a member if they were not receiving net energy metering service. An electric company may not include in an eligible customer-generator’s bill rates, charges or fees that raise the eligible customer-generator’s minimum monthly charge above that of customers of the same rate class to which the eligible customer-generator would otherwise be assigned. An electric company may not charge to an eligible customer-generator new or additional demand charges, standby charges, customer charges, or minimum monthly charges. An electric company may not require an eligible customer-generator whose electric generating system meets the requirements of this chapter to: Install additional controls; Perform or pay for additional tests; or Purchase additional liability insurance. Net Energy Calculation. An electric company shall calculate net energy in accordance with this regulation. Metering Net Energy — The electric company shall meter net energy produced or consumed on a regular basis in accordance with standard metering practice under this subtitle. Time-Varying Rates. For eligible customer-generators whose applicable tariff includes time-varying rates, an electric company may calculate net energy separately for each applicable rate period during a billing cycle. An electric company may apply §§D, E, and F of this regulation separately for each rate period for an eligible customer-generator whose applicable tariff bills using time-varying rates. If net generation is calculated separately for each applicable rate period during a billing cycle, an electric company shall apply §§E and F of this regulation separately for each rate period for an eligible customer-generator whose applicable tariff bills using time-varying rates. Energy Usage Exceeds Generation — Billing. If the electricity used by an eligible customer-generator exceeds the electricity generated by the eligible customer-generator in a billing month, an electric company shall bill the eligible customer-generator for usage under the terms of Regulation .03 of this chapter. Generation Exceeds Usage — Billing. If the electricity generated by an eligible customer-generator exceeds the customer’s usage, an electric company shall only bill the eligible customer-generator a customer charge. Conversion of Excess Generation — Billing. An electric company shall convert any excess electric generation described in §E of this regulation into generation credits upon billing, consistent with the provisions of Regulation .05 of this chapter. Commercial Customers. An electric company shall use the net hourly energy consumed or produced to assign the energy requirement for commercial eligible customer-generators with interval metering equipment. PJM shall use the net energy metered each hour, positive or negative, for the settlement process, even in cases when the total usage by the customer in a month exceeds the electricity generated by a commercial eligible customer-generator with interval metering equipment. Generation Conversion — Dollar Amount. An electric utility shall convert an eligible customer-generator’s net excess generation to a dollar amount according to this regulation. Conversion Calculation. Except as provided in §C of this regulation, an electric company shall convert net excess generation from kilowatt-hours to dollars by multiplying the net excess generation by the generation or commodity portion of the rate that the eligible customer-generator would have been charged by the electric company averaged over the previous 12-month period ending with the billing cycle that is complete immediately prior to the end of April. For customers served by an electricity supplier, the utility shall convert net excess generation in the same manner as described in §B(1) of this regulation except that the dollar value of the net excess generation shall be equal to the generation or commodity rate that the customer would have been charged by the electricity supplier multiplied by the number of kilowatt-hours of net excess generation. Cooperative Electric Company — Conversion Calculation. When net energy metering is provided by a cooperative electric company that serves a population of less than 250,000 in its distribution territory, the eligible customer-generator may choose to be paid for the dollar value of net excess generation remaining at the end of each month instead of at the end of the accrual period specified in §F of this regulation. If an eligible customer-generator chooses to be paid for the dollar value of net excess generation remaining at the end of each month: The customer-generator may accrue net excess generation on a monthly basis; The dollar value of the net excess generation shall be equal to the generation or commodity portion of the rate that the eligible customer-generator would have been charged by the electric company for the previous month multiplied by the number of kilowatt-hours of excess generation; and On or before 30 days after the end of each month, the electric cooperative shall pay the eligible customer-generator for the dollar value of net excess generation remaining at the end of the previous month. Net Excess Generation — Carry Forward. An electric company shall carry forward accrued net excess generation on a customer’s bill until the net excess generation has been used by the customer or the electric company has paid the customer for the credit under §F of this regulation. Time-Varying Rates—Carry Forward. For customers on a time-varying rate, an electric company may calculate net excess generation separately for each applicable rate period during a billing cycle. An electric company may carry forward net excess generation separately for each rate period until the net excess generation has been used by the customer or the electric company has paid the customer for the credit under §F of this regulation. Payment for Generator Credits. On or before 30 days after the billing cycle that is complete immediately prior to the end of April of each year, the electric company shall pay each eligible customer-generator for the dollar value of any accrued net excess generation remaining at the end of previous 12-month period ending with the billing cycle that is complete immediately prior to the end of April. On the closure of a net energy metering account of an eligible customer-generator, an electric company shall pay an eligible customer-generator the dollar value of the net excess generation on their account within 15 days. An electric generating system used by an eligible customer-generator for net energy metering shall meet all applicable safety and performance standards incorporated by reference in COMAR 20.50.02.02. When requested in writing by a qualified eligible customer-generator under §B of this regulation, an electric utility shall provide meter aggregation. Customers Qualifying for Aggregation. The following electric utility eligible customer-generators are qualified to request meter aggregation under §A of this regulation: An eligible customer-generator using electrical service for agriculture; An eligible customer-generator who is a not-for-profit organization or a not-for-profit business; or An eligible customer-generator who is a municipal or county government or its affiliated organizations. An electric company shall require that an eligible customer-generator requesting meter aggregation under this regulation provide written allocation instructions detailing how to distribute its excess generation credits to each account prior to the commencement of any meter aggregation. This regulation applies to an eligible customer-generator qualifying for meter aggregation under Regulation .07 of this chapter. Virtual Meter Aggregation. If an aggregation qualified eligible customer-generator’s electrical services are not located close enough to physically interconnect metered service, the electric company shall sum the usage and excess generation of all applicable accounts on a kilowatt-hour basis over each billing period prior to calculating the customer’s excess generation for that billing period. The electric company shall allocate generated electricity to each account per the instructions of the eligible customer-generator. Physical Meter Aggregation. For an aggregation qualified eligible customer-generator whose electrical services are located close enough to physically interconnect and meter at a single point, the electric company shall allow the customer to make physical electrical connections and re-establish metering at a single location. Physically aggregated services must meet all applicable requirements of COMAR 20.50.01 and 20.50.02. The electric company shall allocate the net-energy used each billing period and the excess generation credit calculated each billing period to each account per the instructions of the customer. Public Utilities Article, §§2-113, 2-121, 5-101, 5-303, and 7-306, Annotated Code of Maryland Effective date: Regulations .01—.04 and Regulations .06—.08 adopted effective September 5, 2011 (38:18 Md. R. 1078) Regulation .04 amended effective September 16, 2024 (51:18 Md. R. 810) Regulation .05 adopted effective February 20, 2012 (39:3 Md. R. 260) Regulation .05 amended effective September 16, 2024 (51:18 Md. R. 810) Regulation .07B amended effective July 18, 2016 (43:14 Md. R. 780) Within 60 days after the effective date of these regulations, each electric company shall file for Commission approval: A list and location map for all CVRZs within its service territory, if applicable; or If no CVRZs are designated in its service territory, its voltage survey plan. Within 30 days after the Commission approves a CVRZ or CVRZs within an electric company’s service territory, the electric company shall file its voltage survey plan for Commission approval. Upon approval of the electric company’s voltage survey plan, the electric company shall conduct an initial contact voltage survey of each CVRZ within 1 year of the approval and shall conduct subsequent contact voltage surveys of each CVRZ as set forth in its voltage survey plan. The electric company shall conduct its initial and each subsequent contact voltage survey within each Commission-approved CVRZ of: All publicly accessible electric distribution plant and electric company-owned or-maintained streetlights that are capable of conducting electricity; Municipal-owned or governmental-owned streetlights and traffic signals that are publicly accessible and are capable of conducting electricity, if the consent of the municipal government or other appropriate governmental authority is received; and All objects and surfaces that are publicly accessible in public parks and playgrounds and that are capable of conducting electricity, if the consent of the municipal government or other appropriate governmental authority is received. At least 60 days prior to implementing any material change to its voltage survey plan, the electric company shall file for Commission approval. For areas within each electric company’s service territory which are not located in a CVRZ, the electric company shall perform an initial contact voltage survey within 3 years of the approval of the voltage survey plan on all publicly accessible electric distribution plant, except for wooden poles, and publicly accessible electric company-owned or-maintained streetlights that are capable of conducting electricity. Subsequent contact voltage surveys for all equipment capable of conducting electricity shall be conducted in accordance with the voltage survey plan. Streetlights shall be tested for contact voltage after dark or when the light is illuminated. The Commission may increase or decrease the frequency or scope of any contact voltage survey requirement upon a showing of good cause. Contact voltage readings shall be conducted in accordance with acceptable methods described in the Institute of Electrical and Electronic Engineers Standard 1695 — 2016. Each electric company shall include in its voltage survey plan all equipment used for detecting contact voltage. The type of equipment shall be certified by an independent test laboratory as being able to reliably detect voltages of 6 to 600 volts and this certification shall be included with the electric company’s voltage survey plan filing. Each electric company shall make an area safe after detecting a potential contact voltage condition during its contact voltage survey until the potential condition can be confirmed under §B of this regulation. Each electric company shall confirm and document all contact voltage detected in its contact voltage survey using a voltmeter and a 500 ohm shunt resistor. For each contact voltage measurement under §B of this regulation greater than or equal to one volt (60 Hertz Alternating Current), each electric company shall: Perform a contact voltage survey on all objects and surfaces that are capable of conducting electricity and are publicly accessible within a minimum 30 foot radius of the location of the measured contact voltage; When an electric distribution plant or an electric company-owned or-maintained streetlight is indicating contact voltage, immediately and continuously make the area safe, and use best efforts to make a permanent repair to mitigate the contact voltage as soon as possible, but not later than 45 days, however, a temporary measure to mitigate contact voltage may last longer than 45 days in extraordinary circumstances provided the area remains safe; When non-electric company property is indicating contact voltage, immediately use best efforts to make the area safe and immediately use best efforts to notify the customer or responsible person associated with the premises or the customer-owned facility of the unsafe condition and the need for the customer to make a permanent repair to mitigate contact voltage; and Maintain written records of its actions to make the area safe and to mitigate the contact voltage. Each electric company shall file, on a form approved by the Commission, an annual compliance report with the Commission: Describing the results of its contact voltage surveys; and Summarizing each known contact voltage electric shock and each contact voltage electric shock complaint received from a member of the public, whether the shock affected a person or animal. An initial compliance report shall be filed at the direction of the Commission and subsequent compliance reports shall be filed on or before April 1 of each year for the preceding calendar year. An electric company’s failure to comply with this subtitle may subject the company to civil penalties under the Public Utilities Article. The Commission may, in its discretion, waive or modify any provision of this subtitle and may also impose additional requirements as circumstances warrant. Public Utilities Article, §§2-113, 2-121, 5-101, and 5-303, Annotated Code of Maryland Effective date: November 28, 2011 (38:24 Md. R. 1503) Regulation .01I adopted effective August 21, 2023 (50:16 Md. R. 728) These regulations apply to an electric company under Commission jurisdiction with a total number of 40,000 or more customers served in Maryland. Reliability Data. Each utility shall collect and maintain the data required to: Provide in its annual performance reports the reliability information specified in this regulation; and Demonstrate compliance with the reliability standards. Reliability Reporting Period. Except as otherwise provided in §B(2) of this regulation, the data used by a utility to determine annual reliability performance shall be from the immediately preceding calendar year. The data used by a utility to determine the poorest performing feeders and multiple device activations shall include outage data from the 12-month period ending September 30 of the immediately preceding calendar year. Reliability Standards — System-Wide Indices. A utility shall collect and maintain the data necessary to report CAIDI, SAIDI, and SAIFI for its system and each operating district, consisting of all feeders assigned to Maryland under Regulation .03D of this chapter. For an investor-owned utility, each index shall be calculated and reported in the annual performance report using the following sets of input data: All interruption data, including and excluding planned outages; All interruption data minus major outage event interruption data; and For the calendar year 2020 and each calendar year thereafter, all interruption data minus the Institute of Electrical and Electronics Engineers’ (IEEE) major event days. For cooperatively owned utilities, each index shall be calculated and reported in the annual performance report using the following sets of input data: All interruption data, including and excluding planned outages; All interruption data minus major outage event interruption data; For the calendar year 2020 and each calendar year thereafter, all interruption data minus the Institute of Electrical and Electronics Engineers’ (IEEE) major event days; All interruption data minus major outage event interruption data and minus outage data resulting from an outage event occurring on another utility’s electric system; and For the calendar year 2020 and each calendar year thereafter, all interruption data minus the Institute of Electrical and Electronics Engineers’ (IEEE) major event days minus outage data resulting from an outage event occurring on another utility’s electric system. SAIDI and SAIFI Standards. The SAIDI in minutes and SAIFI reliability standards for the calendar years noted and thereafter, unless changed by the Commission, are as follows: Each investor-owned utility's annual SAIDI and SAIFI reliability standard shall be measured against its system-wide annual SAIDI and SAIFI result, including all interruption data minus major outage event interruption data and consisting of all feeders assigned to Maryland under Regulation .03D of this chapter. For the calendar year 2020 and each calendar year thereafter, each investor-owned utility’s annual SAIDI and SAIFI reliability standard shall be measured against its system-wide annual SAIDI and SAIFI result, including all interruption data minus the Institute of Electrical and Electronics Engineers’ (IEEE) major event days and consisting of all feeders assigned to Maryland under Regulation .03D of this chapter. Each cooperatively owned utility's annual SAIDI and SAIFI reliability standard shall be measured against its system-wide annual SAIDI and SAIFI result, including all interruption data minus major outage event interruption data and minus outage data resulting from an outage event occurring on another utility's electric system. For the calendar year 2020 and each calendar year thereafter, each cooperatively owned utility’s annual SAIDI and SAIFI reliability standard shall be measured against its system-wide annual SAIDI and SAIFI result, including all interruption data minus the Institute of Electrical and Electronics Engineers’ (IEEE) major event days minus outage data resulting from an outage event occurring on another utility’s electric system. A utility's annual SAIDI result shall be equal to or less than its annual SAIDI reliability standard established in §D(1) of this regulation. A utility's annual SAIFI result shall be equal to or less than its annual SAIFI reliability standard established in §D(1) of this regulation. SAIDI and SAIFI Standards after 2015. For the calendar year 2016 and each calendar year thereafter, the Commission shall establish SAIDI and SAIFI reliability standards and any other appropriate reliability requirements for each utility. By March 1, 2014 and every 4 years thereafter, unless otherwise directed by the Commission, each utility: Shall file proposed annual SAIDI and SAIFI reliability standards for its Maryland service territory; Shall file corresponding cost estimates associated with meeting the proposed SAIDI and SAIFI reliability standards as specified by the Commission; and May propose any other appropriate reliability requirement for the Commission’s consideration along with supporting comments. The proposed annual SAIDI and SAIFI reliability standards filed by each utility shall be for a 4-calendar-year period, at a minimum. If a utility fails to satisfy the standard §D(6) or (7) of this regulation, it shall provide a corrective action plan, preferably in its annual performance report but by no later than April 1. Poorest Performing Feeder Standard for Feeders Assigned to Maryland. A utility shall report in its annual performance report CAIDI, SAIDI, and SAIFI indices for all feeders assigned to Maryland that are identified by the utility as having the poorest feeder reliability. For each utility, each index shall be calculated and reported in the annual performance report using all interruption data, and all interruption data minus the following exclusions: Source loss, including any outage that occurs on the feeder by an event occurring external to the feeder; Major outage events; and Planned outages. For each utility, the feeders with poorest reliability shall be all feeders having circuit reliability performance 250 percent or more above the utility’s System-Wide SAIFI and SAIDI, which shall be calculated in accordance with the exclusions identified in §A(2) of this regulation. No feeder shall appear in a utility’s list of poorest performing feeders during three consecutive 12-month reporting periods, unless the utility has undertaken reasonable remediation measures to improve the performance of the feeder. Poorest Performing Feeder Standard for Feeders Not Assigned to Maryland. For each feeder not assigned to Maryland that serves more than ten Maryland customers, the utility shall report the feeder in its annual performance report and the feeder’s CAIDI, SAIDI, and SAIFI indices, if the feeder would have been included on the poorest performing feeder list but for the fact that the feeder is not assigned to Maryland. For each feeder included in §B(1) of this regulation, the utility shall report the number of customers located in Maryland and the number of customers located in a bordering jurisdiction. For each feeder reported in §B(1) of this regulation, the utility shall implement reasonable remediation measures to improve the performance of the feeder portion serving Maryland customers, which measures shall be described by the utility in its annual performance report. If implementing a remediation plan is not reasonable, the utility shall provide an explanation of its decision in its annual performance plan. The reliability indices and method for identifying the performance of feeders under this provision shall be consistent with §A(2), (3), and (4) of this regulation. Evaluation of Remedial Actions. For the feeders that are identified as having the poorest performance, the utility shall provide the following information: In the annual performance report in which the feeders are identified as requiring reasonable remediation measures, a brief description of the actions taken or proposed, if any, to improve reliability and the actual or expected completion date of the action; and In the five subsequent annual performance reports, the performance of the feeder shall be reported with its performance ranking. Feeders Assigned to Maryland. All feeders of a utility that serve only Maryland customers are assigned to Maryland. For a utility that has one or more feeders that serve a Maryland customer and at least one customer in a bordering jurisdiction: The feeders used in determining the utility’s system-wide SAIDI and SAIFI performance results as reported to the Commission by the utility’s 2010 annual reliability report shall be assigned to Maryland unless otherwise directed by the Commission; The utility may not change the assignment list without Commission approval; and For a new feeder added to the utility's system, or an existing feeder that is modified, that serves more than ten Maryland customers and at least one customer in a bordering jurisdiction, the utility shall file notice with the Commission advising of the feeder's assignment. If a utility fails to satisfy the standard in §A(4) of this regulation with respect to a feeder assigned to Maryland, it shall provide a corrective action plan, preferably in its annual performance report but by no later than April 1. Each utility shall report in its annual performance report the number of protective devices that activated five or more times during the prior 12-month reporting period specified in Regulation .02B(2) of this chapter causing sustained interruptions in electric service, excluding major outage events and planned outages, to more than ten Maryland customers. For each device referenced in §A of this regulation, the utility shall evaluate and report in its annual performance report the cause for the multiple activations. For each device referenced in §A of this regulation, the utility shall implement reasonable remediation measures to reduce the number of activations and describe the measures in its annual performance report. For each device referenced in §A of this regulation, the device shall not experience five or more activations, including all customer sustained interruption data, during three consecutive 12- month reporting periods, unless the utility has undertaken reasonable remediation measures to improve the performance of the device. If a utility fails to satisfy the standard in §D of this regulation, it shall provide a corrective action plan, preferably in its annual performance report but by no later than April 1. A utility shall calculate and report in its supplemental annual performance report the following annual reliability information for its Maryland service territory: All IEEE major event days; Dates of all IEEE major event days; and Number of customers impacted by the IEEE major event day events. A utility shall calculate and report in its supplemental annual performance report an annual (CEMIn) for customers experiencing two or more (CEMI2), four or more (CEMI4), six or more (CEMI6), and eight or more (CEMI8) sustained interruptions unless it does not have the means to make the calculation, in which case it shall provide an explanation of the reason, and an estimate of the cost to provide the information in the future. A utility shall calculate and report: CEMI2, CEMI4, CEMI6, CEMI8, excluding major outage events; and CEMI2, CEMI4, CEMI6, CEMI8, including major outage events. A utility shall calculate and report in its supplemental annual performance report an annual (MAIFIE) for its Maryland service territory unless it does not have the means to make the calculation, in which case it shall provide MAIFI and an explanation of the Utility’s limitation as well as estimated cost to furnish MAIFIE information going forward. A utility shall calculate and report: MAIFIE excluding major outage events; and MAIFIE including major outage events. During each calendar year, a utility shall restore service within 8 hours, measured from when the utility knew or should have known of the outage, to at least 92 percent of its customers experiencing sustained interruptions during normal conditions. During each calendar year, a utility shall restore service within 50 hours, measured from when the utility knew or should have known of the outage, to at least 95 percent of its customers experiencing sustained interruptions during major outage events where the total number of sustained interruptions is less than or equal to 400,000 or 40 percent of the utility's total number of customers, whichever is less. If more than one major outage event subject to the standard set forth in §B of this regulation occurs during a calendar year, the restoration percentage shall be calculated by giving equal weight to all sustained interruptions occurring during the major outage events. During each calendar year, a utility shall restore service as quickly and safely as permitted to its customers experiencing sustained interruptions during each major outage event in which the total number of sustained interruptions is greater than 400,000 or 40 percent of the utility's total number of customers, whichever is less. If a utility fails to satisfy the standard in §A, B or D of this regulation during the previous calendar year, it shall provide a corrective action plan, preferably in its annual performance report but by no later than April 1. In the calendar year these regulations become effective, §§A and B of this regulation shall apply from the effective date of the regulations until the end of the calendar year. Considering data for normal and major outage event conditions for a calendar year, each utility shall respond to a government emergency responder guarded downed electric utility wire within 3 hours after notification by a fire department, police department, or 911 emergency dispatcher at least 90 percent of the time. If a utility fails to satisfy the standard in §A of this regulation during the previous calendar year, it shall provide a corrective action plan, preferably in its annual performance report but by no later than April 1. Each utility shall coordinate its response to a government emergency responder guarded downed electric wire consistent with any program established by a fire department, police department, or 911 emergency dispatcher. Each utility shall exercise reasonable care to reduce the potential hazard caused by a downed electric wire to which its employees, its customers, and the general public may be subjected. Customer Telephone Call Answer Time Standard. Each utility shall answer within 30 seconds, on an annual basis, at least 75 percent of all calls offered to the utility for customer service or outage reporting purposes. Abandoned Call Rate Standard. Each utility shall achieve an annual average abandoned call percentage rate of 5 percent or less, calculated by dividing the total number of abandoned calls by the total number of calls offered to the utility for customer service or outage reporting purposes. Busy Signals. Each utility shall design its telecommunications systems to accommodate expected volumes of customer calls with minimal or, if possible, no customer busy signals during both normal conditions and major outage events. Other Customer Communications Information. Each utility shall state in its supplemental annual performance report: Based solely upon those calls offered to its customer service representatives: The percentage of calls that are answered within 30 seconds; and The abandoned call percentage rate; and The average speed of answer, which shall be calculated by dividing the total amount of time callers spend in queue after requesting to speak to a customer service representative through the automated voice response system by the total number of calls handled, including calls handled by the automated voice response system. First Call Resolution. Each utility shall measure the percentage of customer issues resolved that are reported to the utility in a single interaction with its customer service representatives. Average Handling Time. Each utility shall measure an average amount of time needed to resolve a customer’s request. This includes any time spent on holds, delays, or follow-up actions necessary to fulfill the customer’s needs. Vulnerable Individuals Notified Before Storms. Each utility shall measure the percentage of vulnerable individual customers notified in advance of a storm event. Customer Communications Standards Period. Each standard in this regulation is measured using the 12-month period ending December 31. For the calendar year in which the regulations become effective, the standards shall be measured from the date the regulations are effective until and including December 31 of that year for reporting purposes only. Reporting. Each utility shall report its year-ending performance in its annual performance report. Except as otherwise set forth in §D of this regulation, the standards in this regulation shall apply to customer calls offered to or received by a utility's call overflow system or a third-party vendor retained by the utility. Corrective Action Plan. If a utility fails to satisfy the standard in §A, B or C, of this regulation, it shall provide a corrective action plan, preferably in its annual performance report but by no later than April 1. Intent and Scope. It is the intent of the Commission that a utility engage in vegetation management programs that are necessary and appropriate to maintain safety and electric system reliability. The standards set forth in this regulation shall constitute minimum vegetation management requirements applicable to utilities in the State, and are not intended to supersede or prohibit a utility’s implementation of more aggressive vegetation management standards and practices. The vegetation management requirements in this chapter apply to the extent not limited by contract rights, property rights, or any controlling law or regulation of any unit of State or local government. This regulation applies to any electric transmission plant not regulated by the Federal Energy Regulatory Commission. Technical Standards for Vegetation Management. Each utility shall ensure that vegetation management conducted on its energized plant is performed in accordance with the standards applicable to Maryland Licensed Tree Experts, which are incorporated by reference under COMAR 08.07.07.02. Each utility’s vegetation management program shall address, at a minimum, all of the following activities: Tree pruning and removal; Vegetation management around poles, substations, and energized overhead electric plant; Manual, mechanical, or chemical vegetation management along rights-of-way; Inspection of areas where vegetation management is performed after the vegetation management; Cultural control practices; Public education regarding vegetation management practices; Public and customer notice of planned vegetation management activities; and Debris management during routine vegetation management and during outage restoration efforts. Each utility using a call center to handle vegetation management calls shall adopt a script or job aid that is specifically catered to vegetation management practices for usage by call center representatives. Each utility shall perform periodic reviews of its vegetation management complaints with the goal of improving its complaint resolution process, as necessary. Each utility shall develop its own vegetation management program, which shall be consistent with this regulation. In developing the program, a utility shall conduct its vegetation management and determine the extent and priority of vegetation management to be performed at a particular site based on these factors: The extent of the potential for vegetation to interfere with poles, substations, and energized overhead electric plant; The voltage of the affected energized conductor, with higher voltages requiring larger clearances; The relative importance of the affected energized conductor in maintaining safety and reliability; The type of conductors and type of overhead construction; The likely regrowth rate for each species of vegetation at the site; The potential movement of energized conductors and vegetation during various weather conditions; The utility’s legal rights to access the area where vegetation management is to be performed; The maturity of the vegetation; The identification of the structural condition of the vegetation, including the characteristics of a species as one having a high probability of causing a service interruption during weather events; State and local statutes, regulations, or ordinances affecting utility performance of vegetation management; Customer or owner of the property acceptance of the proposed vegetation management where the utility does not have legal rights to perform vegetation management; and Any other appropriate factor approved by the Commission. Each utility shall file a copy of its vegetation management program with the Commission within 90 days of the effective date of this regulation. If a utility makes a change in its vegetation management program, the utility shall file a copy of the change with the Commission no later than 30 days prior to implementing the change, unless exigent circumstances warrant implementation without prior notice, in which case the change shall be filed by no later than 30 days after implementation. Training, Record Keeping, and Reporting. Each utility shall adopt standards, to the extent not covered by other existing law, to be used by all persons who perform vegetation management for the utility, whether employees or contractors, for the proper care of trees and other woody plants, including safety practices and line clearance techniques. The utility shall monitor and document scheduled vegetation management and related activities the utility or its contractor performs. Documentation shall include, but is not limited to: Identification of each circuit or substation or, if applicable, both circuit and substation where vegetation management was performed; The type of vegetation management performed including removal, trimming, and spraying and methods used; The name of the Maryland Licensed Tree Expert responsible for oversight of vegetation management at the circuit or substation level; The approximate date of activity; Any occurrence resulting in serious injury to a person as a result of vegetation management activities; and When a utility seeks to remove a tree or limb, but is unable to do so because permission or cooperation is not obtained. Each utility shall include a summary of the information required under §C(2) of this regulation about its vegetation management during the preceding calendar year, and shall describe vegetation management planned for the current calendar year, as part of the annual performance report required to be filed with the Commission under Regulation .11 of this chapter. The annual performance report also shall include: Expenditures for vegetation management measured using all-in vegetation management costs in the preceding calendar year; Vegetation management budget for the current calendar year; Circuits or substations, completion dates, and the estimated number of overhead circuit miles trimmed in the preceding calendar year in compliance with the cyclical vegetation management requirements set forth under §F of this regulation; Circuits or substations and the estimated number of overhead circuit miles scheduled for the current calendar year in compliance with the cyclical vegetation management requirements set forth under §F of this regulation; Total overhead circuit miles for the system; and If applicable, a corrective action plan, preferably in its annual performance report or, if necessary, in the supplemental annual performance report. Each utility shall report its own violation of this chapter to the Commission within 60 days of discovery and include its plan for correcting each violation. Public Notice of Planned Vegetation Management. Each utility shall make a reasonable attempt to notify an owner or occupant of all properties upon which cyclical, planned vegetation management is to be performed. This requirement will be satisfied if the utility provides notice to affected property owners or occupants at least 7 days, but not more than 120 days, prior to performing cyclical, planned vegetation management activity. Notice shall be provided by direct mailing, door hanger, postcard, personal contact, or a different method if approved by the Commission, but may not be made solely by bill insert. All direct mailings, door hangers, postcards, or any other method approved by the Commission shall include the contact information of a dedicated group for customers to call for further information. Nothing in this regulation prohibits a utility from using more than one of these methods. Each utility or its contractor shall provide written notice of any cyclical, planned vegetation management activities to a primary contact for each county and municipality affected at least 2 months before commencing the activities unless the county or municipality notifies the utility that written notification is not required. Each utility shall include on its website general information about upcoming vegetation management planned work and shall include a link or reference to the Maryland Department of Natural Resources’ website for additional information about tree experts and related information. For all tree removals that have been readily identified on residential properties, each utility shall proactively contact the customer or owner of the property to discuss the removal of the tree prior to performing the work. Each utility shall provide the option for customers or the owner of the property to have direct communication with a utility vegetation management representative within 7 business days. Outreach Programs. Each utility shall conduct an annual public education program to inform its customers, as well as a primary contact for each county and municipality in the utility’s service territory, of the importance of vegetation management, and of the utility’s role and responsibility in managing vegetation near electric lines, poles, and substations. The public education program required under this section shall be implemented by direct mail, bill inserts, or a different method if approved by the Commission. Each utility shall post its vegetation management public education materials on its website. Specific Requirements. Each utility shall perform vegetation management based on the following schedule: Initially beginning on January 1 of the year immediately following the effective date of this regulation, a utility on a 4-year trim cycle shall within: 12 months perform vegetation management on not less than 15 percent of its total distribution miles; 24 months perform vegetation management on not less than 40 percent of its total distribution miles; 36 months perform vegetation management on not less than 70 percent of its total distribution miles; and 4 years perform vegetation management on not less than 100 percent of its total distribution miles. Initially beginning on January1 of the year immediately following the effective date of this regulation, a utility on a 5-year trim cycle shall within: 12 months perform vegetation management on not less than 12 percent of its total distribution miles; 24 months perform vegetation management on not less than 32 percent of its total distribution miles; 36 months perform vegetation management on not less than 56 percent of its total distribution miles; 48 months perform vegetation management on not less than 75 percent of its total distribution miles; and 5 years perform vegetation management on not less than 100 percent of its total distribution miles. Each utility shall follow the vegetation management performance requirement under §F(1) or (2) of this regulation for each subsequent trim cycle. Vegetation management shall be performed based on the factors set forth under §B(3) of this regulation. The following minimum clearances shall be obtained at the time vegetation management is conducted to the extent not limited by contract rights, property rights or other controlling legal authority: Horizontal clearances: Greater than 34.5 kV: The clearance from the conductors shall be the greater of 15 feet or 4 years’ growth if using a 4-year trim cycle (or 5 years’ growth if using a 5-year trim cycle). Horizontal clearance beneath the conductors shall be measured radially. From 14 kV to 34.5 kV: The clearance from the conductors shall be the greater of 10 feet or 4 years’ growth if using a 4-year trim cycle (or 5 years’ growth if using a 5-year trim cycle). Horizontal clearance beneath the conductors shall be measured radially. Less than 14 kV but at least 600 volts: The clearance from the conductors shall be 4 years’ growth if using a 4-year trim cycle (or 5 years’ growth if using a 5-year trim cycle). Horizontal clearance beneath the conductors shall be measured radially. For a conductor with a voltage from 14 kV to 34.5 kV which is operated only as a distribution feeder, the horizontal clearance shall be as set forth under §G(1)(c) of this regulation as if its voltage were less than 14 kV but at least 600 volts. The horizontal clearances are the minimum clearances the utility shall establish during each cyclical planned vegetation management trim cycle. Vertical clearances: Greater than 34.5 kV: The vertical clearance above the conductors shall be established by removing all overhanging limbs within the maximum horizontal clearance zone specified under §G(1)(a) of this regulation. The vertical clearance below the conductors shall be the greater of 15 feet or 4 years’ growth (or 5 years’ growth if using a 5-year trim cycle). The vertical clearance below the conductors shall be measured radially. See Figure No. 1 From 14 kV to 34.5 kV: The vertical clearance above the conductors shall be established by removing all overhanging limbs above the conductors within the horizontal clearance zone specified under §G(1)(b) of this Regulation. The vertical clearance below the conductors shall be the greater of 10 feet or 4 years’ growth (or 5 years’ growth if using a 5-year trim cycle). The vertical clearance below the conductors shall be measured radially. See Figure No. 2. Less than 14 kV but at least 600 volts: Multiple open wires on a cross-arm or armless construction from the substation to the first protective device: The vertical clearance above the conductors shall be established by removing all overhanging limbs above the conductors within the horizontal clearance zone specified under §G(1)(c) of this regulation. The vertical clearance below the conductors shall be 4 years’ growth (or 5 years’ growth if using a 5-year trim cycle). The vertical clearance below the conductors shall be measured radially. See Figure 3. Except as provided in §G(2)(c)(i) for multiple open wires on a cross-arm or armless construction, the vertical clearance above the conductors shall be 15 feet. The vertical clearance below the conductors shall be 4 years’ growth (or 5 years’ growth if using a 5-year trim cycle). The vertical clearances above and below the conductor shall be measured radially. Spacer cable, tree wire with messenger cable above, aerial cable, and single-phase: The vertical clearance above the conductors shall be 6 feet. The vertical clearance below the conductors shall be 4 years’ growth (or 5 years’ growth if using a 5-year trim cycle). The vertical clearance above and beneath the conductors shall be measured radially. For a conductor with a voltage from 14 kV to 34.5 kV which is operated only as a distribution feeder, the vertical clearance shall be as set forth in the corresponding standard contained in §G(2)(c) of this regulation as if its voltage were less than 14 kV but at least 600 volts. The vertical clearances are the minimum clearances the utility shall establish during each cyclical planned vegetation management trim cycle. Mature trees may be exempt from the minimum clearance requirements specified above at the utility's reasonable discretion for voltage levels at 34.5 kV and below. Federal Energy Regulatory Commission Jurisdictional Transmission Plant. Each utility shall file with the Commission’s Engineering Division a copy of all Vegetation Management Transmission Outage Report filings associated with a transmission line outage in Maryland that are filed with the Federal Energy Regulatory Commission or an entity approved by the Federal Energy Regulatory Commission. If the information is confidential or critical energy infrastructure information, the utility shall advise the Commission’s Engineering Division in writing and make the information available for review at a mutually agreeable time and location. Each utility shall adopt and follow written operation and maintenance procedures for its electric plant in order to maintain safe and reliable service. The operation and maintenance programs shall account for the utility's experience, good engineering practices, and judgment, and manufacturer’s recommendations. Each electric utility shall file its written operation and maintenance programs required under §A of this regulation with the Commission within 60 days from the effective date of these regulations and the programs shall be designed to achieve, at a minimum, the level of reliability established by the Commission's regulations. If the electric utility makes a material change to its written operation and maintenance programs required under §B of this regulation, the utility shall file the change with the Commission not less than 60 days prior to implementing the change, unless exigent circumstances warrant implementation without prior notice, in which case the change shall be filed by no later than 30 days after implementation. The filing shall describe each change and the reason for the change. The operation and maintenance programs required by §B of this regulation shall: Include the frequency or triggers for performing an inspection; Identify the electric plant inspections to be performed; and Identify acceptance criteria for the inspections. Except as provided under §D of this regulation and Regulation .09 of this chapter, the operation and maintenance programs required by §B of this regulation need not include detailed procedures and shall include a description of the corrective maintenance priorities and general timelines for the overall repair of the electric plant. Each utility shall maintain sufficient records to give evidence of compliance with its operation and maintenance programs and shall self-report compliance and non-compliance with its maintenance program each year in its annual performance report. If a utility fails to comply with its operation and maintenance programs and has not received a stay of enforcement pursuant to §H of this regulation, the utility shall provide a corrective action plan, preferably in its annual performance report but by no later than April 1. If a utility cannot perform regular periodic electric plant maintenance work on its electric distribution system according to timeline requirements documented in its operation and maintenance program manual or its vegetation management program pursuant to Regulation .09 of this chapter, the electric company may request a stay of enforcement on a form specified by the Commission. The stay of enforcement request shall demonstrate that the electric company has a good cause for delay, can maintain safety and reliability for the duration of the stay of enforcement, and provides an abatement plan to return to normal timeline requirements. Approval of both the stay of enforcement request and the return to normal shall be delegated to the Commission’s Engineering Division. On or before April 1 of each year, each utility shall file an annual performance report which shall include, at a minimum, the following: The reliability index information and results required in this chapter, including a table showing the actual values of the reliability indices required in this chapter for each of the preceding 3 calendar years; Annual year-end and 3-year average performance results as required under Public Utilities Article, §7-213(g)(2)(i) and (ii), Annotated Code of Maryland, including a table showing the actual values for each of the preceding 3 calendar years; The time periods during which major outage event interruption data and, if a cooperatively owned utility, the outage data resulting from an outage event occurring on another utility's electric system was excluded from the CAIDI, SAIDI, and SAIFI indices, including a brief description of the interruption causes during each time period; A description of the utility’s reliability objectives, planned actions and projects, and programs for providing reliable electric service; An assessment of the results and effectiveness of the utility’s reliability objectives, planned actions and projects, programs, and load studies in achieving an acceptable reliability level as required under Public Utilities Article, §7-213(g)(2)(iii), Annotated Code of Maryland. The assessment of the results and effectiveness shall include, to the extent estimated or determined by the utility, the program's, project’s, or planned action’s impact on reliability indices, including CAIDI, SAIDI, and SAIFI and any other reliability index considered. The method for estimating or determining the impact on any reliability index shall be explained; Current year expenditures, an estimate or budget amount for the following 2 calendar years, if available, current year labor resources hours, and progress measures for each capital and maintenance program designed to support the maintenance of reliable electric service as required under Public Utilities Article, §7-213(g)(2)(iv)(1), Annotated Code of Maryland; An explanation for any material differences between current year expenditures and cost estimates filed pursuant to §A(6) of this regulation; The number of outages by outage type as required under Public Utilities Article, §7-213(g)(2)(iv)(2), Annotated Code of Maryland, including planned outage, nonplanned outage minus major outage event, and major outage event; The number of outages by outage cause required under Public Utilities Article §7-213(g)(2)(iv)(3), Annotated Code of Maryland, including, but not limited to, animals, overhead equipment failure, and underground equipment failure; The total number of customers that experienced an outage required under Public Utilities Article, §7-213(g)(2)(iv)(4), Annotated Code of Maryland; The total number of customer minutes of outage time required under Public Utilities Article, §7-213(g)(2)(iv)(5), Annotated Code of Maryland; To the extent practicable, a breakdown, by the number of days each customer was without electric service, of the number of customers that experienced an outage required under Public Utilities Article, §7-213(g)(2)(iv)(6), Annotated Code of Maryland; Poorest performing feeder information and results required in this chapter; and Multiple device activation information and results required in this chapter. On or before April 1 of each year, each utility shall file a supplemental annual performance report which shall include, at a minimum, the following: The actual operation and maintenance and capital expenditures for the past 3 calendar years for each of the utility's reliability programs, including, but not limited to underground and overhead distribution plant inspection, maintenance and replacement programs, vegetation management, subtransmission inspection and maintenance programs, and distribution substation plant inspection and maintenance programs; Service restoration requirement information and results required in this chapter; Downed wire response performance information and results required in this chapter; Customer communications performance information and results required in this chapter; The vegetation management information required in this chapter; Periodic equipment inspection information and results required in this chapter; For the immediately preceding calendar year, and considering normal conditions only: The number of downed electric utility wires to which the utility responded in: 3 hours or less; More than 3 hours but less than 8 hours; and 8 hours or more; and The total number of downed electric utility wires reported to the utility; Any corrective action plans required under Public Utilities Article, §7-213(e)(1)(iii), Annotated Code of Maryland, or this chapter; and The number of manhole and conduit events during the preceding year that result in a lid displacement, the date of the event, the location and feeder designation, whether the event involved a feeder, primary or secondary services, and the number of customer outages recorded. The Commission may designate a specific report format for the information required to be included in the written reports mandated under §§A and B of this regulation. The Commission may require reporting information required to track performance under these regulations on a quarterly basis on a form approved by the Commission. Within 60 days of the effective date of this regulation, each utility shall file a major outage event response plan providing a description of and procedures for its response to major outage events, and performance measures associated with the assessment of the implementation of the major outage event response plan, including, but not limited, to the following topics and issues: Preparation, training, and drills; Early warning and storm tracking; Emergency organization structure; Activation and mobilization; Materials management and logistics; Major outage event restoration priorities, including, but not limited to: How the utility prioritizes restoration customers; and How the utility communicates with customers that are identified as high priority due to medical needs for electricity and how it schedules restoration actions for such customers; Damage assessment; Public safety, including wire down response; Crew deployment; External communications, including communications with emergency officials, the public, and other persons; Internal communications; Communications technology use, including high call volume capability and capacity; Development of estimated times of restoration and assessment of estimated times of restoration accuracy; Ramp-down; and Major outage event performance review. Each utility shall file with the Commission any material change to its major outage event response plan at least 60 days prior to implementation, unless it will delay implementation of the change in a manner inconsistent with restoring service in the shortest time practicable, in which case the change shall be filed by no later than 30 days after implementing the change. Each utility shall comply with its major outage event response plan when preparing for and responding to major outage events. The major outage event response plan shall be filed as a publicly available document. To the extent that some information may be considered confidential, a redacted version shall also be filed. Major outage event response plan information may be shared without restriction with state officials that participate in a Maryland Department of Emergency Management activation of the State Emergency Operations Center. Written Reports. Each utility shall file a written report with the Commission within 35 calendar days of the end of a major outage event. Contents. The written report shall contain: The total number of Maryland customers served by the utility; The date and time when the major outage event started; The date and time when all sustained interruptions in Maryland related to the major outage event were restored; The total number of Maryland customers who experienced a sustained interruption of service related to the major outage event; The total number of customer interruption hours experienced by customers reported under §B(4) of this regulation; The average duration of customer service interruption, expressed in hours, and calculated by dividing the total number of customer interruption hours reported in §B(5) of this regulation by the total number of Maryland customers who experienced an interruption reported in §B(4) of this regulation; The maximum number of Maryland customers who concurrently experienced a sustained interruption related to the major outage event and the date and time this occurred; The number of Maryland customers who experienced a sustained interruption recorded at a maximum of 6-hour intervals throughout the major outage event; Information about requests for outside assistance, including the: Name of the organization to which the request was made; Date and time of the request; and Resources requested; Information about outside assistance received, including the: Name of the organization providing crews and the nature of the assistance, i.e., mutual assistance, third-party contractor crew normally dedicated to the utility, additional third-party contractor crew, or other (explain in report); Date and time of crew arrivals and departures; Number and types of vehicles; Total number of personnel; Number of personnel on primary overhead line crews; Number of personnel on secondary overhead line crews; Number of personnel on tree trimming crews; and Number of other personnel. Information about electric utility crews working on restoration, including the following: Number and types of vehicles; Total number of personnel; Number of personnel on primary overhead line crews; Number of personnel on secondary overhead line crews; Number of personnel on damage assessment crews; Number of personnel on tree trimming crews; and Number of other personnel. The following information about communications with customers: The total number of calls received by the utility during each hour of the major outage event; The total number of calls answered by the utility’s voice response system, customer service representatives, and any high volume call systems during each hour of the major outage event; The total number of customer service representatives logged into the call center and supporting phone systems actively taking or waiting to take customer calls on an hourly basis during the major outage event; and On a daily basis during the length of the outage and for the entire major outage event, the percentage of all calls that were offered and answered by the utility’s voice response system, customer service representatives, and any high volume call systems within a 30-second timeframe and within a 60-second timeframe. With regard to system damage, the number of each of the following occurring during restoration: Poles replaced as a percentage of total utility owned or partially owned poles; Distribution transformers replaced; Fuses replaced; Downed wires; Substations with damaged equipment and substations outages due to loss of one or multiple supplies; State highways blocked due to electric utility wires that are referred to the utility for remediation; and Traffic signals reported out of service by government agencies that are referred to the utility for remediation; Any issues concerning the availability of materials or equipment that affected restoration progress, including a description of how any unavailability affected restoration, and a description of the emergency measures taken to resolve the issues; A self-assessment, including lessons learned and future plans to improve service restoration efforts during major outage events; A description of the manner in which customers were informed of the status of the outages in their geographic area by means of the customer call center or by other means of customer communications; A description of the manner in which the utility informed elected officials, government officials, and members of the public of the status of the outage and restoration efforts; A description of the manner in which the utility estimated restoration times; A description of any areas where the utility did not comply with its major outage event response plan; The number of customer service interruptions under §B(4) of this regulation and the number of customer service interruption hours under §B(5) of this regulation categorized by outage caused by each one of the following: All outage causes typically provided in annual performance reports pursuant to Regulation .11 of this chapter; A description of the outage causes due to physical security or cybersecurity attacks; A description of any outage causes due to transmission or energy supply disruptions; A description of any other outage causes due to natural weather phenomena not typically encountered; Ice accumulation on conductors; and Each other direct cause of interruption of service to 5 percent or more of total customers interrupted, listing and providing a descriptive name for each cause; For each interruption to normal expected information technology systems used to manage a major outage event, details on deficiencies experienced in these systems including dates, time, and duration of any interruptions to normal expected functionality for the following: Real time operating systems used to monitor and control the event including, but not limited to, distribution automation systems, energy management systems, and outage management systems; Advanced meter infrastructure systems; Web-based outage reporting systems; Web-based outage information systems such as outage maps; Interactive Voice Response (IVR) systems; Phone systems; Mobile data systems used to receive information from field crews; The data interface that provides outage information to the Maryland Department of Emergency Management outage map application; and Any utility business systems directly impacted by the major outage event; The percentage of total Maryland customers who had service restored in 50 hours pursuant to Regulation .06B of this chapter; If the company could not safely work due to high wind conditions for the major outage event, an explanation of the company policy and how this impacted restoration; The percentage of calls that are answered within 30 seconds, the abandoned call percentage rate, and the average speed of answer pursuant to Regulation .08D of this chapter, except measured only for the duration of the major outage event; The average amount of time customers were put on hold for every hour during the major outage event after the customer selected the option to talk to a call center representative in the electric company’s Interactive Voice Response (IVR) system: Before talking to a call center representative; and Before dropping off the call after waiting unsuccessfully to reach a call center representative. For the duration of the major outage event, the number of customers experiencing multiple sustained interruptions, categorized by the number of multiple sustained interruptions, such as the number of customers experiencing “n” sustained interruptions, where n= 1, 2, 3, etc.; The downed wire response performance to a government emergency responder guarded downed electric utility wire within 3 hours after notification by a fire department, police department, or 911 emergency dispatcher pursuant to Regulation .07A of this chapter, except measured only for this major outage event; The number of peak sustained interruptions restored by county and municipal jurisdiction for the duration of the major outage event; The number of customers sustained interruptions caused by off-right-of-way trees; All press releases, if any, issued and details on the date, time, location, and company participants in all press conferences held, if any; The date and time centralized and regional emergency operations centers, district headquarters, and mutual assistance staging areas activated for the major outage event were operational completed; Electric system infrastructure that was damage assessed and how this damage assessment information was used to establish a Global ETR; The number of Maryland critical facilities who experienced a sustained interruption recorded at a maximum of 6-hour intervals throughout the major outage event; and The percentage critical facility sustained interruptions restored within 24 hours and 48 hours of the start of the major outage event. The Commission may designate a specific report format for the information required to be included in the written report mandated under this regulation. Each utility shall perform a customer perception survey no less than every 4 years. The objective of the survey is to measure customer perceptions regarding the utility's overall performance, reliability performance, vegetation management activities, effectiveness of customer communications, and service quality performance. By April 1, 2026, and every 4 years thereafter, unless otherwise directed by the Commission, each utility shall file customer perception survey results that shall be included with each utility’s submittal under Regulation .02D(7)(b) of this chapter. Each utility shall use a survey process as determined by the Commission, in which the survey question themes and associated rating scales shall be consistent among all utilities. Each utility shall determine a communication methodology to reach customers in regard to collecting survey data and survey sample size to reflect a margin of error of plus or minus 5 percent at a minimum 90 percent confidence level for both the residential and commercial customer segments. This regulation applies after January 1, 2024. An electric utility shall have resilience plans to prepare for and recover from various utility-defined credible event threat scenarios such as pandemics, physical attacks, cyber attacks, electric supply shortages, weather events, significant infrastructure failures, and other credible disturbances with the potential to lead to large and widespread electric outages or loss of critical facilities essential for public health and safety. In consultation with State and local jurisdictions, a utility’s resilience plans shall identify critical facilities. An electric utility’s resilience plans shall be made confidentially available for Commission inspection, upon request. After a complaint, report, or inspection, the Commission’s Engineering Division may send an electric company a specific information request. An electric company shall respond within 10 working days after receipt of a specific information request relating to a possible reportable incident under COMAR 20.50.03.04F. Except as provided under §B of this regulation, an electric company shall respond within 30 days after receipt of a specific information request. The Commission’s Engineering Division may waive the requirements of §B or C of this regulation upon written request from an electric company operator demonstrating sufficient cause. A utility shall make available suitable equipment and personnel to provide electric underground location services upon reasonable request of interested persons, in compliance with Public Utilities Article, Title 12, Subtitle 1, Annotated Code of Maryland. In the absence of conditions that allow or dictate a more circumscribed ETR, a utility shall issue a Global ETR within 24 hours of the end of the cause of the major outage event. Should completion of the damage assessment required as the result of the major outage event require more time, this period shall be extended by the electric company. The Global ETR should be reviewed at least once every 24 hours and modified when information is received that would significantly change the Global ETR or allow a more precise ETR for a specific, smaller area. An assessment message statement that indicates the electric company is assessing the system, including a safety message, should be posted within 4 hours, if not immediately, upon the end of the cause of the major outage event. A restoration message statement that indicates when a majority of the electric company’s customers within the entire service territory will be restored shall be delivered to customers within 24 hours following completion of the initial damage assessment. When a Zonal ETR can be established, the electric company shall issue a restoration message statement that indicates when at least 90 percent of the electric company’s customers, who were affected by the original major outage event within a zone, will be restored. Global and Zonal ETRs will be reviewed by the utility, at least once every 24 hours during a major outage event and updated when better information becomes available. An ETR, whether Global or Zonal, shall be considered accurate if at least 90 percent of the customers affected by the original storm event are restored by the last applicable Global or Zonal ETR provided to the customer. Following a major outage event, utilities shall perform a self-assessment of the quality of Global and Zonal ETRs provided to customers as part of lessons learned activities in its Major Outage Event Report pursuant to COMAR 20.50.12.13. Elements to be considered include the accuracy of the original ETR in terms of hours, the number of adjustments to the original ETR, the reasons for updating the ETR, significant external influences that may have contributed to the changes, and the accuracy of the final ETR in terms of hours. All utilities shall engage in consumer education programs to help customers better understand all aspects of emergency preparedness and outage restoration related to a major outage event. Public Utilities Article, §§7-213, 13-201, and 13-202, Annotated Code of Maryland Effective date: May 28, 2012 (39:10 Md. R. 661) Regulation .01 amended effective August 21, 2023 (50:16 Md. R. 728) Regulation .02 amended effective August 21, 2023 (50:16 Md. R. 728) Regulation .02C, D amended effective December 2, 2019 (46:24 Md. R. 1104) Regulation .02D amended effective January 7, 2016 (42:26 Md. R. 1596) Regulation .03 amended effective October 8, 2018 (45:20 Md. R. 920) Regulation .04A, D amended effective August 21, 2023 (50:16 Md. R. 728) Regulation .05 amended effective August 21, 2023 (50:16 Md. R. 728) Regulation .05A amended effective December 2, 2019 (46:24 Md. R. 1104) Regulation .07A amended effective December 2, 2019 (46:24 Md. R. 1104) Regulation .08D amended effective August 21, 2023 (50:16 Md. R. 728) Regulation .09 amended effective August 21, 2023 (50:16 Md. R. 728) Regulation .10 amended effective August 21, 2023 (50:16 Md. R. 728) Regulation .11A amended effective March 18, 2013 (40:5 Md. R. 412); December 2, 2019 (46:24 Md. R. 1104) Regulation .11B amended effective August 21, 2023 (50:16 Md. R. 728) Regulation .12A, B amended effective August 21, 2023 (50:16 Md. R. 728) Regulation .12D, E adopted effective August 21, 2023 (50:16 Md. R. 728) Regulation .13 amended effective August 21, 2023 (50:16 Md. R. 728) Regulation .14 amended effective August 21, 2023 (50:16 Md. R. 728) Regulation .15 adopted effective August 21, 2023 (50:16 Md. R. 728) Regulation .16 adopted effective August 21, 2023 (50:16 Md. R. 728) Regulation .17 adopted effective August 21, 2023 (50:16 Md. R. 728) Regulation .18 adopted effective August 21, 2023 (50:16 Md. R. 728) This chapter applies to Electric System Plans for the advancement of the State policy goals and legislative intent set forth at Public Utilities Article, §§7-801—7-804, et seq., Annotated Code of Maryland, and all other relevant State goals and targets in effect during plan development. The objective of the final Electric System Plan is an electric system that advances State policy goals and is built in a manner that enables an electric company to provide safe, reliable, and cost-effective services and otherwise operates for the public good. An Electric System Plan shall demonstrate a holistic approach to grid planning by: Considering cost-effective solutions to electric system needs; Incorporating new cost-effective technologies and analytical tools into planning processes to create a modern distribution system; Utilizing real-time data to improve forecasting and planning for grid investments; and Addressing issues related to other relevant Commission proceedings. This chapter shall not become effective for electric cooperatives and municipal electric companies until January 1, 2028. Electric company and gas company coordination on Electric System Plans may be performed, but shall not be required, unless required by law or as otherwise directed by the Commission. Waiver of Regulations. Upon written request, a regulation in this chapter may be waived by the Commission for “good cause shown”. Terms Defined. “Annual Electric System Plan Update” means the update that electric companies publish annually at the end of the distribution system planning cycle in the years that they do not publish an Electric System Plan and that contains the information in Regulation .04B of this chapter. “Baseline scenario” means an expected future state of a system or situation if no new interventions or policies are implemented beyond those already in place. It serves as a point of comparison to assess the impact of proposed actions or policies. “Cost-effective” means having projected benefits that are greater than projected costs while considering other factors as determined by the Commission. “Demand response” means changes in electric usage by demand-side resources from their normal consumption patterns in response to changes in the price of electricity over time or to incentive payments designed to induce lower electricity use at times of high wholesale market prices or ensure system reliability. “Distributed energy resource (DER)” has the meaning stated in COMAR 20.50.09.02B. “Distributed generation” means the same definition as Small Generator Facility in COMAR 20.50.09.02B. “Electric company” has the meaning stated in Public Utilities Article, §1-101, Annotated Code of Maryland. “Energy storage device” has the meaning stated in Public Utilities Article, §7-216, Annotated Code of Maryland. “Electric System Plan” means the plan that electric companies publish pursuant to Regulation .04J of this chapter that concludes the distribution system planning cycle. “Electric vehicle (EV)” has the meaning stated in COMAR 20.50.09.02B. “Goal scenario” means a potential future state of a system or situation if policy goals are fully realized and it serves as a point of comparison to assess the progress towards policy goals. “Grid needs” means the need for a specific mitigating action to alleviate an identified system constraint found during the electric system planning process. The specific characteristic of the system constraint and commensurate grid need will inform the solution that will mitigate the issue. “Grid services” means the dispatch and control of one or more DERs to provide service to the electric company’s electric grid pursuant to an electric company tariff, service contract between the electric company and the owner of DERs or providing transmission-level grid services by participating in PJM Interconnection, LLC wholesale markets. “Hosting capacity” has the meaning stated in COMAR 20.50.09.02B. “Locational value assessment” means a process that provides price signals based on the benefits and costs of deploying distributed energy resources in a specific location and over time, considering grid conditions and the potential to defer or avoid traditional electric distribution infrastructure investments. “Non-wires solution (NWS)” means a project or other solution that makes use of one or more DERs, technologies, and/or leads to the introduction of new or modification of existing energy management practices, standards, or protocols to address a system constraint or provide other grid services to the electric system. “Planning metrics” means quantifiable measurements used to assess performance, track progress, and/or measure success of a process that an electric company electric system plan directly affects. “Preliminary Electric System Plan” means the plan that electric companies file before the annual technical conference that contains the information in Regulation .04F of this chapter. “Rightsizing” has the meaning stated in COMAR 20.50.09.02B. “System constraints” means specific violations caused by physical characteristics of the electric distribution system exceeding electric company planning criteria, the result of which would threaten safe and reliable delivery of power. “Stakeholder” means a person who is granted leave to intervene in an electric system plan proceeding pursuant to Public Utilities Article, §3-106, Annotated Code of Maryland. “Traditional wires solution” means a solution to address a system constraint that would be deferred or replaced by a non-wires solution. “Virtual power plant (VPP)” has the meaning stated in Public Utilities Article, §7-216, Annotated Code of Maryland. An electric system planning process shall align with the following components for each planning cycle and scenario and related requirements specified in this chapter: Considerations feeding into types of projections; Goals/ objectives; DER forecast; Load forecast; Hosting capacity assessment; Grid needs and locational value assessment; Identify possible solutions to grid needs; Screen and evaluate possible solutions; Choose solutions and publish plan; Program and project design; and Assess results. Considerations Feeding into Types of Projections. Time Horizons for DER and Load Forecasting. DER and load forecasting processes for electric companies other than electric cooperatives and municipal electric companies shall include at least three planning time horizons: 1 to 3 years; 4 to 6 years; and 7 to 10 years. DER and load forecasting processes for electric cooperatives and municipal electric companies shall include at least two planning time horizons: 1 to 3 years; and 4 years up to 20 years. Level of Granularity. The granularity of information in an electric system plan may vary as described in other sections of this regulation. As a near-term objective: Information shall be provided in an Electric System Plan at the substation level; and Feeder-level information shall be provided as part of the planning process for feeders where there are identified system constraints; As a longer-term objective, electric companies shall report on progress regarding incorporating more granular electric system and customer information and data into forecasting and planning processes in their electric system plan or annual electric system plan update. Scenarios/Projections to be Analyzed. An electric system plan shall include a minimum of two scenarios to provide a range of outcomes to inform planning analysis and the determination of the scale and pace of grid needs: A baseline scenario; and A goal scenario. The Commission may request an electric company to analyze scenarios in addition to a baseline scenario and goal scenario. Data Sources, Scope, and Access. Electric companies shall provide for data collection and access that: Allows stakeholders the opportunity to provide data inputs at pre-identified time periods defined by the electric company; Provides collected data in a format that can be easily accessed by stakeholders; and Provides stakeholders transparency into data sources, data and assumptions used to develop electric system plans and annual electric system plan updates. Already-Approved Resource Retirements and Additions. Electric companies shall consider in their electric system plans whether distribution-level electric system planning can be used to mitigate potential gaps caused by generation retirements. PJM Wholesale Markets. Electric companies shall consider DERs and VPPs that participate in the PJM wholesale markets in electric distribution planning as applicable. Resource Costs and Capabilities. Electric companies contracting decisions to implement electric system plans and annual electric system plan updates shall be left to electric company discretion. Goals/Objectives. An electric system plan shall promote applicable State policy goals pursuant to Public Utilities Article, §§7-801—7-804, et seq., Annotated Code of Maryland, and other applicable goals and targets as directed by the Commission. DER Forecast. An electric system plan shall account for the following considerations for each electric system planning cycle and scenario. Electric companies shall develop separate forecasts for each relevant DER type, including energy efficiency, demand response, distributed generation, energy storage devices, VPPs and managed EV charging-discharging. Electric Companies shall develop hourly DER forecasts. Load Forecast. Load forecasts shall account for the following considerations for each planning cycle and scenario as follows: Electric companies shall incorporate load impacts of current and future transportation and building electrification based on known information and assumptions; and Electric company distribution-level forecasts in aggregate shall be aligned to a reasonable extent with available electric company developed transmission-level forecasts and with PJM-developed system-level forecasts with an explanation provided in electric system plans for any differences and the associated factors, including differences in assumptions. Hosting Capacity Assessment. An electric system plan shall account for the following considerations for each planning cycle and scenario. Hosting capacity calculations shall be determined using a circuit-specific calculation including installed and forecasted DER interconnections. DER forecasting shall be incorporated into reserve hosting capacity determinations and the rightsizing of hosting capacity upgrades. Electric companies shall establish methodologies for calculating available hosting capacity and, in the annual electric system plan update and electric system plan, discuss planned hosting capacity capability improvements. Grid Needs and Locational Value Assessment. Grid Needs Assessment. An electric company’s grid needs assessment shall include current and forecast distribution substation and feeder constraints identified as part of each planning cycle, including the timing, magnitude and other relevant characteristics for each identified system constraint. The annual electric system plan update shall discuss changes to an electric company’s grid needs assessment that may occur between planning cycles. Electric companies shall cost-effectively pursue industry best practice methods and analytical tools to improve their planning analysis and processes, the choice of which to adopt shall be at the discretion of the electric companies. Locational Value Assessment. An electric system plan shall provide locational value for each identified electric system constraint. Locational value shall include the potential deferral or avoided value of a traditional wires solution. Electric companies shall develop a locational value assessment using the Commission's uniform benefit cost analysis framework. Electric companies shall report on the progress towards implementation of locational value assessments at annual technical conferences. Identify Possible Solutions to Grid Needs. An electric system plan shall account for the following considerations for each planning cycle and scenario: Near-Term Objective. An electric system plan shall identify solutions for identified grid needs. Electric companies shall identify non-wires solutions considered to address system constraints. For any proposed upgrade projects resulting from Regulations .03H and .03I of this chapter, future hosting capacity constraints that incorporate DER forecasts shall be considered. As A Longer-Term Objective. Electric companies shall assess the feasibility of utilizing new cost-effective technologies and methodologies for solutions to grid needs. Electric companies shall report on the progress towards utilizing new cost-effective technologies and methodologies at annual technical conferences. Pursuant to Public Utilities Article, §7-804, Annotated Code of Maryland, electric companies shall consider investment in, or procurement of cost-effective demand-side methods and technology to improve reliability and efficiency, including VPPs. Screen and Evaluate Possible Solutions. An electric company shall screen and evaluate possible solutions for each planning cycle and scenario. The electric system plan shall include the criteria used to evaluate possible solutions, including cost-effectiveness considerations. Electric companies shall evaluate cost-effectiveness for alternatives considered, if applicable. Electric companies shall utilize the Commission's Unified Benefit Cost Analysis framework for solutions involving DERs in determining cost-effectiveness. Choose Solutions and Publish Plan. An electric company shall choose a solution or solutions for each scenario and publish a plan for each planning cycle as described in Regulation .04 of this chapter. Electric companies shall present their rationale for solution selection in electric system plans, including why alternative solutions were not selected. Information and data shall be provided in an electric system plan at the substation level. When project solutions are proposed in response to system constraints, electric companies shall provide feeder-level information, where applicable. Program and Project Design. Program and project design including construction, procurement, and electric company contracting are factors in the electric companies’ mandate to provide safe and reliable service and a consideration in overall cost which shall be estimated in electric system plans. Program and project design including construction, procurement, and electric company contracting decisions shall be left to electric company discretion in executing an electric system plan although these factors will remain subject to review in rate cases. Assess Results. An electric company shall account for the following considerations for each planning cycle: An electric company shall assess the results of their electric system plans to determine lessons learned and changes to future planning assumptions. Rate case filings shall provide explanations for projects that do not reconcile with electric system plans. Electric System Plan Frequency. Electric companies shall retain flexibility to determine the frequency of their respective electric system plan that best aligns with their internal planning cycles and considerations based upon their unique processes, system characteristics, and customer needs. An electric company’s electric system plan publishing frequency shall be at least once every 3 years. Electric companies shall publish a preliminary electric system plan and the electric system plan on the electric companies’ websites and file these plans with the Commission under the electric system plan docket assigned to each electric company. An electric company shall file an annual electric system plan update during the years in which a complete electric system plan is not filed. An electric company shall redact all confidential information from the electric system plan published to its website or otherwise submitted on a public basis, however, a full version of the electric system plan, including any confidential information, shall be filed with the Commission in accordance with the Commission’s rules for filing confidential material, unless otherwise restricted from doing so by applicable law. Annual Electric System Plan Update. Electric companies shall include the following annual electric system plan updates: A narrative describing the existing planning and forecasting processes, current capabilities that exist, and plans for potential future improvements; Relevant planning criteria utilized to identify system constraints; Description of any new market or policy conditions that are impacting the planning environment and how they plan to incorporate them into future planning; Description of any updates to system constraints or constraint solutions that may have changed from the previous year, including, but not limited to, updates on progress regarding projects and programs that have changed from the previous year and rationale for the change; A report using a common framework for electric company reporting as directed by the Commission, with information regarding the current status of projects designed to promote State policy goals identified in Public Utilities Article, §7-802, Annotated Code of Maryland, including information on planning processes and implementation that promote these goals; and Electric system plan targets and planning metrics pursuant to Regulation .05 of this chapter. Electric companies shall file an annual electric system plan update no less than 75 days prior to the annual technical conference. In the year an electric company files a preliminary electric system plan, an annual electric system plan update is not required. Data Collection: Electric companies shall identify a discrete opportunity to collect stakeholder inputs for consideration in the electric system plan. The electric company shall provide an overview of the already-collected data including data sources. Electric companies shall provide a method for collecting this data. Electric companies shall provide a list of the parties they engaged as part of their published electric system plan. Align Inputs and Assumptions. Electric companies shall develop electric system planning inputs and assumptions or develop forecasts, scenarios, or other electric system planning criteria and identify a discrete opportunity for stakeholders and other persons to provide feedback. Run Analyses. Electric companies shall run analyses using data, planning inputs, and assumptions while considering stakeholder and other person feedback from §§C and D of this regulation and provide a preliminary electric system plan in years that an electric system plan is due. Provide Preliminary Electric System Plan. Electric companies shall include the following in their preliminary electric system plan: Lessons learned and process improvements from the previous electric system plan cycle; A narrative describing the existing electric system planning process, current capabilities, and plans for potential future changes including the methodology used to develop aggregate electric distribution-level net load forecasts; Descriptions of electric system planning scenarios describing the data used as inputs and assumed adoption rates used for load and DER forecasting; Summary of feedback received in §§C and D of this regulation; Electric company response to feedback received in §§C and D of this regulation; Any change in system constraints since the last electric system plan; The nature, magnitude, and timing of system constraints; System constraint solutions that have not yet been initiated as projects, including: Projected timeline for solution implementation to address system constraints and policy targets over the forecast period; and Implementation interdependencies with current and identified system constraint solutions and other electric company projects; Cost-effectiveness analysis for identified system constraint solutions, if applicable; A description of the final methodology, inputs, and results of the analyses; Locational value for each identified system constraint; and Electric system plan targets and planning metrics pursuant to Regulation .05 of this chapter. The preliminary electric system plan shall be published to align with the electric system plan frequency pursuant to §A of this regulation. An electric company shall publish on its website and file with the Commission its preliminary electric system plan no less than 75 days prior to the annual technical conference. Comments Filed By Parties. Comments shall be filed by any stakeholders or other persons no less than 30 days prior to the annual technical conference. Stakeholders and electric companies shall have the opportunity to obtain discovery. Annual Technical Conference. The annual technical conference shall provide a venue for stakeholders and other persons to comment on the assumptions, inputs, and results of the preliminary electric system plan and annual electric system plan update. Electric Companies’ Consideration of Feedback. The Commission may provide an order noting the preliminary electric system plan after an annual technical conference which may include direction for the electric companies. Electric companies shall evaluate any feedback received from the Commission in any order following the annual technical conference. Electric companies shall evaluate feedback received from stakeholders in §§C, D, G, and H of this regulation. Within 90 days of the annual technical conference, except as otherwise required by the Commission, electric companies shall publish on their website and file a response to stakeholder and other person feedback with the Commission, including what stakeholder and other person proposals will be considered or not considered in the development of the electric system plan and the reasoning for these decisions under the electric system plan docket assigned to each electric company. Electric System Plan Publishing. Electric companies shall publish a final electric system plan under the electric system plan docket assigned to each electric company after the consideration of feedback in Regulation .04I of this chapter. An electric company shall include planning metrics listed in §C of this regulation in its preliminary electric system plan and other planning metrics as determined by the Commission. An electric company shall include planning metrics listed in §C of this regulation in its annual electric system plan update and other planning metrics as determined by the Commission. An electric company shall include in its preliminary electric system plan, electric system plan, and annual electric system plan update a set of planning metrics that will allow monitoring of progress in at minimum the following plan areas: State goals and targets; Reliability; Resilience; DER integration, by DER category; Load and demand management; Hosting capacity; System constraint resolution including: Substation overload conditions defined as overload conditions identified on substations that require remediation; and Feeder overload conditions defined as overload conditions identified on substations that require remediation; NWS incorporation; and Stakeholder and other person engagement. Annual Maryland General Assembly Report. On or before November 1 annually, each electric company shall file material updates to project status reported pursuant to Regulation .04B(1)(e) of this chapter. On or before December 1 annually, the Commission’s Technical Staff shall submit a report to the Maryland General Assembly regarding the current status of projects designed to promote the State’s policy goals identified in Public Utilities Article, §7-802, Annotated Code of Maryland, including information on planning processes and implementation that promote these goals. Public Utilities Article, §§1-101, 2-113, 2-121, 7-216, and 7-801—7-804, Annotated Code of Maryland Effective date: November 24, 2025 (52:23 Md. R. 1140) This chapter applies to the following: All front-of-the meter energy storage devices in Maryland pursuant to Public Utilities Article, §7–219, Annotated Code of Maryland. Any energy storage devices eligible to be enrolled or registered in the Maryland Energy Storage Program pursuant to Public Utilities Article, §7-216.1, Annotated Code of Maryland. Electric vehicles that are part of a renewable on-site generating system and mobile energy storage devices are ineligible for registration in the Maryland Energy Storage Program pursuant to Public Utilities Article, §7-1005(E)(2)(II)(1), Annotated Code of Maryland. A virtual power plant or microgrid is ineligible for registration in the Maryland Energy Storage Program as a stand-alone energy storage device. Any energy storage device that constitutes part of a virtual power plant, microgrid, or a renewable on-site generating system, except as specified in Regulation .01B of this chapter, is eligible to register in the Maryland Energy Storage Program or enroll in Administrator Initiatives. Electric company owned energy storage devices used for substation control, support, and emergency back-up of utility equipment and facilities are exempt from the requirements of this chapter. An energy storage device as defined in Public Utilities Article, §7-216, Annotated Code of Maryland that off-sets grid demand, but does not deliver energy to the grid, shall not be subject to the requirements of in Regulation .03 of this chapter, except for §G of this regulation and other conditions as determined by the Commission for inclusion in a Maryland Energy Storage Program Initiative. The applicant shall make a filing with the Commission regarding the technical details of its proposed energy storage device and the applicant’s rationale for inclusion in a Maryland Energy Storage Program Initiative. The Commission shall determine the next steps necessary to consider the matter as a special case in the Maryland Energy Storage Program. Applicable Standards. Unless otherwise specified by the Commission, an energy storage device shall, to the extent applicable, comply with the provisions in the National Fire Protection Association (NFPA) 855 Standard for the Installation of Stationary Energy Storage Systems, 2023 Edition, which is incorporated by reference in Regulation .03 of this chapter. Terms Defined. “Administrator” means an approved electric company, state agency, or Commission approved entity responsible for the enrollment in and general administration of an initiative under the Maryland Energy Storage Program. “Affected community” means the residential individuals, organizations, and other entities located within 1 mile of the proposed location of an energy storage device. “Applicant” means an energy storage device owner that submits an application to an administrator to enroll in an initiative in the Maryland Energy Storage Program or to construct a front-of-the-meter energy storage device. “Behind-the-meter energy storage device” means an energy storage device that is installed on the customer side of an electric company meter and serves a particular electric company customer electric load. “Construction” has the meaning stated in Public Utilities Article, §7-207(a)(3), Annotated Code of Maryland. “Cost-effective” means having projected benefits that are greater than projected costs while considering other factors as determined by the Commission. “Delivery year” has the meaning stated in Public Utilities Article, §7-216.1, Annotated Code of Maryland and is a planning period consisting of the 12 months beginning June 1 and extending through May 31 of the following year. “Deployment incentive mechanism” means an incentive or rebate provided by an administrator to accelerate the deployment of cost-effective energy storage devices providing grid services as part of the Maryland Energy Storage Program and is not a payment for performance or specific operations. “Distributed energy resource” has the meaning stated in COMAR 20.50.09.02. “Electric company” has the meaning stated in Public Utilities Article, §1-101, Annotated Code of Maryland. “Energy storage device” has the meaning stated in Public Utilities Article, §7-216, Annotated Code of Maryland and may be classified by market segment for the purposes of registration in the Maryland Energy Storage Program or enrollment in Administrator Initiatives. “Enrollment” means the acceptance by an administrator of an application of an energy storage device in an initiative for a delivery year and occurs in parallel with the PJM Interconnection LLC or the electric company’s interconnection process. “Front-of-the-meter energy storage device” means an energy storage device where there is no load on the customer side of the meter beyond loads required to operate the energy storage device and includes: A separate electrical isolation device to prevent the flow of electricity when required for operation or maintenance; A separate energy measurement meter; At least one inverter; and The ability to be operated in an independent manner from other energy storage devices. “Generating station” has the meaning stated in COMAR 20.79.01.02. “Grid services” means the dispatch and control of an energy storage device to provide service to the electric company’s electric grid pursuant to an electric company tariff, service contract between the electric company and the owner of a registered energy storage device, or providing transmission-level grid services by participating in PJM Interconnection LLC wholesale markets. “Grid services mechanism” means “pay-for-performance” compensation from an electric company to owners of energy storage devices registered in the Maryland Energy Storage Program that provide grid services to the electric system. “Initiative” means an administrator’s Commission-approved structure in which energy storage devices can enroll that offers a mechanism targeted at a specific market segment. “Long-duration energy storage system (LDES)” means an energy storage device capable of continuously discharging electricity at its full rated capacity for 10 hours or longer but less than 24 hours. “Market segment” means the categorization of energy storage devices in the Maryland Energy Storage Program as front-of-the-meter electric transmission, front-of-the meter electric distribution, or behind-the-meter electric distribution. “Maryland energy storage program” means the initiatives and registrations that the Commission established to meet State energy storage targets pursuant to Public Utilities Article, §7-216.1, Annotated Code of Maryland. “Mechanism” means a procurement mechanism, a grid services mechanism, or a deployment incentive mechanism and may be implemented as a tariff, grant, rebate, or a contract. “Microgrid” means a network that can consist of interconnected loads, distributed energy resources, and energy storage devices within clearly defined electrical boundaries that acts as a single controllable network with respect to the electric system and that can be disconnected from the electric distribution or transmission system to operate independently. “Multi-day energy storage (Multi-day ES)” means an energy storage device capable of continuously discharging electricity at its full rated capacity for 24 hours or longer. “Notice to affected community” means by advertisement in a newspaper of general circulation in the county or municipal corporation affected by the application and on two types of social media platforms. “Overburdened community” has the same meaning as defined in Environment Article, §1–701, Annotated Code of Maryland. “Ownership and operations model” means the role that third-parties and electric companies play in owning and operating energy storage devices and may include, but are not limited to: A third-party ownership and operations model; An electric company ownership and operations model; An electric company owned and third party-operated model; A third-party owned and electric company operated model; and An electric company ownership and leaseback model. “Parcel” means a lot or group of lots devoted to a particular use including open spaces required or used in connection with that particular use. “Pre-existing energy storage device” means an energy storage device that is in-service or under construction prior to the effective date of this chapter. “Procurement mechanism” means a competitive solicitation by an administrator for energy storage devices providing grid services or a contract established by an administrator for grid services from energy storage devices. “Registrant” means the person that obtains registration of an energy storage device in the Maryland Energy Storage Program. “Registration” means the counting of an energy storage device in the Maryland Energy Storage Program energy storage device targets stated in Public Utilities Article, §7-216.1, Annotated Code of Maryland as of the date it is in-service. “Renewable on-site generating system” has the meaning stated in Public Utilities Article, §7-1001(i), Annotated Code of Maryland. “Short-duration energy storage (SDES)” means an energy storage device capable of continuously discharging electricity at its full rated capacity for less than 10 hours. “Technology type” means all types of electric storage device technologies, regardless of their size, storage medium, or operational purpose as classified in Public Utilities Article, §7-216, Annotated Code of Maryland. “Unclassified technology type” means a technology that is not stated in Public Utilities Article, §7-216, Annotated Code of Maryland. “Underserved community” has the same meaning as defined in Environment Article, §1–701, Annotated Code of Maryland. “Virtual power plant” means a collection of distributed energy resources, potentially including energy storage devices, that can provide grid services when aggregated together and coordinated with grid operations. In this chapter, NFPA 855, Standard for the Installation of Stationary Energy Storage Systems, 2023 is incorporated by reference. Targets. Targets for the cost-effective deployment of new energy storage devices may be established by the Commission in a manner as determined by the Commission or the legislature. The Commission may assign an administrator individual targets in a manner as determined by the Commission to help meet state energy storage targets pursuant to Public Utilities Article, §7-216.1, Annotated Code of Maryland and to support state policy goals in Public Utilities Article, §§7–801 and 7–802, Annotated Code of Maryland. An administrator shall propose to the Commission achievable goals for the enrollment of cost-effective energy storage devices in its initiatives in a manner as determined by the Commission. Targets may be proposed for front-of-the-meter and behind-the-meter energy storage device initiative installations. Targets may be proposed for energy storage device initiative installations on the electric distribution system and the electric transmission system. Targets may be proposed for energy storage device deployment using different ownership and operating models. Targets may consider energy storage device characteristics including but not limited to attributes such as SDES, LDES, and Multi-day ES durations. Targets may be proposed by electric companies for performance incentive mechanisms for goal achievement and the establishment of retail tariffs to support the Maryland Energy Storage Program. An administrator shall meet its assigned targets in a cost-effective manner. If an administrator determines at any time that it cannot meet its assigned targets cost-effectively, the administrator shall make a filing with the Commission seeking to reduce the targets, pursuant to Public Utilities Article, §7-216.1, Annotated Code of Maryland or propose an alternative. Counting for Enrollment and Registration. Administrators shall develop applications to enroll energy storage devices in an initiative. An energy storage device is enrolled in an initiative on the date the administrator sends notification of enrollment to the applicant. An administrator shall use information regarding energy storage device enrollments to determine the amount of energy storage devices required to meet end of delivery year targets. The Maryland Energy Storage Program Manager shall use information regarding registered energy storage devices to determine if end of delivery year targets were met. A pre-existing energy storage device shall be registered in the Maryland Energy Storage Program on the date it is discovered and cannot be enrolled in an initiative offering a deployment incentive mechanism or a procurement mechanism. To enroll in an initiative offering a procurement mechanism or a deployment mechanism, an energy storage device shall provide grid services. An administrator shall not double count an energy storage device participating in two mechanisms for reporting purposes pursuant to Regulation .13 of this chapter. An energy storage device shall not be enrolled in an initiative offering a deployment incentive mechanism and a procurement mechanism at the same time. An energy storage device may enroll in an electric company initiative offering a grid services mechanism and be registered in the Maryland Energy Storage Program and counted towards the targets stated in the Public Utilities Article, §7-216.1, Annotated Code of Maryland without enrolling in an initiative offering a procurement mechanism or deployment incentive mechanism. An energy storage device that is eligible for a deployment incentive mechanism shall receive a deployment incentive from the administrator only after the energy storage device is registered in the Maryland Energy Storage Program. An electric company shall not enroll an electric-company-owned energy storage device in an initiative in which it is the administrator unless approved by the Commission. An electric company may enroll an electric company-owned energy storage device in an initiative in which it is not an administrator. Grid Services. Each electric company shall implement necessary retail tariffs or service contracts for energy storage devices to provide grid services and to support initiative targets assigned by the Commission. Retail tariffs that include grid services shall also recognize the unique role that energy storage plays in reducing peak demand in the development of demand charges. Energy storage devices providing transmission-level grid services under PJM Interconnection LLC tariffs shall be counted toward achieving the Maryland Energy Storage Program targets set forth in Public Utilities Article, §7-216.1, Annotated Code of Maryland. Pre-Existing Energy Storage Devices. Pre-existing energy storage devices are not eligible to participate in an initiative offering a deployment incentive mechanism or a procurement mechanism. Pre-existing energy storage devices are eligible to participate in a grid services mechanism. Pre-existing energy storage devices participating in a grid services mechanism shall be registered in the Maryland Energy Storage Program as a pre-existing energy storage device. Administration. An administrator shall be approved by the Commission in a manner as determined by the Commission. An electric company may provide administration for an initiative it creates or contract with a third party to provide administration on its behalf. A State agency may provide administration for an initiative it creates or contract with a third party to provide administration on its behalf. The Commission shall assign a Commission person, whether internal or contracted, to serve as the Maryland Energy Storage Program Manager to: Coordinate with administrators on federal and State funding requests; Manage and report on the status of meeting energy storage targets stated in the Public Utilities Article, §7-216.1, Annotated Code of Maryland; Coordinate and develop initiative target allocation recommendations; and Advise the Commission on the plans of their initiatives. An administrator shall post information on applying for an initiative on an administrator’s website and through other standard promotional methods, as appropriate, and all promotional efforts shall include information to enable prospective owners of eligible energy storage devices to apply for initiatives. An electric company may identify desired locations for energy storage devices on its website and update this information at least annually. An administrator shall issue a notice to an energy storage device applicant following its approval or denial for enrollment in its initiative. An administrator shall make reasonable efforts to apply for all applicable State and federal grants, rebates, tax credits, loan guarantees, and other similar benefits as the benefits become available to help offset the cost of its initiative. An administrator shall also update initiative data as required in Regulation .13 of this chapter. Complaints. Any person may file a complaint with the Commission’s Executive Secretary regarding fairness, transparency, conflicts of interest, and timely resolutions, among other things. All energy storage devices owned by an electric company that inject power into the electric system shall be considered registered in the Maryland Energy Storage Program at the in-service date as reported to the Maryland Energy Storage Program Manager by the electric company. Electric company-owned pre-existing energy storage devices are registered as provided in Regulation .04(B) of this chapter. Prior to the commencement of the stakeholder engagement and participation requirements pursuant to Regulation .09 of this chapter, the electric company shall file a notification with the Commission containing information about the energy storage device. The date of this notification shall be the energy storage device enrollment date provided that the energy storage device is enrolled in an initiative. An electric company-owned energy storage device shall be subject to the stakeholder engagement and participation requirements for front-of-the-meter energy storage device applicants in Regulation .09 of this chapter and shall also be subject to the safety, siting, and environmental requirements for front-of-the-meter energy storage devices in Regulation .10 of this chapter, except to the extent exempted under Regulation .08G of this chapter, and the Department of Natural Resources Power Plant Research Program review and recommendations in Regulation .11 of this chapter, except to the extent exempted under Regulation .08G of this chapter. An electric company-owned energy storage device shall be subject to Commission approvals in Regulation .12 of this chapter, except to the extent exempted under Regulation .08G of this chapter. All applicants seeking to enroll an energy storage device in an initiative offering a behind-the-meter mechanism shall submit an application to an administrator prior to the beginning of construction, except for pre-existing energy storage devices seeking to enroll in a grid services mechanism, which may submit an application before or after construction. An application seeking to enroll in a behind-the-meter mechanism shall include an attestation by the applicant that: The energy storage device shall meet the definition of an “energy storage device” in the Public Utilities Article, §7-216, Annotated Code of Maryland. At the time of enrollment, the energy storage device’s planned electrical capacity in kilowatts and energy in kilowatt-hours that can be delivered to the grid or offset grid demand. The energy storage device shall meet NFPA 855 standards, if applicable, in addition to any other applicable federal and State requirements and local codes and standards. The energy storage device applicant shall meet a specified in-service date. An administrator shall deny any application for enrollment in a mechanism if the conditions in §B of this regulation, as applicable, are not met and shall provide the applicant an explanation for denial to aid the applicant in curing and resubmitting the application. The enrollment date shall be the date the administrator notifies the applicant that its application is approved. The date of registration in the Maryland Energy Storage Program is the in-service date, as noted in a certificate of completion to be tendered by the Program Administrator. Pre-existing energy storage devices are registered as required in Regulation .04(B) of this chapter. Should an applicant not meet the expected in-service date within 60 days of the certificate of completion, an administrator shall provide notification to an applicant that its enrollment will be withdrawn unless a request for extension is submitted to the administrator within 30 days and a notice is submitted to the electric company with a new projected in-service date. An administrator may approve an extension request for good cause or otherwise deny the request if good cause is not provided. An applicant may appeal to the Commission an administrator’s decision regarding an extension by filing an appeal with the Commission's Executive Secretary. All energy storage devices that are not owned by an electric company seeking to enroll in a procurement mechanism or deployment incentive mechanism shall submit an application form with an administrator prior to beginning construction. All non-electric company front-of-the meter energy storage device applications to enroll in a deployment incentive mechanism or procurement mechanism shall include an attestation that: The energy storage device meets the definition of an “energy storage device” in the Public Utilities Article, §7-216, Annotated Code of Maryland. The energy storage device is not a pre-existing energy storage device. At the time of enrollment, the energy storage device’s planned electrical capacity in kilowatts and energy in kilowatt-hours that can be delivered to the grid. If an energy storage device does not have capacity ratings in kilowatts and energy ratings in kilowatt-hours supplied by a manufacturer, the applicant shall provide these ratings in kilowatts and kilowatt-hours in a document describing the calculation methodology and showing the rating calculations. These capacity and energy rating calculations shall be certified by a professional engineer licensed in Maryland. The applicant shall make reasonable efforts to meet a specific in-service date. The energy storage device shall have a position in either the PJM new services queue or have filed an interconnection request with the electric company. An administrator shall deny any application for enrollment if the conditions in §B of this regulation, as applicable, are not met and shall provide the applicant an explanation for the denial to aid the applicant in curing and resubmitting the application. An administrator shall make a proposal when seeking Commission approval of an initiative for project maturity requirements to avoid speculative projects entering into enrollment. The registration date is the in-service date stated on a certificate of completion tendered by the administrator. Should an applicant for a deployment incentive mechanism initiative not meet the expected in-service date within 60 days of the certificate of completion, an administrator shall provide notification to an applicant that its enrollment will be withdrawn unless a request for extension is submitted to the administrator. An administrator may approve an extension request for good cause or otherwise deny the request if good cause is not provided. An applicant may appeal an administrator’s decision regarding an extension to the Commission by filing an appeal with the Commission's Executive Secretary. Should an applicant for a procurement mechanism initiative or a grid services mechanism initiative fail to meet the expected in-service date the terms and conditions of the executed contract apply. Non-electric company-owned front-of-the meter energy storage devices enrolling in an initiative shall be subject to the stakeholder engagement and participation requirements for all front-of-the-meter energy storage devices in Regulation .09 of this chapter and shall be subject to the safety, siting, and environmental requirements for front-of-the-meter energy storage devices in Regulation .10 of this chapter and the Department of Natural Resources Power Plant Research Program review and recommendations in Regulation .11 of this chapter, except to the extent exempted under Regulation .08G of this chapter. Non-electric company owned front-of-the meter energy storage devices shall be subject to Commission approvals in Regulation .12 of this chapter, except to the extent exempted under Regulation .08G of this chapter. A front-of-the-meter energy storage device applicant or registrant or an electric utility proposing a front-of-the-meter energy storage device may request from the Commission, a waiver or to be exempted from a requirement of this chapter that is not applicable to its energy storage device. All waiver requests shall state whether the energy storage device is currently: Operational, including the in-service date; Under construction, including the projected in-service date; or Proposed, including the expected construction start date and projected in-service date. All waiver requests shall describe the energy storage device’s technical and operational characteristics and explain why those characteristics, or other factors, make a requirement of the regulation inapplicable or would result in undue hardship. All waiver requests shall be served on the electric company with jurisdiction over the electric system to which the energy storage device seeks to enroll or register in an initiative or submits an application for Commission Energy Storage Construction Approvals and Waivers for energy storage devices not seeking to enroll in an initiative. For waiver requests for front-of-the-meter energy storage devices equal to or greater than 20 megawatt-hours per parcel, the waiver request shall be subject to state agency review pursuant to Regulation .11C of this chapter. For waiver requests for front-of-the-meter energy storage devices under 20 megawatt-hours per parcel, the Commission shall either approve, approve with modifications, or deny the waiver request after notice and an opportunity for public comment. The Commission may set a date for consideration of the waiver request at a hearing in the Commission’s Administrative Docket. An energy storage device that is approved in a Certificate of Public Convenience and Necessity (CPCN) proceeding conducted pursuant to Public Utilities Article, §7-207, Annotated Code of Maryland shall be enrolled by an administrator in the Maryland Energy Storage Program upon Commission approval of the CPCN and shall be registered by the Maryland Energy Storage Program Manager upon being placed in-service. The energy storage device is otherwise exempt from the engagement, safety, environmental, and siting regulations in Regulations .09, .10, .11 and .12 of this chapter that are replicated in the CPCN review process. A waiver request may cover multiple energy storage devices provided that all applicable sections of this regulation are followed. General Stakeholder Engagement and Participation Requirements Under Public Utilities Article, §7-219(c) and (d), Annotated Code of Maryland. The applicant or electric company, for a utility-owned energy storage device, shall provide immediate notice to affected communities on submission of an application for approval of the construction of a front-of-the-meter energy storage device to: The governing body of each county or municipal corporation in which any portion of the energy storage device is to be constructed; The governing body of each county or municipal corporation within 1 mile of the proposed location of the energy storage device; Each member of the General Assembly representing any part of a county in which any portion of the energy storage device is proposed to be constructed; Each member of the General Assembly representing any part of a county within 1 mile of the proposed location of the energy storage device; and The affected communities that are within 1 mile of the proposed location of the energy storage device. The applicant or electric company, for a utility-owned energy storage device, shall: Hold at least two public meetings in the affected community if the proposed location of the front-of-the-meter energy storage device is in an area considered to be an overburdened community or underserved community. Be exempt from meeting the requirements of §A(2)(a) of this regulation if an owner of a proposed front-of-the-meter energy storage device is located within the boundaries of an existing electricity generating station. Stakeholder Engagement and Participation for Proposed Energy Storage Devices with 20 Megawatt-Hours or Greater Energy Storage Device Capacity Total Sited Per Parcel. This section applies to an applicant or electric company, for a utility-owned energy storage device, with proposed energy storage devices greater than or equal to 20 megawatt-hours storage capacity total sited per parcel regardless of energy storage device technology. A minimum of 90 days prior to submitting an application for enrolling in an initiative or prior to filing for a zoning variance or permits, whichever is earlier, an applicant or electric company, for a utility-owned energy storage device, shall take the following steps to engage and consult with the county or municipal corporation in which any portion of the energy storage device is proposed to be located. Submit to the affected county or municipal corporation and each owner of land on which the energy storage device is located and owner of adjacent land, a conceptual site plan for the energy storage device. Submit to the affected county or municipal corporation a request for a meeting. The applicant shall make a good faith effort to meet with the staff of the affected county or municipal corporation. Submit to the affected county or municipal corporation a request for a preliminary report containing the following: A statement or finding whether the proposed energy storage device is consistent with the current comprehensive plan of the county or municipal corporation; A statement or finding whether the proposed energy storage device is consistent with the current zoning ordinance of the county or municipal corporation; and Suggestions for improving or modifying the application prior to submission of the application to the initiative administrator. If the applicant or electric company, for a utility-owned energy storage device, makes any material changes to the energy storage device as submitted to the administrator under this regulation, the applicant shall provide notice of the changes to the county or municipal corporation in which any portion of the energy storage device is proposed to be located. The applicant shall submit to the Department of Natural Resources Power Plant Research Program any report or other information received on their energy storage device from the county or municipal corporation in which any portion of the energy storage device is proposed to be located before filing an application for enrollment in an initiative or submits an application for Commission Energy Storage Construction Approvals and Waivers for energy storage devices not seeking to enroll in an initiative. The applicant or electric company, for a utility-owned energy storage device, shall, a minimum of 60 days prior to filing an application for enrollment, submitting an application for Commission Energy Storage Construction Approvals and Waivers for energy storage devices not seeking to enroll in an initiative, or prior to filing for a zoning variance or permits, whichever is earlier, meet with affected communities for the purposes of public engagement and participation. The applicant or electric company, for a utility-owned energy storage device, shall provide 14 days’ notice to affected communities and: If the proposed location of the front-of-the-meter energy storage device is in an area considered to be an overburdened community or underserved community, the applicant or electric company, for a utility-owned energy storage device, shall hold at least two public meetings in the affected community; and An owner of a proposed front-of-the-meter energy storage device that is located within the boundaries of an existing electricity generating station shall be exempt from meeting the requirements of §B(3)(a) of this regulation. The applicant or electric company, for a utility-owned energy storage device, shall submit to the Commission any report received on their energy storage device from the affected communities in which any portion of the energy storage device is proposed to be located including the following information: A description of the time, place, and manner in which the applicant held the public meeting with members of the affected communities; A description of the manner in which the applicant provided notice to the affected communities of the proposed public meeting with members of the affected communities; A copy of any meeting sign-in sheet voluntarily indicating persons of interest; and A description of any terms, incentives, or resolutions reached between the applicant and the affected communities. Affected communities including residential individuals, organizations, affected county or municipal corporations may also file information with the Commission on their position supporting, opposing, or requesting modifications to a front-of-the-meter energy storage device. The applicant or electric company, for a utility-owned energy storage device, may respond within 30 days of the Commission’s receipt of such information from affected communities, residential individuals, organizations, affected counties or municipal corporations. Applicability. This regulation applies to all front-of-the meter energy storage devices unless exempted pursuant to Regulation .08 of this chapter. Minimum Safety, Siting, and Environmental Requirements. An energy storage device that will not be constructed at an electricity generating station, electric substation, or commercial or industrial location shall meet the site requirements of Public Utilities Article, §7-219(e), Annotated Code of Maryland. An energy storage device shall adhere to the design, construction, operation, and maintenance standards in NFPA 855, if applicable, which is incorporated by reference in this chapter. The scope of NFPA 855 applies only to the technologies and energy storage devices of certain size thresholds whether owned and operated by an applicant or registrant. The applicant or registrant shall include an attestation from a professional engineer licensed in Maryland that its proposed energy storage device shall comply with the standards in NFPA 855, if applicable. If an applicant or registrant states that NFPA 855 is not applicable to the energy storage device technology utilized, the applicant or registrant shall include an attestation that the energy storage device shall be designed, constructed, installed, operated, and maintained in accordance with any applicable standards, regulations, and codes, in addition to complying with all state and local building, fire, and zoning requirements, and shall include a copy of the applicable standards, regulations, and codes with its application. In cases where the adherence with NFPA 855 or other applicable standards, regulations, and codes are not applicable, the applicant or registrant may seek a waiver pursuant to Regulation .08 of this chapter. An energy storage device shall have hazard mitigation and firefighting preparedness plans that include hazard mitigation, firefighting water needs, and fire tests. An energy storage device shall have emergency preparedness plans and procedures including pre-incident plans, emergency procedures, periodic safety inspections, first responder response, and training. An energy storage device shall comply with all applicable codes and standards. State Agency Application Review Coordinated by the Power Plant Research Program. An applicant with proposed energy storage devices 20 megawatt-hours storage capacity or greater total sited per parcel, regardless of energy storage device technology, shall no later than 45 days prior to filing an application for enrollment in an initiative, submitting an application for Commission Energy Storage Construction Approvals and Waivers for energy storage devices not seeking to enroll in an initiative, or prior to filing for a zoning variance or permits, whichever is earlier, consult with the staff of the Department of Natural Resources Power Plant Research Program to provide an overview of the proposed energy storage device. The Department of Natural Resources Power Plant Research Program review shall include the minimum safety, siting, and environmental requirements in Regulation .10 of this chapter. Other potential factors for which the Department of Natural Resources Power Plant Research Program may request information include the following. Environmental information required under COMAR 20.79.03.02. Natural Resources information required under COMAR 20.79.03.03. Socioeconomic information required under COMAR 20.79.03.04. EJSCREEN Reports pursuant to COMAR 20.79.03.05. Plans for compliance which are subject to COMAR 26.02.03.02 noise assessment regulations. Plans for compliance with all state and local building, fire, and zoning requirements. Information on grid reliability impacts. Decommissioning plans, if applicable, to ensure there is an appropriate financial surety instrument to cover the projected cost of decommissioning less projected salvage value at the end of projected project life. Electric companies are exempt from decommissioning requirements. Any additional information required by the Department of Natural Resources Power Plant Research Program for state agency review which shall not be unreasonably denied. State Agency Application Recommendations. The State agencies shall consider in its recommendation to the Commission, the information received from the applicant regarding stakeholder engagement and participation of counties, municipal corporations, or an affected community. The Department of Natural Resources Power Plant Research Program shall upon request, provide the Maryland Office of People’s Counsel the information it collected from the applicant. An energy storage device owner may respond within 30 days of the Commission’s receipt of such information from the State agencies. The State agencies shall file with the Commission within 4 months of receipt of all required information, a recommendation on whether the energy storage device enrollment in the Maryland Energy Storage Program or an application for Commission Energy Storage Construction Approvals and Waivers for energy storage devices not seeking to enroll in an initiative should be approved, approved with modifications, or denied. The State agencies shall also include any recommended conditions. An applicant shall have 10 days to agree or disagree with these State agency recommended conditions in a filing to the Commission. State Agency Waiver Reviews. The State agencies shall also consider waiver requests for front-of-the-meter energy storage devices equal to or greater than 20 megawatt-hours per parcel pursuant to Regulation .08 of this chapter and make recommendations to the Commission within 4 months of receipt of all required information to approve, approve with modifications, or deny the waiver request. Pursuant to Public Utilities Article, §7–219(B), Annotated Code of Maryland, a person may not begin construction of a front-of-the-meter energy storage device unless the construction has been approved by the Commission. Hearings and Approvals. State agency recommendations coordinated by the Department of Natural Resources Power Plant Research Program pursuant to Regulation .11 of this chapter may be considered by the Commission in its Administrative Docket within 60 days of filing of the state agency recommendations unless there is a filing by any other state agency, county, municipal corporation, an affected community, or any other stakeholder opposing the state agency recommendations that necessitates an evidentiary hearing. The Commission may approve, deny, or approve modifications to an application or a waiver request within 30 days of a hearing in either the Commission’s Administrative Docket or at an evidentiary hearing as determined by the Commission. Compliance and Revocation of Approval. If an energy storage device enrolled in an initiative is found to be in violation of any conditions approved for its inclusion, its approval may be revoked by the administrator and the energy storage device removed from enrollment in the initiative pursuant to a Commission determination. Appeals. Within 30 days of the filing of an appeal, the Commission may consider any motions to appeal any decisions. No change in an energy storage device’s application status, enrollment status, or registration status shall be made until the appeal is adjudicated by the Commission. Starting September 1 of the year after the Commission approves the first administrator’s initiative, an administrator shall file the following information for the prior delivery year with the Commission segregated by market segment, ownership, and operating model, technology type, and SDES, LDES, Multi-day ES durations: The following information regarding applications, enrollments, registrations, awards, and removals from initiatives: Total number of energy storage device initiative applications; Total kilowatts of energy storage device applications; Total kilowatt-hours of energy storage device applications; Total number of energy storage devices enrolled for each delivery year; Total kilowatts of energy storage devices enrolled for each delivery year; Total kilowatt-hours of energy storage devices enrolled for each delivery year; Total number of energy storage devices registered; Total kilowatts of energy storage devices registered; Total kilowatt-hours of energy storage devices registered; Total number of denied energy storage device applications; Total kilowatts of denied energy storage applications; Total kilowatt-hours of denied energy storage applications; Total number of energy storage devices removed from initiative enrollment or registration by delivery year for any reason; Total kilowatts of energy storage devices removed from an initiative enrollment or registration by delivery year for any reason; Total kilowatt-hours of energy storage devices removed from an initiative enrollment or registration by delivery year for any reason; Total kilowatts of energy storage device deployment incentives awarded in the prior delivery year; Total kilowatt-hours of energy storage device deployment incentives awarded in the prior delivery year; Total dollars for energy storage device deployment incentives awarded in the prior delivery year; Total kilowatts for energy storage device procurement mechanisms awarded in the prior delivery year; Total kilowatt-hours for energy storage device procurement mechanisms awarded in the prior delivery year; and Total dollars for energy storage device procurement mechanisms awarded in the prior delivery year; The following information regarding pre-existing energy storage devices: Total number of pre-existing energy storage devices discovered in the prior delivery year; Total kilowatts of pre-existing energy storage devices discovered in the prior delivery year; and Total kilowatt-hours of pre-existing energy storage devices discovered in the prior delivery year; Initiative administrative costs in the prior delivery year; Cumulative totals that include data from previous annual reports for the information in §§A(1), (2), and (3) of this regulation; Initiative assessments containing the following information: Initiative assessment regarding evaluation, measurement and verification benefit/costs expected and benefit/costs received in the prior delivery year; and Initiative assessment regarding equity impacts of the initiative in the prior delivery year, including: Total number, total kilowatts and kilowatt-hours of energy storage devices providing benefits to underserved communities; Percentage of number, total kilowatts and kilowatt-hours of energy storage devices providing benefits to underserved communities; and A description of actions taken to promote or incentivize initiative participation in underserved communities and any metrics used for monitoring underserved community participation; and Cumulative totals that include data from previous annual reports for the information in §A(2)(a) and (b) of this regulation. Maryland Energy Storage Program Annual Report. The Maryland Energy Storage Program Manager shall annually each October 1 file a report with the Commission that summarizes the information in §§A(1) and (2) of this regulation. Public Utilities Article, §§1-101, 2-113, 2-121, 7-207, 7-216, 7-216.1, 7-219, 7–1001, and 7-1005, Annotated Code of Maryland Effective date: March 30, 2026 (52:6 Md. R. 292)