Annually, the Chairman of the Commission shall forward to the Secretary of Natural Resources a 10-year plan listing possible and proposed sites, including the associated transmission routes, for the construction of electric plants within the State. The Chairman shall delete from the 10-year plan any site that the Secretary of Natural Resources identifies as unsuitable in accordance with the requirements of § 3-304 of the Natural Resources Article. The Chairman may include a site deleted from a 10-year plan under subparagraph (i) of this paragraph in a subsequent 10-year plan. The Chairman shall include information in the annual 10-year plan on current and projected efforts by electric companies and the Commission to moderate overall electrical generation demand and peak demand through the electric companies’ promotion of energy conservation by customers and through the electric companies’ use of alternative energy sources, including cogeneration. To the extent that the Commission requires an electric company to report the information described in paragraph (3) of this subsection, a small rural electric cooperative described in § 7-502(a) of this title may satisfy the requirement by submitting to the Commission a copy of the power requirement study that the small rural electric cooperative submits to the rural utilities service. The Commission shall evaluate the cost-effectiveness of the investments by electric companies in energy conservation to reduce electrical demand and in renewable energy sources to help meet electrical demand. The evaluation of investments shall include: the electric companies’ promotion and conduct of a building audit and weatherization program, including low-interest or no-interest electric company financing for the installation of energy conservation materials and renewable energy devices; utilization of renewable energy sources; promotion and utilization of electricity from cogeneration and wastes; and widespread public promotion of energy conservation programs.

If the Commission determines that a site is needed, the Commission, on its own motion, may request the Secretary of Natural Resources to purchase a power plant site as provided in Title 3, Subtitle 3 of the Natural Resources Article. In determining whether a need exists for the State to purchase a power plant site, the Commission shall consider: the suitability of sites owned by an electric company, both within and outside the State; the anticipated growth of electric power demand and the alternative means and locations for meeting that demand, both within and outside the State; and any other factors required by law. The Commission may determine that a power plant site is needed only after the Commission gives public notice and holds a public hearing. The hearing shall be held in the legislative district in which the site under consideration is located.

The Commission shall: impose an environmental surcharge per kilowatt hour of electricity distributed to retail electric customers within the State; and authorize each electric company to add the full amount of the surcharge to its customers’ bills. To the extent that an electric company fails to collect the surcharge from its customers, the amount uncollected shall be deemed a cost of power distribution and allowed and computed as such together with other allowable expenses for purposes of rate making. The Comptroller shall collect the revenue from the surcharge imposed under subsection (a) of this section and place the revenue into a special fund, the Environmental Trust Fund. The Comptroller shall maintain the method of collection of the surcharge from each electric company, and the money collected shall accrue to the Fund. Each fiscal year, the Secretary of Natural Resources shall coordinate the preparation of the annual budget required to carry out the provisions of the Power Plant Research Program under Title 3, Subtitle 3 of the Natural Resources Article. Each fiscal year, on approval of the annual budget by the General Assembly for the Power Plant Research Program, the Commission shall establish the amount of the environmental surcharge per kilowatt hour of electric energy distributed in the State that is to be imposed on each electric company in accordance with subsection (a) of this section. Notwithstanding any other provision of this subtitle, the amount of the surcharge for each account of each retail electric customer may not exceed the lesser of 0.15 mill per kilowatt hour or $1,000 per month. The Department of Natural Resources shall credit against the amount the Commission requires each electric company to pay into the Environmental Trust Fund 0.75% of the total surcharge amount attributed to the electric company on the basis of the amount of the electricity distributed in the State. To the extent that the Commission requires an electric company to report the total estimated kilowatt hours of electricity distributed in the State in order to calculate the surcharge under subsection (a)(1) of this section, a small rural electric cooperative described in § 7–502(a) of this title may satisfy the requirement by submitting to the Commission an estimate made in accordance with a formula approved by the Commission from information that the small rural electric cooperative submits to the rural utilities service that includes the required information. The surcharge imposed under this subtitle shall terminate on June 30, 2030.

In this section, “construction” has the meaning stated in § 7–207 of this subtitle. Notwithstanding any other provision of this division, at least 30 days before a hearing, a public service company shall provide to each owner of land and each owner of adjacent land, by certified mail, written notice of intent to run a line or similar transmission device over, on, or under the land. On receipt of an application for the construction of a transmission line under § 7–207 or § 7–208 of this subtitle, the Commission shall provide, or direct the person applying for a certificate of public convenience and necessity to provide, by certified mail, notice of intent to run a line or similar transmission device over, on, or under the land to: each owner of land that abuts the property where the construction is planned; and for construction of an overhead transmission line, each owner of land and each owner of adjacent land. Notice provided under this subsection shall include information regarding: any applicable right to file as an intervenor in the proceeding in accordance with § 3–106 of this article; the process for filing as an intervenor in the proceeding, including the method for filing and the location where the filing is required to be submitted; and contact information for the Commission and the website where the recipient may obtain additional information regarding intervention rights and procedures. The public service company shall determine the property owners from the current tax assessment records of the political subdivision in which the property is located. If the Commission determines that a person directed to provide notice under subsection (b)(2) of this section has failed to provide notice in accordance with this section: if the failure is willful or deliberate, the public hearing is invalidated and another hearing must take place; or if the failure is not willful or deliberate, the Commission may require another hearing to take place.

In this section, “modification” means a physical alteration of, replacement of, or other change to the facilities at a power plant, or a change in the fuel used by the plant, that could result in a change of the air emissions from the plant or from a generating unit of the plant. “Modification” does not include: routine maintenance or repairs of the facilities of a power plant; or a change that the Commission determines will not result in an increase in air emissions from the plant or from a generating unit of the plant. Subject to subsections (c) through (e) of this section, a person may not commence a modification without the prior approval of the Commission under this title. Unless the Commission orders otherwise, an application for a modification to a power plant shall be filed with the Commission at least 180 days before the date on which the modification is to commence. The applicant for the modification shall submit to the Commission and to the Department of the Environment all information relating to the modification, including: detailed plans and specifications; and the impact of the modification on air quality. The Commission shall render its decision within 150 days after the day the application is filed. Notwithstanding the provisions of this section, a modification to a power plant that involves the short-term inability to obtain the type of fuel normally used by the plant is subject to Title 2, Subtitle 5 of the Environment Article.

This section applies to the installation of pollution control equipment or a change in the method of operation at a generating station that a person performs in order to comply with Phase II pollution control requirements of the federal Clean Air Act. Any person that performs an installation or change in operation under subsection (a) of this section shall obtain prior review and approval of the Commission in accordance with: §§ 7-203, 7-207, and 7-208 of this subtitle; and the procedures set forth in § 7-205 of this subtitle and § 2-405 of the Environment Article. In order to meet compliance dates established under Title 2, Subtitle 10 of the Environment Article or the federal Clean Air Act, a Commission review and approval, or processing of an application for a certificate of public convenience and necessity under § 7-207 of this subtitle, shall be expedited and take precedence over other review and approval by the Commission if the review and approval or certificate of public convenience and necessity is required: for pollution control equipment or a change in the method of operation at a generating station; and for compliance with: Title 2, Subtitle 10 of the Environment Article; regulations adopted by the Department of the Environment under Title 2, Subtitle 10 of the Environment Article; or the federal Clean Air Act.

In this section the following words have the meanings indicated. “Advanced transmission technologies” means: grid–enhancing technologies; high performance conductors; or storage used as a transmission asset. “Brownfields site” means: a former industrial or commercial site identified by federal or State laws or regulation as contaminated or polluted; a closed landfill regulated by the Department of the Environment; or mined land. “Construction” means: any physical change at a site, including fabrication, erection, installation, or demolition; or the entry into a binding agreement or contractual obligation to purchase equipment exclusively for use in construction in the State or to undertake a program of actual construction in the State which cannot be canceled or modified without substantial loss to the owner or operator of the proposed generating station. “Construction” does not include a change that is needed for the temporary use of a site or route for nonutility purposes or for use in securing geological data, including any boring that is necessary to ascertain foundation conditions. “Generating station” does not include: a generating unit or facility that: is used for the production of electricity; has the capacity to produce not more than 2 megawatts of alternating current; and is installed with equipment that prevents the flow of electricity to the electric grid during time periods when the electric grid is out of service; a combination of two or more generating units or facilities that: are used for the production of electricity from a solar photovoltaic system or an eligible customer–generator that is subject to the provisions of § 7–306 of this title; are located on the same property or adjacent properties; have the capacity to produce, when calculated cumulatively for all generating units or facilities on the property or adjacent property, more than 2 megawatts but not more than 14 megawatts of alternating current; and for each individual generating unit or facility: has the capacity to produce not more than 2 megawatts of alternating current; is separately metered by the electric company; and does not export electricity for sale on the wholesale market under an agreement with PJM Interconnection, LLC; a generating unit or facility that: is used for the production of electricity for the purpose of: onsite emergency backup at a facility when service from the electric company is interrupted due to electric distribution or transmission system failure or when there is equipment failure at a site where critical infrastructure is located; and test and maintenance operations necessary to ensure functionality of the generating unit or facility in the event of a service interruption from the electric company due to electric distribution or transmission system failure or when there is equipment failure at a site where critical infrastructure is located; is installed with equipment that prevents the flow of electricity to the electric grid; is subject to a permit to construct issued by the Department of the Environment; and is installed at a facility that is part of critical infrastructure if the facility complies with all applicable regulations regarding noise level and testing hours; or a combination of two or more generating units or facilities that satisfy item (iii) of this paragraph. “Grid–enhancing technology” means hardware or software that increases the capacity, efficiency, or reliability of existing transmission systems. “Grid–enhancing technology” includes: a system that uses real–time or forecasted weather and operating conditions to determine the transfer capacity of transmission systems; technology that modulates circuit impedance or other electrical properties to reroute power flows and relieve congestion; and software that identifies switching configurations to reroute electricity and alleviate transmission constraints. “High performance conductors” means conductors, including advanced steel core conductors, carbon fiber and composite core conductors, and superconductors, that have a direct current electrical resistance that is at least 20% less than traditional ACSR conductors of a similar diameter when used on the electric transmission system at the standard operating temperature of 20 degrees Celsius. “Mined land” means the surface or subsurface of an area in which surface mining operations will be, are being, or have been conducted. “Mined land” includes: private ways and roads used for mining appurtenant to any surface mining area; land excavations; workings; and overburden. “Qualified generator lead line” means a transmission line and any associated advanced transmission technology designed to carry, or support the carrying of, a voltage in excess of 69,000 volts and would allow an out–of–state Tier 1 or Tier 2 renewable source to interconnect with a portion of the electric system in Maryland that is owned by an electric company. “Storage used as a transmission asset” means an energy storage facility that: is planned, operated, and recovers costs as a transmission facility that provides one or more transmission services, including congestion relief, voltage support, power flow control, or stability under any PJM tariffs and applicable FERC orders; except as authorized for transmission assets, is not dispatched for wholesale energy storage; and is eligible for cost recovery in transmission rates. “Traditional ACSR conductors” means electrical cables used in transmission systems that consist of a central core of steel wires surrounded by strands of aluminum. Except as provided in subparagraph (ii) of this paragraph, unless a certificate of public convenience and necessity for the construction is first obtained from the Commission, a person may not begin construction in the State of: a generating station; a qualified generator lead line; or an energy storage device that is part of a proposal approved by the Commission under § 7–1206 of this title. A person is not required to obtain a certificate of public convenience and necessity under this section if the person obtains: Commission approval for construction under § 7–207.1 of this subtitle; or a distributed generation certificate of public convenience and necessity under § 7–207.4 of this subtitle. Notwithstanding subparagraph (i) of this paragraph, a person may not apply to obtain a certificate of public convenience and necessity for construction of a qualified generator lead line unless: at least 90 days before the filing of an application for a certificate of public convenience and necessity, the person had in good faith offered the electric company that owns that portion of the electric grid in Maryland to which the qualified generator lead line would interconnect a full and fair opportunity for the electric company to construct the qualified generator lead line; and at any time at least 10 days before the filing of an application for a certificate of public convenience and necessity, the electric company: did not accept from the person a proposal or a negotiated version of the proposal under which the electric company would construct the qualified generator lead line; or stated in writing that the electric company did not intend to construct the qualified generator lead line. Notwithstanding any other provision of this section, a certificate of public convenience and necessity for the construction of a generating station that is part of a proposal approved by the Commission under § 7–1206 of this title shall be issued in accordance with § 7–207.4 of this subtitle. When a person applies for a certificate of public convenience and necessity for the construction of a generating station under this section, the application shall state whether the proposed generating station or the proposed modification is part of a proposal approved by the Commission under § 7–1206 of this title. The Commission may prioritize the review of an application for a certificate of public convenience and necessity under § 7–207.4 of this subtitle over the review of an application for a certificate of public convenience and necessity under this section. The Commission may extend the time for the review of an application for a certificate of public convenience and necessity under this section if, in accordance with subsubparagraph 1 of this subparagraph, the Commission has prioritized the review of an application for a certificate of public convenience and necessity under § 7–207.4 of this subtitle over the review of the application for a certificate of public convenience and necessity under this section. Unless a certificate of public convenience and necessity for the construction is first obtained from the Commission, and the Commission has found that the capacity is necessary to ensure a sufficient supply of electricity to customers in the State, a person may not exercise a right of condemnation in connection with the construction of a generating station. Except as provided in paragraph (4) of this subsection, unless a certificate of public convenience and necessity for the construction is first obtained from the Commission, a person may not begin construction of a transmission line that is designed to carry a voltage in excess of 69,000 volts or exercise a right of condemnation with the construction. For construction related to an existing transmission line that is designed to carry a voltage in excess of 69,000 volts, the Commission may waive the requirement in subparagraph (i) of this paragraph for good cause. In determining whether good cause exists under subparagraph (ii) of this paragraph, the Commission shall consider: whether the proposed construction: does not require the acquisition of new real property or additional rights–of–way through eminent domain; does not require larger or higher structures to accommodate increased voltage or larger conductors; is located substantially within an existing transmission right–of–way or existing transmission corridor or conduit system; and has a purpose independent of, and is not a part of, another project that would otherwise require the issuance of a certificate of public convenience and necessity; whether the applicant gave due consideration to alternatives to the proposed construction, including the use of advanced transmission technologies; and the extent to which: the construction substantially consists of new facilities; the cost of the facilities being constructed will be allocated to ratepayers; the facilities being constructed will impact power flow and reliability; and other factors, as determined by the Commission, support granting or denying a waiver for good cause. Except as provided in subsubparagraph 2 of this subparagraph, the Commission shall issue a�written decision granting or denying a waiver under subparagraph (ii) of this paragraph within 90 days after the applicant has submitted a waiver request. Unless otherwise agreed to by the applicant, the Commission may extend the period for issuing a written decision granting or denying a waiver under subparagraph (ii) of this paragraph for a period not to exceed 60 days if the Commission determines: the applicant has failed to provide sufficient information for the Commission to make a determination; or further consideration is necessary due to material impacts to the public or ratepayers under subparagraph (iii)3 of this paragraph. Within 30 days after issuing a written decision denying a waiver under subsubparagraph 1 or 2 of this subparagraph, the Commission shall issue a written decision that states the grounds for the denial. An applicant for a certificate of public convenience and necessity for the construction of a transmission line shall include in its application: evidence that the applicant considered, as part of the applicant’s internal planning process, any local, State, or federal government transmission planning processes and any transmission planning processes required by PJM Interconnection, including: an analysis of advanced transmission technologies and whether the use of the technologies will enhance the value of the new transmission line and therefore lead to increased ratepayer value through efficiency and avoided costs; alternative routings; technologies or modifications to one or more electric distribution systems in the State that are owned by the applicant or its affiliates that could avoid the need for the transmission line; the cost to ratepayers; resource adequacy; and any other information the Commission considers appropriate; and an analysis of the transmission line route selection, including: risks associated with the costs estimates; cost containment efforts; construction schedule; acquisition of land and rights–of–way; and the applicant’s plan to work with communities and stakeholders on proposed routes. Notwithstanding subparagraph (i) of this paragraph and subject to subparagraph (vii) of this paragraph, the Commission may issue a certificate of public convenience and necessity for the construction of a transmission line only if the applicant for the certificate of public convenience and necessity: is an electric company; or is or, on the start of commercial operation of the transmission line, will be subject to regulation as a public utility by an officer or an agency of the United States. The Commission may not issue a certificate of public convenience and necessity for the construction of a transmission line in the electric distribution service territory of an electric company to an applicant other than an electric company if: the transmission line is to be located solely within the electric distribution service territory of that electric company; and the cost of the transmission line is to be paid solely by that electric company and its ratepayers. This subparagraph applies to the construction of a transmission line for which a certificate of public convenience and necessity is required under this section. On issuance of a certificate of public convenience and necessity for the construction of a transmission line, a person may acquire by condemnation, in accordance with Title 12 of the Real Property Article, any property or right necessary for the construction or maintenance of the transmission line. A person may complete construction related to an existing transmission line, including repairs, if the construction is necessary to avoid an imminent safety hazard or reliability risk. Within 30 days after construction is completed under subparagraph (i) of this paragraph, a person shall file a report with the Commission describing the work that was completed. On receipt of an application for a certificate of public convenience and necessity under the section, the Commission shall provide notice immediately or require the applicant to provide notice immediately of the application to: the Department of Planning; the governing body, and if applicable the executive, of each county or municipal corporation in which any portion of the generating station, transmission line, or qualified generator lead line is proposed to be constructed; the governing body, and if applicable the executive, of each county or municipal corporation within 1 mile of the proposed location of the generating station, transmission line, or qualified generator lead line; each member of the General Assembly representing any part of a county in which any portion of the generating station, transmission line, or qualified generator lead line is proposed to be constructed; each member of the General Assembly representing any part of each county within 1 mile of the proposed location of the generating station, transmission line, or qualified generator lead line; for a proposed transmission line, each owner of land and each owner of adjacent land; and all other interested persons. The Commission, when sending the notice required under paragraph (1) of this subsection, shall forward a copy of the application to: each appropriate State unit and unit of local government for review, evaluation, and comment regarding the significance of the proposal to State, area–wide, and local plans or programs; and each member of the General Assembly included under paragraph (1)(iv) and (v) of this subsection who requests a copy of the application. On receipt of an application for a certificate of public convenience and necessity under this section, the Commission shall provide notice of the application on the Commission’s social media platforms and website. The Commission shall provide an opportunity for public comment and hold a public hearing on the application for a certificate of public convenience and necessity in each county and municipal corporation in which any portion of the construction of a generating station, a transmission line designed to carry a voltage in excess of 69,000 volts, or a qualified generator lead line is proposed to be located. The Commission may hold the public hearing virtually rather than in person if the Commission provides a comparable opportunity for public comment and participation in the hearing. The Commission shall hold the public hearing jointly with the governing body of the county or municipal corporation in which any portion of the construction of the generating station, transmission line, or qualified generator lead line is proposed to be located, unless the governing body declines to participate in the hearing. Once in each of the 4 successive weeks immediately before the hearing date, the Commission shall provide weekly notice of the public hearing and an opportunity for public comment: by advertisement in a newspaper of general circulation in the county or municipal corporation affected by the application; on two types of social media; and on the Commission’s website. Before a public hearing, the Commission shall coordinate with the governing body of the county or municipal corporation in which any portion of the construction of the generating station, transmission line, or qualified generator lead line is proposed to be located to identify additional options for providing, in an efficient and cost–effective manner, notice of the public hearing through other types of media that are familiar to the residents of the county or municipal corporation. On the day of a public hearing, an informational sign shall be posted prominently at or near each public entrance of the building in which the public hearing will be held. The informational sign required under subparagraph (i) of this paragraph shall: state the time, room number, and subject of the public hearing; and be at least 17 by 22 inches in size. If the public hearing is conducted virtually rather than in person, the Commission shall provide information on the hearing prominently on the Commission’s website. The Commission shall ensure presentation and recommendations from each interested State unit, and shall allow representatives of each State unit to sit during hearing of all parties. The Commission shall allow each State unit 15 days after the conclusion of the hearing to modify the State unit’s initial recommendations. The Commission shall take final action on an application for a certificate of public convenience and necessity only after due consideration of: the recommendation of the governing body of each county or municipal corporation in which any portion of the construction of the generating station, transmission line, or qualified generator lead line is proposed to be located; the effect of the generating station, transmission line, or qualified generator lead line on: the stability and reliability of the electric system; economics; esthetics; historic sites; when applicable, aviation safety as determined by the Maryland Aviation Administration and the administrator of the Federal Aviation Administration; when applicable, air quality and water pollution; and the availability of means for the required timely disposal of wastes produced by any generating station; the effect of climate change on the generating station, transmission line, or qualified generator lead line based on the best available scientific information recognized by the Intergovernmental Panel on Climate Change; for a generating station: the consistency of the application with the comprehensive plan and zoning of each county or municipal corporation where any portion of the generating station is proposed to be located; the efforts to resolve any issues presented by a county or municipal corporation where any portion of the generating station is proposed to be located; the impact of the generating station on the quantity of annual and long–term statewide greenhouse gas emissions, measured in the manner specified in § 2–1202 of the Environment Article and based on the best available scientific information recognized by the Intergovernmental Panel on Climate Change; and the consistency of the application with the State’s climate commitments for reducing statewide greenhouse gas emissions, including those specified in Title 2, Subtitle 12 of the Environment Article; and for a solar energy generating station specified under § 7–218 of this subtitle, whether the owner of a proposed solar energy generating station complies with the site requirements under § 7–218(f) of this subtitle. For the construction of a transmission line, in addition to the considerations listed in subsection (e) of this section, the Commission shall: take final action on an application for a certificate of public convenience and necessity only after due consideration of: the need to meet existing and future demand for electric service; evidence that alternatives have been considered by the applicant in accordance with subsection (b)(3)(v) of this section; and for construction related to a new transmission line, the alternative routes that the applicant considered, including the estimated capital and operating costs of each alternative route and a statement of the reason why the alternative route was rejected; require as an ongoing condition of the certificate of public convenience and necessity that an applicant comply with: all relevant agreements with PJM Interconnection, L.L.C., or its successors, related to the ongoing operation and maintenance of the transmission line; and all obligations imposed by the North America Electric Reliability Council and the Federal Energy Regulatory Commission related to the ongoing operation and maintenance of the transmission line; and require the applicant to identify whether the transmission line is proposed to be constructed on: an existing brownfields site; property that is subject to an existing easement; or a site where a tower structure or components of a tower structure used to support an overhead transmission line exist. The Commission may not authorize, and a person may not undertake, the construction of an overhead transmission line that is aligned with and within 1 mile of either end of a public airport runway, unless: the Federal Aviation Administration determines that the construction of an overhead transmission line will not constitute a hazard to air navigation; and the Maryland Aviation Administration concurs in that determination. A privately owned airport runway shall qualify as a public airport runway under this subsection only if the runway has been on file with the Federal Aviation Administration for at least 2 years as being open to the public without restriction. A county or municipal corporation has the authority to approve or deny any local permit required under a certificate of public convenience and necessity issued under this section or a distributed generation certificate of public convenience and necessity issued under § 7–207.4 of this subtitle. A county or municipal corporation shall approve or deny any local permits required under a certificate of public convenience and necessity issued under this section or a distributed generation certificate of public convenience and necessity issued under § 7–207.4 of this subtitle: within a reasonable time; and to the extent local laws are not preempted by State law, in accordance with local laws. A county or municipal corporation may not condition the approval of a local permit required under a certificate of public convenience and necessity issued under this section or a distributed generation certificate of public convenience and necessity issued under § 7–207.4 of this subtitle on receipt of any of the following approvals for any aspect of a generating station, a transmission line, or a qualified lead line proposed to be constructed under the certificate: a conditional use approval; a special exception approval; or a floating zone approval.

In this section, “generating station” does not include: a generating unit or facility that: is used for the production of electricity; has the capacity to produce not more than 2 megawatts of alternating current; and is installed with equipment that prevents the flow of electricity to the electric grid during time periods when the electric grid is out of service; a combination of two or more generating units or facilities that: are used for the production of electricity from a solar photovoltaic system or an eligible customer–generator that is subject to the provisions of § 7–306 of this title; are located on the same property or adjacent properties; have the capacity to produce, when calculated cumulatively for all generating units or facilities on the property or adjacent property, more than 2 megawatts but not more than 14 megawatts of alternating current; and for each individual generating unit or facility: has the capacity to produce not more than 2 megawatts of alternating current; is separately metered by the electric company; and does not export electricity for sale on the wholesale market under an agreement with PJM Interconnection, LLC; a generating unit or facility that: is used for the production of electricity for the purpose of: onsite emergency backup at a facility when service from the electric company is interrupted due to electric distribution or transmission system failure or when there is equipment failure at a site where critical infrastructure is located; and test and maintenance operations necessary to ensure functionality of the generating unit or facility in the event of a service interruption from the electric company due to electric distribution or transmission system failure or when there is equipment failure at a site where critical infrastructure is located; is installed with equipment that prevents the flow of electricity to the electric grid; is subject to a permit to construct issued by the Department of the Environment; and is installed at a facility that is part of critical infrastructure if the facility complies with all applicable regulations regarding noise level and testing hours; or a combination of two or more generating units or facilities that satisfy item (3) of this subsection. This section applies to a person who: constructs a generating station: designed to provide on–site generated electricity if: the capacity of the generating station does not exceed 70 megawatts; and the electricity that may be exported for sale from the generating station to the electric system is sold only on the wholesale market pursuant to an interconnection, operation, and maintenance agreement with the local electric company; or that produces electricity from wind if: the generating station is land–based; the capacity of the generating station does not exceed 70 megawatts; the electricity that may be exported for sale from the generating station to the electric system is sold only on the wholesale market pursuant to an interconnection, operation, and maintenance agreement with the local electric company; the Commission provides an opportunity for public comment at a public hearing as provided in subsection (g) of this section; and the generating station’s wind turbines are not located within a distance from the Patuxent River Naval Air Station that is determined by regulations adopted by the Commission in coordination with the Commander, Naval Air Warfare Center Aircraft Division, provided that the distance requirement under the regulation is: not greater than is necessary to encompass an area in which utility scale wind turbines could create Doppler radar interference for missions at the Patuxent River Naval Air Station; not greater than 46 miles, measured from location 38.29667N, 76.37668W; and subject to modification if necessary to reflect changes in missions or technology at the Patuxent River Naval Air Station or changes in wind energy technology; or constructs a generating station if: the capacity of the generating station does not exceed 25 megawatts; the electricity that may be exported for sale from the generating station to the electric system is sold only on the wholesale market pursuant to an interconnection, operation, and maintenance agreement with the local electric company; and at least 10% of the electricity generated at the generating station each year is consumed on–site. The Commission shall require a person that is exempted from the requirement to obtain a certificate of public convenience and necessity under § 7–207(b)(1)(ii)1 of this subtitle to obtain approval from the Commission under this section before the person may construct a generating station described in subsection (b) of this section. An application for approval under this section shall: be made to the Commission in writing on a form adopted by the Commission; be verified by oath or affirmation; and contain information that the Commission requires, including: proof of compliance with all applicable requirements of the independent system operator; and a copy of an interconnection, operation, and maintenance agreement between the generating station and the local electric company. On receipt of an application for approval under this section, the Commission shall provide notice immediately or require the applicant to provide notice immediately of the application to: the governing body of each county or municipal corporation in which any portion of the generating station is proposed to be constructed; the governing body of each county or municipal corporation within 1 mile of the proposed location of the generating station; each member of the General Assembly representing any part of a county in which any portion of the generating station is proposed to be constructed; and each member of the General Assembly representing any part of each county within 1 mile of the proposed location of the generating station. When reviewing an application for approval under this section, the Commission shall: ensure the safety and reliability of the electric system; require the person constructing the generating station to notify the Commission 2 weeks before the first export of electricity from a generating station approved under this section; and conduct its review and approval in an expeditious manner. Except for the notice required under subsection (d) of this section, the Commission may waive an element of the approval process under this section if the Commission determines that the waiver is in the public interest. The Commission shall provide an opportunity for public comment and hold a public hearing as provided under this subsection on an application for approval made under subsection (b)(1)(ii) of this section in each county and municipal corporation in which any portion of the construction of a generating station is proposed to be located. Upon the request of the governing body of a county or municipal corporation in which any portion of the construction of a generating station is proposed to be located, the Commission shall hold the public hearing jointly with the governing body. Once in each of 2 successive weeks immediately before the hearing date, the Commission, at the expense of the applicant, shall provide weekly notice of the public hearing and opportunity for public comment by advertisement in a newspaper of general circulation in the county or municipal corporation affected by the application.

On or before December 1, 2025, and each December 1 thereafter, the owner or operator of a generating unit or facility specified under § 7–207(a)(4)(iii) of this subtitle shall submit to the Department of the Environment a report that includes: dates on which the generating unit or facility was used for the previous 12 months; the length of time the generating unit or facility was operated for the previous 12 months; and for each instance that the generating unit or facility was operated over the previous 12 months, the reason the generating unit or facility was operated. Unless the Department of the Environment determines that the report required under paragraph (1) of this subsection poses a risk to cybersecurity, national security, or the security of the State, the report: shall be made publicly available; and may not be redacted. On or before December 1, 2025, and every 2 years thereafter, the Maryland Energy Administration, in consultation with the Department of Commerce and industry representatives selected by the Department of Commerce, shall, in accordance with § 2–1257 of the State Government Article, submit a report to the General Assembly detailing: advancements in backup generation technologies; the commercial availability of new backup generation technologies that can be procured; and the affordability of adopting new backup generation technologies.

In this section the following words have the meanings indicated. “Distributed generation certificate of public convenience and necessity” or “DGCPCN” means a certificate issued by the Commission under this section that authorizes the construction and operation of a distributed solar energy generating system. “Distributed solar energy generating system” means a community solar energy generating system, as defined in § 7–306.2 of this title, that: would be required to obtain a certificate of public convenience and necessity under § 7–207 of this subtitle if the system does not obtain a DGCPCN under this section; has a capacity to produce more than 2 megawatts but not more than 5 megawatts of alternating current as measured by the alternating current rating of the system’s inverter; and is not located within a municipal corporation. “Forest” has the meaning stated in § 5–1601 of the Natural Resources Article. “Power Plant Research Program” means the program within the Department of Natural Resources under Title 3, Subtitle 3 of the Natural Resources Article. “Standard licensing conditions” means the predetermined licensing conditions adopted by the Commission under this section for the construction and operation of a distributed solar energy generating system that has been issued a DGCPCN under this section. “Standard siting and design requirements” means the predetermined objective requirements adopted by the Commission under this section for the siting and design of a distributed solar energy generating system that has been issued a DGCPCN under this section. On or before July 1, 2026, the Power Plant Research Program, after giving notice and opportunity for public comment, shall develop and submit to the Commission proposed standard siting and design requirements and proposed standard licensing conditions for the issuance of a DGCPCN. In developing the proposed standard siting and design requirements and the proposed standard licensing conditions, the Power Plant Research Program shall: consider achievement of the State’s climate and renewable energy commitments; consider reasonable setbacks and landscape screening requirements; consider environmental preservation, including prohibitions on forest clearance except where necessary to: reduce solar panel shading near the perimeter of the project site; facilitate interconnection infrastructure; and ensure adequate site access; consider stormwater management, erosion and sediment control, and site stabilization, accounting for: the effects on runoff from solar panels and associated equipment; the effects of soil characteristics and compaction on runoff; and the effects of the ground cover under and between the solar panels on runoff; consider minimization and mitigation of the effects of a distributed solar energy generating system on historic sites; consider public safety; consider industry best practices; consider ensuring the stability and reliability of the electric system by requiring the applicant to submit a signed interconnection agreement with the electric company before the start of construction; consider licensing conditions previously adopted by the Commission for solar energy generating systems, including requirements related to decommissioning; ensure the standard siting and design requirements are consistent with § 7–218 of this subtitle; and consider any other requirements determined necessary by the Power Plant Research Program. Subject to paragraph (2) of this subsection, on or before July 1, 2027, the Commission shall adopt regulations to: implement standard siting and design requirements and standard licensing conditions for a DGCPCN; specify the form of the application for a distributed solar energy generating system to receive a DGCPCN and any application fee; specify the Commission’s procedure for processing an application for a DGCPCN; and establish the time period within which the Power Plant Research Program must make the determination under subsection (f) of this section. The Commission shall: consider the proposed standard siting and design requirements and the proposed standard licensing conditions developed by the Power Plant Research Program in adopting the regulations under this subsection; and ensure regulations adopted to implement standard siting and design requirements are consistent with § 7–218 of this subtitle. The Commission, in consultation with the Power Plant Research Program, may periodically solicit public comments regarding improvements to the standard siting and design requirements and standard licensing conditions for a DGCPCN. The process for soliciting public comments under subparagraph (i) of this paragraph shall be the same as the process for soliciting public comment regarding the adoption of a regulation. The Commission and the Department of Natural Resources may jointly set an application fee for a DGCPCN application at an amount that the Commission and the Department of Natural Resources determine may offset the administrative costs of the DGCPCN approval process that are incurred by the Commission and the Department of Natural Resources. The administrative costs under subparagraph (i) of this paragraph shall be based on an estimate of the number of DGCPCN applications that will be filed with the Commission each year. A person may not begin construction of a distributed solar energy generating system unless: a DGCPCN is first obtained from the Commission in accordance with this section; or a certificate of public convenience and necessity is first obtained from the Commission in accordance with § 7–207 of this subtitle. At least 30 days before submitting an application for a DGCPCN to the Commission, the applicant shall submit a copy of the application to the governing body of the county in which the distributed solar energy generating system is proposed to be located. When a person submits an application for a DGCPCN to the Commission, the person shall submit a copy of the application to the Power Plant Research Program. After receiving an application for a DGCPCN but before a determination is made under subsection (f) of this section, the Commission shall provide an opportunity for public comment and hold a public hearing on an application for a DGCPCN in each county in which any portion of the construction of the distributed solar energy generating system is proposed to be located. The Commission may hold the public hearing virtually rather than in person if the Commission provides a comparable opportunity for public comment and participation in the hearing. After an application for a DGCPCN is filed with the Commission and within the time period set by the Commission under subsection (c)(1)(iv) of this section, the Power Plant Research Program shall: determine whether the distributed solar energy generating system satisfies the standard siting and design requirements for the DGCPCN; and notify the Commission in writing as to the determination made under item (i) of this paragraph, including how an application that is determined not to satisfy the standard siting and design requirements can cure the deficiency. In making a determination under paragraph (1) of this subsection, the Power Plant Research Program shall consider public comments received by the Commission. Within 60 days after the Power Plant Research Program makes its determination under subsection (f)(1) of this section, the Commission shall schedule a hearing to consider the application for a DGCPCN. At the hearing under paragraph (1) of this subsection, the Commission shall determine whether the proposed distributed solar energy generating system satisfies the standard siting and design requirements. The Commission shall issue a DGCPCN to an applicant to construct a proposed distributed solar energy generating system subject to the standard licensing conditions if the Commission determines that the proposed distributed solar energy generating system satisfies the standard siting and design requirements. The Commission may not issue a DGCPCN to an applicant if the proposed distributed solar energy generating system does not satisfy each of the standard siting and design requirements. In making a determination under this subsection, the Commission shall consider public comments received by the Commission under subsection (e) of this section. A DGCPCN issued by the Commission under this section shall require the person constructing the distributed solar energy generating system to obtain the following permits and approvals from the county, municipal corporation, or soil conservation district in which the system is to be constructed: site plan approval; stormwater management plan approval; erosion and sediment control plan approval; all applicable building and electrical permits; and any additional local permit required by the standard licensing conditions. The provisions of § 7–207(h) of this subtitle shall apply to any permits and approvals required under paragraph (1) of this subsection. A DGCPCN issued by the Commission under this section has the same force and effect as a certificate of public convenience and necessity issued under § 7–207 of this subtitle.

In this section the following words have the meanings indicated. “Construction” has the meaning stated in § 7–207 of this subtitle. “Dispatchable energy generation project” means a generating station or energy storage device that is part of a proposal approved by the Commission under § 7–1206 of this title. “Dispatchable energy generation project” includes any associated infrastructure necessary to interconnect the generating station to the electric distribution system. “Energy storage device” has the meaning stated in § 7–216 of this subtitle. “Generating station” has the meaning stated in § 7–207 of this subtitle. “Large capacity energy resource” means a generating station that: on or before January 1, 2025: has applied to PJM for interconnection approval; or has been approved by PJM for interconnection; has a capacity rating equal to or greater than 20 megawatts after accounting for the effective load carrying capability; and is part of a proposal approved by the Commission under § 7–1206 of this title. “Qualifying project” means a dispatchable energy generation project or large capacity energy resource project that has been approved by the Commission under § 7–1208 of this title. This section applies only to an application for a certificate of public convenience and necessity for the construction of a qualifying project. Unless a certificate of public convenience and necessity is first obtained from the Commission in accordance with this section or § 7–207 of this subtitle, a person may not construct a qualifying project. A certificate of public convenience and necessity issued under this section bestows the same rights as a certificate of public convenience and necessity issued under § 7–207 of this subtitle. A person applying for a certificate of public convenience and necessity under this section shall: at least 45 days before submitting an application under this section, notify the Commission and the Power Plant Research Program; and unless otherwise specified under this section, complete all pre–application requirements before submitting an application. Except as provided in paragraph (2) of this subsection, the timelines associated with the normal pre–application requirements under § 7–207 of this subtitle, including the requirements under COMAR 20.79.01.04 and COMAR 20.79.01.05, shall be shortened to 45 days for applications submitted under this section. If the proposed location of a qualifying project is in an overburdened community or underserved community, as defined in § 1–701 of the Environment Article, the timeline for the pre–application requirements under COMAR 20.79.01.04 and COMAR 20.79.01.05 shall remain at 90 days. Once five applications have been received under this section within a 2–month period, the Commission may delay processing any subsequent applications submitted under this section without impacting the timelines specified in this section. The Commission shall: expedite all proceedings for the review and approval of a certificate of public convenience and necessity for a qualifying project; and take final action on a certificate of public convenience and necessity for a qualifying project not later than 295 days after the Power Plant Research Program determines that the application is complete in accordance with COMAR 20.79.01.10. The Commission may extend the time to take final action on a certificate of public convenience and necessity under this section if an applicant fails to comply with the law, regulatory requirements, or Commission orders associated with obtaining a certificate of public convenience and necessity. Notwithstanding any other law or regulation, in order to meet the required timelines for the issuance of a certificate of public convenience and necessity under this section, the Commission may review and determine whether to approve decommissioning plans for a qualifying project after the certificate of public convenience and necessity has been issued. In evaluating an application for a certificate of public convenience and necessity under this section, the Commission may contract for the services of independent consultants and experts.

A person that submits an application for approval of the construction of a solar energy generating station in accordance with § 7–207, § 7–207.1, or § 7–207.4 of this subtitle shall: request, within 90 days before beginning construction, the Commissioner of Labor and Industry to determine the prevailing wage rate for each classification of worker required to perform work on the project; require that any contractor or subcontractor on the project pay its employees not less than the prevailing wage rate as determined by the Commissioner of Labor and Industry under item (1) of this subsection and Title 17, Subtitle 2 of the State Finance and Procurement Article; and include in the application an attestation that the person shall comply with the provisions of this section and any additional requirements imposed by the Commissioner of Labor and Industry. In accordance with Title 3, Subtitle 5 of the Labor and Employment Article, the Maryland Department of Labor shall enforce the requirement under subsection (a)(2) of this section for contractors and subcontractors to pay employees not less than the prevailing wage rate determined by the Commissioner of Labor and Industry.

In this section, “advanced transmission technologies” has the meaning stated in § 7–207 of this subtitle. Subject to paragraphs (2) and (3) of this subsection, on or before December 1, 2026, and every 4 years thereafter, each owner or operator of a transmission line shall submit to the Commission a report that: identifies areas of significant transmission congestion costs for the immediately preceding 3 years and any reasonably foreseeable transmission constraints for the 5 years immediately following the date of the report; identifies the projected or actual cost to ratepayers as a result of past and projected future transmission congestion; identifies the feasibility and cost of using alternative means of addressing transmission congestion, including the use of advanced transmission technologies; identifies the economic, environmental, and social issues posed by the use of each alternative means identified under item (iii) of this paragraph; and if feasible, proposes an advanced transmission technology implementation plan to address areas of transmission congestion identified under item (i) of this paragraph. The report required under paragraph (1) of this subsection shall distinguish between regional and local congestion drivers and reference the PJM planning inputs or any other planning inputs used to support the congestion forecasts and proposed congestion relief solutions. The Commission may modify the reporting schedule specified in paragraph (1) of this subsection. An owner or operator of a transmission line may use any available data from PJM or other sources in completing the report required under this section.

In this section the following words have the meanings indicated. “Construction” has the meaning stated in § 7–207 of this subtitle. “Generating station” does not include: a generating unit or facility that: is used for the production of electricity for the purpose of: onsite emergency backup at a facility when service from the electric company is interrupted due to electric distribution or transmission system failure or when there is equipment failure at a site where critical infrastructure is located; and test and maintenance operations necessary to ensure functionality of the generating unit or facility in the event of an interruption of service from the electric company due to electric distribution or transmission system failure or when there is equipment failure at a site where critical infrastructure is located; is installed with equipment that prevents the flow of electricity to the electric grid; is subject to a permit to construct issued by the Department of the Environment; and is installed at a facility that is part of critical infrastructure if the facility complies with all applicable regulations regarding noise level and testing hours; or a combination of two or more generating units or facilities that satisfy item (i) of this paragraph. “Qualified offshore wind project” has the meaning stated in § 7–701 of this title. “Qualified submerged renewable energy line” means: a line carrying electricity supply and connecting a qualified offshore wind project to the transmission system; and a line in which the portions of the line crossing any submerged lands or any part of a beach erosion control district are buried or submerged. This section applies to any person: constructing a generating station and its associated transmission lines designed to carry a voltage in excess of 69,000 volts; exercising the right of condemnation in connection with the construction; or constructing a qualified submerged renewable energy line. To obtain the certificate of public convenience and necessity required under § 7–207 of this subtitle for construction under this section, a person shall file an application with the Commission at least 2 years before construction of the facility will commence. The Commission may waive the 2–year requirement on a showing of good cause. The applicant shall: include in an application under this section the information that the Commission requests initially; and furnish any additional information that the Commission requests subsequently. On the receipt of an application under this section, together with any additional information requested under subsection (d)(2) of this section, the Commission shall provide notice to: for a proposed transmission line, each owner of land and each owner of adjacent land; all interested persons; the Department of Agriculture; the Department of Commerce; the Department of the Environment; the Department of Natural Resources; the Department of Transportation; the Department of Planning; and the Maryland Energy Administration. On receipt of an application under this section, and whenever additional information is received under subsection (d)(2) of this section, the Commission shall provide notice immediately or require the applicant to provide notice immediately to: the governing body of each county or municipal corporation in which any portion of the generating station or the associated transmission lines is proposed to be constructed; the governing body of each county or municipal corporation within 1 mile of the proposed location of the generating station or the associated transmission lines; each member of the General Assembly representing any part of a county in which any portion of the generating station or the associated transmission lines is proposed to be constructed; and each member of the General Assembly representing any part of each county within 1 mile of the proposed location of the generating station or the associated transmission lines. The Commission shall hold a public hearing on the application as required by § 7–207 of this subtitle after: the receipt of any additional information requested under subsection (d)(2) of this section that the Commission considers necessary; and any publication of notice the Commission considers to be proper. At the public hearing, the Commission shall ensure presentation of the information and recommendations of the State units specified in paragraph (1) of this subsection and shall allow the official representative of each unit to sit during hearing of all parties. Based on the evidence relating to the unit’s areas of concern, the Commission shall allow each unit 15 days after the conclusion of the hearing to modify or affirm the unit’s initial recommendations. Within 90 days after the conclusion of the hearing on an application under this section, the Commission shall: grant a certificate of public convenience and necessity unconditionally; grant the certificate, subject to conditions the Commission determines to be appropriate; or deny the certificate; and notify all interested parties of its decision. The Commission shall include in each certificate it issues under subsection (f) of this section: the requirements of the federal and State environmental laws and standards that are identified by the Department of the Environment; and the methods and conditions that the Commission determines are appropriate to comply with those environmental laws and standards. The Commission may not adopt any method or condition under paragraph (1)(ii) of this subsection that the Department of the Environment determines is inconsistent with federal and State environmental laws and standards. A decision of the Commission regarding the issuance of a certificate requires the vote of a majority of the members of the Commission. If a majority of the members of the Commission fails to reach agreement on the conditions to be attached to a conditional certificate, the certificate shall be denied. The grant of a certificate by the Commission to any person under subsection (f) of this section constitutes: authority for the person to dredge and construct bulkheads in the waters or private wetlands of the State and to appropriate or use the waters; and registration and a permit to construct, as required under Title 2, Subtitle 4 of the Environment Article. A county or municipal corporation has the authority to approve or deny any local permit required under a certificate of public convenience and necessity issued under this section. A county or municipal corporation shall approve or deny any local permits required under a certificate of public convenience and necessity issued under this section: within a reasonable time; and to the extent local laws are not preempted by State law, in accordance with local laws. A county or municipal corporation may not condition the approval of a local permit required under a certificate of public convenience and necessity issued under this section on receipt of any of the following approvals for any aspect of a generating station, a transmission line, or a qualified lead line proposed to be constructed under the certificate: a conditional use approval; a special exception approval; or a floating zone approval.

The Commission shall examine alternatives to the construction of a new transmission line in a service area, including the use of an existing transmission line of another company, if: the existing transmission line is convenient to the service area; or the use of the transmission line will best promote economic and efficient service to the public. In considering the use of an existing transmission line under subsection (a) of this section, the Commission need not consider whether the company that owns the line has a franchise in a service area.

This section does not apply to Baltimore City. A municipal corporation may not build, maintain, or operate a plant for supplying gas or electricity for other than municipal purposes unless the municipal corporation has a certificate of authority from the Commission. If the Commission denies the certificate of authority, the municipal corporation may not reapply for a certificate until at least 6 months have elapsed from the date that the Commission denied the previous application. Subject to subsection (b) of this section, a municipal corporation in the business of supplying electricity for other than municipal purposes may own or finance an interest in an electric plant to secure an entitlement of electricity for its customers. If the boundaries of a municipal corporation are enlarged by annexation, the municipal corporation may acquire the exclusive right to supply electricity within the annexed area if: the municipal corporation: files a petition with the Commission seeking approval to acquire the exclusive right to supply electricity within the annexed area; provides a copy of the petition to each electric company whose service territory or electric plant will be affected by the annexation; and attaches to the petition a copy of the amendment to the municipal corporation charter that describes the area annexed and a description of the service territory, plant, equipment, and customers of each electric company that is likely to be affected by the annexation; and the Commission determines that modification of the service territory of an electric company and the transfer of a franchise or right under the franchise is in the public interest. A municipal corporation that acquires the exclusive right under subsection (d) of this section to supply electricity within an area annexed by the municipal corporation may exercise the right of eminent domain to acquire the existing installed facilities of each electric company within the annexed area that are used solely to supply electricity to the annexed area. The value of any property taken under paragraph (1) of this subsection shall be determined as of the date of the taking.

The General Assembly finds and declares that it is the policy of the State to encourage the development of clean, carbon–free nuclear power, including development through innovative designs. The Maryland Energy Administration, in coordination with the Commission and the Department of Natural Resources, shall pursue: cost–sharing agreements with neighboring states in the PJM region to mitigate the risks of developing new nuclear energy generating stations; and agreements with federal agencies regarding the siting of small modular reactors: on federal land; or on or near federal facilities, including military and national security installations. On or before December 1, 2026, the Maryland Energy Administration shall report to the General Assembly, in accordance with § 2–1257 of the State Government Article, on: the status of the efforts made under subsection (b) of this section, including an assessment of any opportunities to participate with other states, federal agencies, and public or private partners in a multistate procurement of new nuclear energy technology; and an evaluation and status of the nuclear energy procurement process established under Subtitle 12, Part III of this title.

On or before July 1, 2008, the Commission shall adopt regulations governing the purchase of liquid–immersed distribution transformers by electric companies. Except as provided in subsection (c) of this section, the regulations shall be consistent with the regulations adopted by the U.S. Department of Energy. Subject to paragraph (2) of this subsection, the regulations shall ensure that, subject to availability, purchases of liquid–immersed distribution transformers by electric companies occurring on or after January 1, 2009, are based on the life–cycle cost methodology contained in Section 2 of Standard TP–1–2002 published by the National Electrical Manufacturers Association. The regulations adopted under this section may not apply to an electric cooperative that supplies electricity to less than 60,000 electric meters in the State. For electric companies that maintain inventories of distribution transformers in the State for installation in adjacent service areas outside of the State, the Commission may also consider additional inventory management costs as costs for inclusion within the life–cycle cost methodology to be used by electric companies for purposes of this section.

In this section the following words have the meanings indicated. “Eligible reliability measure” means a replacement of or an improvement in existing infrastructure of an electric company that: is made on or after June 1, 2014; is designed to improve public safety or infrastructure reliability; does not increase the revenue of an electric company by connecting an improvement directly to new customers; and is not included in the current rate base of the electric company as determined in the electric company’s most recent base rate proceeding. “Eligible reliability measure” includes vegetation management measures that are necessary to meet applicable service quality and reliability standards under this section. “Fund” means the Electric Reliability Remediation Fund established under subsection (j) of this section. “System–average interruption duration index” or “SAIDI” means the sum of the customer interruption hours divided by the total number of customers served. “System–average interruption frequency index” or “SAIFI” means the sum of the number of customer interruptions divided by the total number of customers served. It is the goal of the State that each electric company provide its customers with high levels of service quality and reliability in a cost–effective manner, as measured by objective and verifiable standards, and that each electric company be held accountable if it fails to deliver reliable service according to those standards. This section does not apply to small rural electric cooperatives or municipal electric companies. On or before July 1, 2012, the Commission shall adopt regulations that implement service quality and reliability standards relating to the delivery of electricity to retail customers by electric companies through their distribution systems, using: SAIFI; SAIDI; and any other performance measurement that the Commission determines to be reasonable. The regulations adopted under subsection (d) of this section shall: include service quality and reliability standards, including standards relating to: service interruption; downed wire response; customer communications; vegetation management; periodic equipment inspections; annual reliability reporting; and any other standards established by the Commission; account for major outages caused by events outside the control of an electric company; and for an electric company that fails to meet the applicable service quality and reliability standards, require the electric company to file a corrective action plan that details specific actions the company will take to meet the standards. The regulations adopted under subsection (d) of this section may include a separate reliability standard for each electric company in order to account for system reliability differentiating factors, including: system design; existing infrastructure; customer density; and geography. In adopting the regulations required under subsection (d) of this section, the Commission shall: consider applicable standards of the Institute of Electrical and Electronics Engineers; ensure that the service quality and reliability standards are cost–effective; and with respect to standards relating to vegetation management, consider: limitations on an electric company’s right to access private property; and customer acceptance of vegetation management initiatives. A county or municipal corporation may not adopt or enforce a local law, rule, or regulation or take any other action that interferes with, or materially increases the cost of the work of an electric company toward, compliance with the vegetation management standards adopted under subsection (d) of this section. On or before September 1 of each year, the Commission shall determine whether each electric company has met the service quality and reliability standards adopted by the Commission for that electric company under subsection (d) of this section and under § 7–213.1(e) of this subtitle. This paragraph does not apply to electric cooperatives. The Commission shall take appropriate corrective action against an electric company that fails to meet any or all of the applicable service quality and reliability standards, including the imposition of appropriate civil penalties for noncompliance as provided in § 13–201 of this article. A civil penalty assessed under § 13–201 of this article for a violation of the service quality and reliability standards under this section shall be paid into the Fund. An electric company may not recover the cost of any civil penalty paid under this section from ratepayers. On or before April 1 of each year, each electric company shall submit to the Commission an annual performance report that summarizes the actual electric service reliability results for the preceding year. The annual performance report shall include: the electric company’s average 3–year performance results; actual year–end performance measure results; an assessment of the results and effectiveness of the reliability objectives, planned actions and projects, programs, and load studies in achieving an acceptable reliability level; and annual information that the Commission determines necessary to assess the electric company’s efforts to maintain reliable electric service to all customers in the electric company’s service territory, including: current year expenditures, labor resource hours, and progress measures for each capital and maintenance program designed to support the maintenance of reliable electric service; the number of outages by outage type; the number of outages by outage cause; the total number of customers that experienced an outage; the total customer minutes of outage time; and 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. At the request of an electric company, the Commission shall hold a hearing to discuss the annual performance report of the electric company. This section may not be construed to limit the Commission’s authority to adopt and enforce engineering and safety standards for electric companies. The Commission and each electric company assessed a penalty for a violation of service quality and reliability standards under this section shall establish priorities for targeting remediation efforts to improve electric service quality and reliability for the worst performing feeder lines and other distribution lines and equipment that shall be paid for, in whole or in part, using the Fund, as available and in accordance with subsection (j) of this section. There is an Electric Reliability Remediation Fund in the Commission. The purpose of the Fund is to provide resources to target remediation efforts to improve electric service quality and reliability for the worst performing electric distribution lines in the State. The Commission shall administer the Fund. The Fund is a special, nonlapsing fund that is not subject to reversion under § 7–302 of the State Finance and Procurement Article. The State Treasurer shall hold the Fund separately, and the Comptroller shall account for the Fund. The Fund consists of: revenue distributed to the Fund under § 13–201(e)(2) of this article for a violation of this section; money appropriated in the State budget to the Fund; and any other money from any other source accepted for the benefit of the Fund. The Fund may be used only for eligible reliability measures. The civil penalties collected from an electric company: may be used only for eligible reliability measures and projects in the service territory of that electric company; but may not replace or substitute for money already budgeted for or spent on any project, including an otherwise eligible reliability measure, that the electric company is required to implement under this section or any other law. The State Treasurer shall invest the money of the Fund in the same manner as other State money may be invested. Any investment earnings of the Fund shall be credited to the General Fund of the State.

In this section, “special medical needs facility” includes: an assisted living facility as defined in § 19–1801 of the Health – General Article; a congregate housing services program under Title 10, Subtitle 2 of the Human Services Article; a hospice facility as defined in § 19–901 of the Health – General Article; a hospital as defined in § 19–301 of the Health – General Article or a similar institution; a nursing home as defined in § 19–1401 of the Health – General Article; or any other type of facility that the Commission designates in regulation as a special medical needs facility. The purpose of this section is to: further the service quality and reliability goals under § 7–213 of this subtitle as they relate to special medical needs facilities; and encourage the reliable delivery of service to special medical needs facilities. The Secretary of Health shall: on or before January 1 of each year, establish and provide a list of special medical needs facilities, including the licensed capacity of each facility, to each electric company for its service territory; post the list required under item (1) of this subsection on the website of the Maryland Department of Health; and establish a procedure to allow a special medical needs facility to remove its information from the list established under item (1) of this subsection. On or before April 1 of each year, an electric company shall submit to the Commission as part of the electric company’s annual performance report under § 7–213(g) of this subtitle: a list of special medical needs facilities that are served by protective devices that activated five or more times during the reporting period, resulting in a power outage; a list of special medical needs facilities that experienced a service interruption that: exceeded 4 consecutive hours during the reporting period; and was reported to or was otherwise known to the electric company; a list of special medical needs facilities that are served by the 3% of feeders assigned to an electric company’s service territory in the State that are identified by the electric company as having the poorest reliability during the reporting period; and a description of the electric company’s performance in assessing and acting to remediate, and future plans and proposals to improve, the reliability of feeders and protective devices identified under this subsection. This section does not prohibit the Commission from taking the corrective action authorized in § 7–213(f)(2) of this subtitle against an electric company that fails to meet any or all of the applicable standards.

In this section the following words have the meanings indicated. “Contact voltage” means a voltage condition that may result in an object or surface being inadvertently energized. “Contact voltage risk zone” or “CVRZ” means the portions of each electric company’s service territory that: are served by 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 electric company’s voltage survey plan. “Electric distribution plant” means all electric company plant used to distribute electricity to its customers. “Electric distribution plant” includes covers and protective structures. “Electric distribution plant” does not include customer meters and meter enclosures. “Voltage survey plan” means a plan, submitted by an electric company and approved by the Commission, that governs the electric company’s contact voltage detection and testing equipment and voltage detection and testing procedures to be used when conducting contact voltage surveys. On or before September 1, 2012, each electric company shall file with the Commission for 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, a voltage survey plan. Within 30 days after the Commission approves a CVRZ within an electric company’s service territory, the electric company shall file its voltage survey plan for Commission approval. On Commission approval of its voltage survey plan, each electric company shall conduct: an initial contact voltage survey of each CVRZ within 1 year after the Commission approves an electric company’s voltage survey plan; and subsequent surveys of each CVRZ as set forth in its voltage survey plan. Each electric company shall conduct an initial and each subsequent contact voltage survey within each CVRZ of all objects and surfaces that are: publicly accessible; capable of conducting electricity; and electric distribution plant; streetlights owned or maintained by the electric company; streetlights and traffic signals owned by a municipal corporation or other unit of government, with the consent of the appropriate authority; and public parks and playgrounds, with the consent of the appropriate authority. For areas in each electric company’s service territory not located in a CVRZ, except for wooden poles, the electric company shall conduct a contact voltage survey on all publicly accessible electric distribution plant and publicly accessible streetlights that the electric company owns or maintains that are capable of conducting electricity: within 3 years after the initial approval of the voltage survey plan; and subsequently as set forth in its voltage survey plan. An electric company shall test each streetlight for contact voltage after dark or when the light is illuminated. At least 60 days before implementing a material change to a voltage survey plan, an electric company shall file an amended voltage survey plan for Commission approval. The Commission may modify the frequency or scope of any contact voltage survey requirement on a showing of good cause. Each electric company shall include in its voltage survey plan all equipment used for detecting contact voltage. The type of each equipment must be certified by an independent test laboratory as being able to reliably detect voltages of 6 to 600 volts. Each electric company shall include the certification when filing the voltage survey plan. 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. Until a potential contact voltage condition can be confirmed under paragraph (1) of this subsection, each electric company shall make an area safe after detecting a potential contact voltage condition during its contact voltage survey. If an electric company detects a contact voltage measurement under paragraph (1) of this subsection that is at least 1 volt of alternating current, the electric company shall: perform a contact voltage survey on all objects and surfaces that are capable of conducting electricity and are publicly accessible within at least 30 feet of the location of the measured contact voltage; when electric distribution plant or a street light that the electric company owns or maintains 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, unless extraordinary circumstances exist and the area continues to be made safe through a temporary measure to mitigate the contact voltage; when property that is not owned by the electric company is indicating contact voltage, immediately use best efforts to: make the area safe; and notify the customer or responsible person associated with the premises or 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 mitigate the contact voltage. On or before April 1 of each year, each electric company shall file a 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 an individual or an animal. The Commission shall approve the form of the report. The Commission may impose a civil penalty under this division for a violation of this subsection. The Commission may, in its discretion, through order or regulation: waive or modify any provision of this section; or impose additional requirements as circumstances require.

This section applies to a solar electric generating facility located in the State that: has the capacity to produce more than 2 megawatts of electricity; and is designed to produce electricity for sale on the wholesale market. Not later than 30 days after selling or otherwise transferring ownership of a solar electric generating facility the owner of the facility shall provide notice of the sale or transfer to: the county in which the facility is located; and the Commission. The notice under this section shall include the name, address, phone number, and e–mail address of the new owner.

In this section the following words have the meanings indicated. “Energy storage device” means a resource capable of absorbing electrical energy, storing it for a period of time, and delivering the energy for use at a later time as needed, regardless of where the resource is located on the electric system. “Energy storage device” includes all types of electric storage technologies, regardless of their size, storage medium, or operational purpose, including: thermal storage; electrochemical storage; thermo–mechanical storage; and hydrogen–based storage. “Investor–owned electric company” means an electric company that is not a municipal electric utility or an electric cooperative. The Commission shall establish an Energy Storage Pilot Program. The cumulative size of the pilot projects under the program shall be between 5 and 10 megawatts, with a minimum of 15 megawatt–hours. The Commission shall require each investor–owned electric company to solicit offers to develop energy storage projects for each of the following commercial and regulatory models: a “utility–only” model under which the electric company would own the project, control the project for grid reliability, and operate the project in wholesale markets or other applications when not providing grid services; a “utility and third–party” model under which the electric company would own the project and control the project for grid reliability, and a third party would operate the project in wholesale markets or other applications when the project is not providing grid services; a “third–party ownership” model under which the electric company would: contract with a project owned by a third party for grid reliability; and allow the third party to operate the project in wholesale markets or other applications when the project is not providing grid services; and a “virtual power plant” model under which: the electric company would aggregate or use a third–party aggregator to receive grid services from distributed energy storage projects owned by customers or a third party; and the projects would be used by the customers or third party for other applications when the projects are not providing grid services. Each investor–owned electric company shall submit applications for Commission approval to deploy energy storage projects from at least two of the models described under subsection (c) of this section, one of which must be from a model described in subsection (c)(3) or (4) of this section. A proposed project must be able to meet reasonably the program’s timelines and data collection requirements. An investor–owned electric company shall give priority to projects that directly defer or replace an existing or anticipated distribution need. An investor–owned electric company may propose a project that does not directly defer or replace an existing or anticipated distribution need if the project includes grid benefits, ratepayer benefits, or otherwise helps meet the State’s policy goals. An investor–owned electric company shall describe in the company’s application whether a project demonstrates an opportunity to reduce system costs. An application under subsection (d) of this section shall include information concerning: best estimates of costs and savings for the project, including: estimated permitting and interconnection costs; an approximation of the potential benefits, including cost savings; an estimate of funds expected to be received from wholesale market transactions; an estimate of the value of any distribution investment deferral or replacement due to the project, such as the present value of the costs avoided by installing the storage system; estimates of other societal benefits achieved by the project, such as incremental reliability and resiliency, greenhouse gas emission reductions, and learning benefits; and the estimated impact of each project on the investor–owned electric company’s rates for each class of customer; project location; project size in watts and duration in watt–hours; primary and secondary applications; the business model selected for the project under subsection (c) of this section; the project developer or engineering, procurement, and construction firm selected for the project; the type of energy storage technology; the process the investor–owned electric company used to solicit offers for the project, including feedback on models not selected and an explanation for why the chosen model was selected; and any other information required by the Commission. For purposes of the pilot program only, the Commission may determine how to address cost recovery for the models described under subsection (c)(3) and (4) of this section. For purposes of the pilot program only, the Commission may, on a project–by–project basis, allow: an investor–owned electric company to own or operate an energy storage device; an energy storage device owned or operated by an investor–owned electric company to participate in all available PJM wholesale revenue markets in order to realize benefits for investor–owned electric company customers; full and timely cost recovery by the investor–owned electric company, at the rate of return authorized by the Commission in the most recent base rate proceeding for the investor–owned electric company, taking into account any use of an asset that may not be included in base rates; an investor–owned electric company to coordinate the use of an energy storage device; an investor–owned electric company to use fully until the end of the device’s useful life, an energy storage device owned or operated by the investor–owned electric company; and an investor–owned electric company to offer rebates or other incentives for energy storage devices behind or in front of the meter that can be configured to provide temporary backup power to a customer. The pilot program shall begin on or before June 1, 2019. On or before April 15, 2020, each investor–owned electric company shall solicit proposals and apply for Commission approval for the first energy storage project required under subsection (d)(1) of this section. On or before September 15, 2020, each investor–owned electric company shall solicit proposals and apply for Commission approval for the second energy storage project required under subsection (d)(1) of this section. On or before April 15, 2021: the Commission shall determine which projects to approve; and each investor–owned electric company shall negotiate contracts to implement projects. The Commission shall solicit comments from the Maryland Energy Administration, the Office of People’s Counsel, and other stakeholders and hold a hearing on each application submitted under subsection (d) of this section. The Commission shall approve, approve with modifications, or reject an application submitted under subsection (d) of this section after: receiving comments from the Maryland Energy Administration, the Office of People’s Counsel, and other stakeholders and holding a hearing; considering the projected costs and benefits of the projects proposed for inclusion in the pilot program; and determining whether the project is in the public and ratepayer interest. If the Commission rejects an application, within 3 months after receiving notice of the rejection of an application, the investor–owned electric company shall submit an amended application for Commission approval. The Commission shall approve, approve with modifications, or reject an amended application within 3 months after receipt of the amended application. Except as provided in subparagraph (ii) of this paragraph, on or before February 28, 2022, all approved projects shall become operational. The Commission may, for good cause shown, grant an extension from the deadline established in subparagraph (i) of this paragraph for unanticipated project development delays. The Commission may establish additional interim deadlines. On or before July 1 of 2023, 2024, and 2025, an investor–owned electric company shall submit to the Commission, the Maryland Energy Administration, and the Office of People’s Counsel information or data concerning: estimated project costs; final project costs; the number of days necessary to achieve project interconnection; the total cost of project interconnection; the number of days necessary to achieve project permitting; the total cost of project permitting; the contractual or committed commercial operation date; the actual commercial operation date; the name and address of the project developer; the location and address of the project; the size of the energy storage project in watts; the duration of the energy storage project in watt–hours; the type of energy storage technology; the identities of any project owners or lessors; any project financing methods; the identity of any entity that provides financing for the project; the length of any project contract; any inverters used for the project, including the type and manufacturer; any manufacturer warranty, including its duration; any developer warranty, including its duration; any technology with which the project is paired; how meters and inverters associated with the project are configured; any system integrator associated with the project; project safety, including battery type and chemistry; any energy management system associated with the project; any energy storage power conversion system associated with the project; the business model selected for the project under subsection (c) of this section; the cost recovery mechanism for the project; the rate of return applied to the project; for a virtual power plant project under subsection (c)(4) of this section, the number and type of customers participating; for a virtual power plant project under subsection (c)(4) of this section, the identity of the aggregator; operational challenges related to multiple stakeholder or third–party use of the storage asset; the types of revenue expected from the project, including any wholesale market revenues; the types of revenue provided by the project, including any wholesale market revenues; the distribution need the project addressed; the amount of time the project is expected to defer the need for an alternative investment; any value of optionality associated with the amount of time the project is expected to defer the need for an alternative investment; the expected load projection before the project was installed; enhanced grid reliability as a result of the project; for a utility and third–party project under subsection (c)(2) of this section, the dollar value of the lease payments from the third party to the utility; for a utility and third–party project under subsection (c)(2) of this section, the duration of the lease agreement between the third party and the utility; any other identified benefits, including resiliency and social benefits; expected and actual storage system cycling; the project’s success in switching between applications without challenges or problems; occasions when the project was unable to serve an application; any project delays and the causes for the delays; any emissions reductions expected as a result of the project; and any other information required by the Commission. Subject to subparagraph (iv) of this paragraph, an investor–owned electric company shall make all data provided under subparagraph (i) of this paragraph that is not proprietary or confidential available to the public. To the extent possible, any annualized data provided under subparagraph (i) of this paragraph shall be seasonally adjusted. After receiving comments from all parties, the Commission shall determine: which data related to the projects shall be made available only to the technical staff of the Commission and the Office of People’s Counsel; and which data related to the projects shall be made available to the public. On or before April 1, 2026, if an investor–owned electric company determines that additional time to gather data would provide additional opportunities for learning and justify continuing the pilot program, the Commission may extend the pilot program and delay by a corresponding amount of time the evaluation and report required under subsection (k) of this section. On or before July 1, 2024, in accordance with § 2–1257 of the State Government Article, the Commission shall submit an interim report to the General Assembly that provides an initial evaluation of the projects approved under this section based on: project costs; value streams; any reduction in system costs; any issues encountered in the early implementation phase; and an analysis of any funds generated from the whole market. Except as provided in subsection (i) of this section, on or before July 1, 2026, in consultation with the Maryland Energy Administration and the Office of People’s Counsel, the Commission shall evaluate the projects approved under this section based on: the overall cost of the project; whether the project was optimized through multiple applications; whether the project managed to capture different value streams; whether the project reduced system costs; whether the project deferred or replaced entirely a traditional investment on the distribution system, and any value of such a deferral or replacement; an analysis of any funds generated from the wholesale market; other benefits provided as a result of the project; issues that the project encountered in implementation; and whether the project altered the quality or availability of electricity supply. On or before December 31, 2026, the Commission shall report, in accordance with § 2–1257 of the State Government Article, to the General Assembly on its findings under paragraph (1) of this subsection and its recommendations for the continued development of energy storage in the State. The pilot program may not preclude any other investment by a public service company in energy storage. Unless the Commission extends the pilot program in accordance with subsection (i) of this section, the pilot program shall terminate on December 31, 2026. The termination of the pilot program may not affect the cost recovery by an investor–owned electric company for the lifetime of an energy storage project.

In this section the following words have the meanings indicated. “Delivery year” has the meaning stated in the PJM Interconnection glossary. “Energy storage device” has the meaning stated in § 7–216 of this subtitle. “Investor–owned electric company” has the meaning stated in § 7–216 of this subtitle. “Program” means the Maryland Energy Storage Program. The Commission shall establish targets for the cost–effective deployment of new energy storage devices in the State with a goal of achieving: 750 megawatts of cumulative energy storage capacity by the end of delivery year 2027; 1,500 megawatts of cumulative energy storage capacity by the end of delivery year 2030; and 3,000 megawatts of cumulative energy storage capacity by the end of delivery year 2033. If a target specified in paragraph (1) of this subsection cannot be met cost effectively, the target shall be reduced to the maximum cost–effective amount of energy storage, measured in megawatts, that can be deployed by the end of the delivery year for the target. The Commission shall establish the Maryland Energy Storage Program. The Program shall be implemented no later than July 1, 2025. The Program shall include competitive procurement mechanisms to reach a minimum of 3,000 megawatts of energy storage, or the maximum cost–effective amount of energy storage that can be deployed, by the end of delivery year 2033. The Program may include: a system of energy storage credits and market–based incentives designed to: develop a robust energy storage market in the State; and deploy energy storage devices in a cost–effective manner; a requirement that investor–owned electric companies: install or contract for energy storage devices; or contract for credits from an energy storage project under § 7–216 of this subtitle; a requirement that Program participants 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; or any other mechanism or policy that the Commission determines is appropriate to achieve the goal of a robust, cost–effective energy storage system in the State. On or before November 1 each year, the Commission shall report to the General Assembly, in accordance with § 2–1257 of the State Government Article, on the status of the Program, including: the capacity of operational energy storage devices in the State that is being counted toward the capacity goal established under subsection (c)(3) of this section, disaggregated by: electric company service territory; energy storage device capacity; front–of–meter transmission–level storage; front–of–meter distribution–level storage; behind–the–meter storage; and any other relevant category, as determined by the Commission; whether the capacity goal established under subsection (c)(3) of this section should be altered; barriers to achieving the goals identified under this section; and any other information the Commission considers pertinent.

In this section, “energy storage device” has the meaning stated in § 7–216 of this subtitle. The General Assembly finds and declares that the State has a goal of reaching at least 150 megawatts of distribution–connected front–of–the–meter energy storage devices. On or before July 1, 2025, and on or before July 1, 2026, the Commission shall notify each investor–owned electric company of its proportion of the goal established under this subsection, based on: the electric company’s service load; or other criteria established by the Commission. On or before November 1, 2025, the Commission shall require each investor–owned electric company to submit a plan to achieve up to one–third of the proportion of distribution–connected front–of–the–meter energy storage devices necessary to reach the electric company’s apportionment of the goal stated in subsection (b) of this section. On or before November 1, 2026, the Commission shall require each investor–owned electric company to submit a plan for the balance of the proportion of distribution–connected front–of–the–meter energy storage devices necessary to reach the electric company’s apportionment of the goal stated in subsection (b) of this section. On or before May 1, 2026, for plans submitted in accordance with paragraph (1) of this subsection, and on or before May 1, 2027, for plans submitted in accordance with paragraph (2) of this subsection, the Commission shall: evaluate each plan; accept public comments on each plan; and issue an order for each plan that: approves the plan; approves the plan with modifications that the Commission considers necessary; or rejects the plan, with an explanation of the reasons for the rejection. The energy storage devices constructed or procured under each plan shall include a combination of devices owned by the investor–owned electric company and devices owned by a third party, with a goal of 30% of the devices being owned by a third party. The energy storage devices that are constructed or procured under a plan submitted by November 1, 2025, shall be operational by November 1, 2027. The energy storage devices that are constructed or procured under a plan submitted by November 1, 2026, shall be operational by November 1, 2028. The Commission may extend a deadline under this paragraph for good cause. The Commission shall require each plan to demonstrate that the construction or procurement of each energy storage device: is cost–effective in consideration of a cost–benefit analysis, including a demonstration of any: avoided or delayed transmission, distribution, and generation costs; and avoided emissions in the short term and projected emissions in the long term, measured using the social cost of carbon, as determined by the U.S. Environmental Protection Agency as of January 1, 2025; can be completed within 18 months after the plan is approved; and complies with any other factors determined by the Commission. A developer of a third–party–owned energy storage device constructed in accordance with this section shall ensure that workers are paid not less than the prevailing wage rate determined under Title 17, Subtitle 2 of the State Finance and Procurement Article. An energy storage device constructed and owned by an electric company shall be constructed by: employees of the electric company; or contractors that shall ensure that workers constructing the energy storage device are paid not less than the prevailing wage rate determined under Title 17, Subtitle 2 of the State Finance and Procurement Article. An investor–owned electric company shall operate and maintain energy storage devices installed by the electric company in accordance with this section. In performing the maintenance and operations required under subparagraph (i) of this paragraph, an investor–owned electric company shall meet with the employee bargaining unit’s labor representative and confer in good faith regarding the viability of: allocating maintenance and operations work to current bargaining unit employees; training current bargaining unit employees to perform maintenance and operations work; hiring qualified individuals to perform maintenance and operations work; training newly hired individuals to perform maintenance and operations work; and maintaining and operating storage devices in accordance with paragraph (4) of this subsection. Subject to subparagraph (ii) of this paragraph, an investor–owned electric company may contract any work under this section not conducted by the company’s employee bargaining unit to a qualified contractor. An investor–owned electric company shall require a contractor or subcontractor on a project under this section to: pay the area prevailing wage rate determined by the Commissioner of Labor and Industry, including wages and fringe benefits; and offer health care and retirement benefits to the employees working on the project. Each energy storage project constructed in accordance with this section shall include a proposed decommissioning plan. The proposed decommissioning plan shall include a plan to maximize the recycling or reuse of all qualifying components of each energy storage device. The owner or operator of an energy storage device may submit a revised recycling and reuse plan that incorporates emerging recycling and reuse opportunities up to 1 year before executing the decommissioning plan.

In this section the following words have the meanings indicated. “Electric school bus” means a school bus that is powered exclusively by an electric motor that draws its current from rechargeable storage batteries that are recharged with electricity from an electric vehicle charging station. “Electric school bus pilot program” means a pilot program conducted by an investor–owned electric company under this section. “Incremental administrative and operating costs” means the amount by which the cost of administering and operating an electric school bus program exceeds the cost of administering and operating a diesel school bus program. “Incremental costs of purchasing and deploying electric school buses” means the amount by which the costs of purchasing and deploying electric school buses exceed the costs of purchasing and deploying diesel school buses. “Interconnection equipment” means a group of components or an integrated system that connects an electric vehicle charging station with the distribution system of an investor–owned electric company. “Interconnection facilities” means facilities required by an investor–owned electric company to accommodate the interconnection of an electric vehicle charging station. “Participating school system” means a school system located within an investor–owned electric company’s service territory that: participates in an electric school bus pilot program under an agreement between its school board and an investor–owned electric company; and owns its school buses or contracts with another entity for school bus services. “Program costs” means: any costs to deploy appropriate electric school bus charging infrastructure that are incurred by an investor–owned electric company in implementing an electric school bus pilot program; and rebates paid to a participating school system. “Rebate” means an incentive provided by an investor–owned electric company to a participating school system that is equal to: the demonstrable incremental costs of purchasing and deploying electric school buses to participating school systems; and the incremental administrative and operating costs incurred by a participating school system in implementing its electric school bus pilot program. There is an electric school bus pilot program. The electric school bus pilot program shall be implemented and administered by the Commission and shall operate as provided in this section. An investor–owned electric company may apply to the Commission to implement an electric school bus pilot program if the pilot program is structured to: commence on or before October 1, 2024; provide for the deployment of not fewer than 25 electric school buses; provide for electric school bus rebates to participating school systems; limit total rebates to $50,000,000; allow the investor–owned electric company to use the storage batteries of the electric school buses to access the stored electricity through vehicle–to–grid technology: except as provided in item (6) of this subsection, without additional compensation to the school system for the electricity; and at times when the participating school system determines that the school buses are not needed to transport students; ensure that if the investor–owned utility uses electricity that a participating school system provides to charge an electric school bus battery, the investor–owned utility replaces that electricity at no cost to the participating school system; provide for the selection of school systems that apply to participate in the pilot program on the basis of appropriate factors determined by the investor–owned electric company with the approval of the Commission, including the locational benefits that the storage batteries of school buses may bring to the investor–owned electric company; consider, in determining the appropriate factors under item (7) of this subsection, the health and economic effects on low–income and minority communities; provide and install the interconnection equipment and interconnection facilities for electric vehicle charging stations; ensure each electric school bus is equipped with lap and shoulder belts in accordance with recommendations from the National Transportation Safety Board; and ensure the school board is provided with adequate training and expertise to operate ably electric school buses, electric vehicle charging stations, and associated infrastructure. A participating school system shall: when deploying electric school buses, consider criteria that benefit students who are eligible for free and reduced price meals; and before the delivery of electric school buses, develop a plan for training and retaining any school system employee affected by the electric school bus pilot program. Subject to the Commission’s approval, an investor–owned electric company may recover all reasonable and prudent program costs incurred under an electric school bus pilot program through a mechanism that is reviewed and approved by the Commission. Subject to the Commission’s approval, an investor–owned electric company may establish a pilot tariff or rate to provide service to an electric school bus. An investor–owned electric company that applies to implement an electric school bus pilot program shall provide to the Commission any information, data, and analysis that the Commission requires. The Commission shall approve, deny, or approve with modifications an investor–owned electric company’s application to implement an electric school bus pilot program. An investor–owned electric company that establishes an electric school bus pilot program authorized by this section shall, in consultation with each participating school system, by February 1, 2025, and each year thereafter for the duration of the pilot program, report on the status of the pilot program to the Governor, the Commission, and, in accordance with § 2–1257 of the State Government Article, the House Economic Matters Committee and the Senate Finance Committee. The report required under paragraph (1) of this subsection shall include: an evaluation of the environmental and health benefits of the pilot program; and the financial costs and benefits of implementing the pilot program to the participating school system and the investor–owned utility, including: the deployment, operation, and maintenance of the electric school buses; and the use of vehicle–to–grid technology. The initial duration of an electric school bus pilot program shall be at least 3 years and may not exceed 5 years. On the request of an investor–owned electric company, the Commission may authorize an expansion of the scope, deployment, program costs, and duration of the electric school bus pilot program.

In this section the following words have the meanings indicated. “Agrivoltaics” has the meaning stated in § 7–306.2 of this title. “Brownfields site” has the meaning stated in § 7–207 of this subtitle. “Local jurisdiction” includes counties, municipal corporations, and other forms of local government. “Priority preservation area” means an area certified as a priority preservation area under § 2–518 of the Agriculture Article. “Project area” means an area within which construction, materials and equipment storage, grading, landscaping, and related activities for a project may occur. “Project area” includes one or more contiguous parcels or properties under the same ownership or lease agreement. This section applies only to a solar energy generating station that: has the capacity to produce more than 1 megawatt of electricity as measured by the alternating current rating of the station’s inverter; is designed to produce electricity for sale on the wholesale market; is a community solar energy generating system under § 7–306.2 of this title; or is part of aggregate net metering under § 7–306.3 of this title; and is not located on a rooftop, carport, or brownfields site or behind the meter of a retail electric customer. A person may not begin construction of a solar energy generating station unless: the Commission or, for a solar energy generating station that has the capacity to produce not more than 2 megawatts of electricity as measured by the alternating current rating of the station’s inverter, the local jurisdiction verifies that the proposed construction meets all of the site requirements under subsection (f) of this section; for a solar energy generating station that has the capacity to produce more than 2 megawatts of electricity as measured by the alternating current rating of the station’s inverter: a certificate of public convenience and necessity has been issued in accordance with § 7–207 of this subtitle; a distributed generation certificate of public convenience and necessity has been issued in accordance with § 7–207.4 of this subtitle; or the construction has been approved by the Commission in accordance with § 7–207.1 of this subtitle; and the construction has received approval for all local permits required under § 7–207(h) of this subtitle. A person that submits an application for approval of the construction of a solar energy generating station in accordance with § 7–207, § 7–207.1, or § 7–207.4 of this subtitle shall include with the application written documentation or other evidence showing that the proposed construction meets the requirements under subsections (f) and (g) of this section. For a solar energy generating station that has the capacity to produce not more than 2 megawatts of electricity as measured by the alternating current rating of the station’s inverter, a person that submits a site development plan to a local jurisdiction shall include with the plan written documentation or other evidence showing that the proposed construction meets the requirements under subsections (f) and (g) of this section. When verifying whether the documentation provided under subsection (d) of this section meets the requirements under subsections (f) and (g) of this section, the Commission or local jurisdiction shall, if the proposed location of the solar energy generating station is in an area considered to be overburdened and underserved, as defined in § 1–701 of the Environment Article, require the person constructing the solar energy generating station to hold at least two public meetings in the community where the solar energy generating station is to be located to collect community feedback and provide opportunities to address community feedback. Subject to subparagraph (ii) of this paragraph, the meetings required under paragraph (1) of this subsection shall be held: in the county in which the proposed solar energy generating station is to be located; and within 10 miles of the proposed location of the solar energy generating station. If the owner of a proposed solar energy generating station cannot find a meeting location that meets the requirements of subparagraph (i) of this paragraph, the owner may select an alternative location that is as close as practicable to the location of the proposed solar energy generating station. This subsection does not apply to agrivoltaics. Except as provided in paragraph (10) of this subsection, an owner of a proposed solar energy generating station: shall provide a boundary of 150 feet between the solar energy generating station and the nearest wall of a residential dwelling; shall provide a boundary of 100 feet between the solar energy generating station and all property lines, not including property lines that bisect the interior of a project area; shall provide nonbarbed wire fencing: only on the interior of a landscape buffer or immediately adjacent to a solar energy generating station; that is not more than 20 feet in height; that is only black or green vinyl wire mesh if the owner proposes to use chain link fencing; and that is not less than 50 feet away from the edge of any public road right–of–way; and may use barbed wire fencing around the substations or other critical infrastructure for protection of that infrastructure; shall provide for a landscaping buffer or vegetative screening in accordance with paragraph (4) of this subsection; except for equipment required for interconnection with electric system infrastructure, may not locate any solar array, ancillary equipment, or accessory buildings or facilities within a public road right–of–way; shall mitigate the visual impact of the solar energy generating station on a preservation area, rural legacy area, priority preservation area, public park, scenic river or byway, designated heritage area, or historic structure or site listed on or eligible for the National Register of Historic Places or relevant county register of historic places; and for a solar energy generating station that has the capacity to produce more than 2 megawatts of electricity as measured by the alternating current of the station’s inverter, shall include in the application submitted under subsection (c)(2) of this section a viewshed analysis for any area, structure, or site specified in item 1 of this item; and for a solar energy generating station that has the capacity to produce not more than 2 megawatts of electricity as measured by the alternating current of the station’s inverter, shall include in an application for a site development plan a viewshed analysis for any area, structure, or site specified in item 1 of this item; and shall provide notice of each proposed solar energy generating station to the emergency response services of each county in which any portion of the generating station is to be constructed, including a map of the proposed generating station and the proposed location of any solar collector or isolator switch. A local jurisdiction may not require the use of a berm for a solar energy generating station approved under this section. The buffer or vegetative screening required in paragraph (2)(iv) of this subsection shall: be not more than 35 feet wide; be provided along: all property lines; locations of the exterior boundary for the solar energy generating station where existing wooded vegetation of 50 feet or more in width does not exist; or an alternative location within the boundary for the solar energy generating station if the owner demonstrates that the alternative location would maximize the visual screening; provide for four–season visual screening of the solar energy generating station; be placed between any fencing and the public view; include multilayered, staggered rows of overstory and understory trees and shrubs that: are a mixture of evergreen and deciduous vegetation; are predominantly native to the region; are more than 4 feet in height at planting; are designed to provide screening or buffering within 5 years of planting; may not be trimmed to stunt upward or outward growth or to otherwise limit the effectiveness of the visual screen; conform to the plant size specifications established by the American Standard for Nursery Stock (ANSI Z60.1); and are specified in a landscaping plan prepared by a qualified professional landscape architect; be installed as early in the construction process as practicable and before the activation of the proposed solar energy generating station; preserve to the maximum extent practicable and supplemented with new plantings where necessary, any forest or hedgerow that exists at a location where visual screening or landscape buffering is required; and shall be maintained with a 90% survival threshold for the life of the solar energy generating station through a maintenance agreement that includes a watering plan. With respect to the site on which a solar energy generating station is proposed for construction, the owner of the solar energy generating station: shall minimize grading to the maximum extent possible; may not remove topsoil from the parcel, but may move or temporarily stockpile topsoil for grading; to maintain soil integrity, shall plant native or noninvasive naturalized vegetation and other appropriate vegetative protections that have a 90% survival threshold for the life of the solar energy generating station; shall limit mowing and other unnecessary landscaping; may not use herbicides except to control invasive species in compliance with the Department of Agriculture’s weed control program; and shall post for the first 5 years of the life of the solar energy generating station a landscaping bond equal to 100% of the total landscaping cost with the county in which the solar energy generating station is located. Subject to subparagraphs (ii) and (iii) of this paragraph, a local jurisdiction shall hold any landscaping bond required under paragraph (5)(vi) of this subsection for 5 years. A local jurisdiction shall release 50% of the landscaping bond if, on inspection, the vegetative protections meet a 90% survival threshold. Following the release of a landscaping bond under subparagraph (ii) of this paragraph, the remaining landscaping bond shall be held for an additional 2 years and, on further inspection and confirmation that the vegetative protections continue to meet a 90% survival threshold, shall be released. Except as required by law, or for safety or emergency, the solar energy generating station may not emit visible light during dusk to dawn operations. This paragraph does not apply to: equipment necessary for interconnection with the electric system; or solar energy generating stations located on land that is also used for agricultural purposes. A proposed solar energy generating station and any accessory structures associated with the station must have an average height of not more than 15 feet. Setbacks for solar energy generating stations: shall be measured from the property boundary to the nearest solar array or accessory equipment, buildings, or facilities that generate, maintain, operate, manage, distribute, and transmit electricity; and may not apply to any interconnection tie line or facility that connects a solar energy generating station to the electric system. The owner of a proposed solar energy generating station may provide to the Commission or local jurisdiction written documentation of a siting agreement: entered into with the county in which the proposed solar energy generating station is to be located; and that provides less stringent restrictions than those specified under this subsection. If a proposed solar energy generating station provides to the Commission or local jurisdiction written documentation in accordance with subparagraph (i) of this paragraph, the proposed solar energy generating station shall be considered as meeting the requirements of this subsection. An owner of a solar energy generating station: shall enter into a decommissioning agreement with the Commission on a form that the Commission provides; shall post a surety bond with the Commission for not more than 125% of the estimated future cost of decommissioning the solar energy generating station and its related infrastructure, less any salvage value; and shall execute a securitization bond true–up every 5 years. Except as provided in paragraphs (3) and (4) of this subsection, a local jurisdiction may not: adopt zoning laws or other laws or regulations that prohibit the construction or operation of solar energy generating stations; or deny site development plans for solar energy generating stations that meet the requirements of subsection (f) of this section. A local jurisdiction shall: expedite the review and approval of site development plans for solar energy generating stations if those plans meet the requirements of this section; and for solar energy generating stations with a generating capacity of not more than 5 megawatts, as measured by the alternating current rating of the solar energy generating station’s inverter, process the site development plan application as a permitted use subject to the review standards in § 4–205 of the Land Use Article. A ground mounted solar energy generating station with a generating capacity of more than 5 megawatts, as measured by the alternating current rating of the solar energy generating station’s inverter, may not be located on any lot, parcel, or tract of land that, as of January 1, 2025, is located within: a Tier 1 or Tier 2 mapped locally designated growth area adopted under § 1–506 of the Land Use Article; a medium density residential area or high density residential area, as defined in § 5–1601 of the Natural Resources Article; or a mixed–use area with a residential component. The total combined number of solar energy generating stations that may be approved for construction in a priority preservation area that was established before January 1, 2025, shall: be limited in area to 5% of the total acreage of the priority preservation area; be located in the project area within the priority preservation area; and meet all requirements under this section. The prohibitions in paragraph (1) of this subsection do not apply to the remaining 95% of a priority preservation area once the 5% limitation under subparagraph (i) of this paragraph has been achieved for the priority preservation area. A county shall report to the Commission when the 5% limitation under subparagraph (i) of this paragraph has been achieved for a priority preservation area. Nothing in this section may be construed to add any additional limitations to the authority of the Commission in the approval process for an application for a certificate of public convenience and necessity.

In this section the following words have the meanings indicated. “Energy storage device” has the meaning stated in § 7–216 of this subtitle. “Local jurisdiction” includes counties, municipal corporations, and other forms of local government. A person may not begin construction of a front–of–the–meter energy storage device unless the construction has been approved by the Commission in accordance with regulations adopted under this section. On receipt of an application for approval of the construction of a front–of–the–meter energy storage device under this section, the Commission shall provide immediate notice or require the applicant to provide immediate notice of the application to: the governing body of each county or municipal corporation in which any portion of the energy storage device is proposed 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. When reviewing an application for approval under this section, the Commission shall: if the proposed location of the front–of–the–meter energy storage device is in an area considered to be overburdened and underserved, as defined in § 1–701 of the Environment Article, require the applicant to hold at least two public meetings in the community where the energy storage device is to be located; and exempt a front–of–the–meter energy storage device that is located within the boundaries of an existing electricity generating station from the meeting requirements of this subsection. An owner of a proposed front–of–the–meter energy storage device that will not be constructed at a commercial or industrial location: shall provide nonbarbed wire fencing: around the energy storage device; and that is not more than 20 feet in height; and may use barbed wire fencing around the substations or other critical infrastructure for protection of that infrastructure; and shall provide for a landscaping buffer or vegetative screening if required by the local jurisdiction. A local jurisdiction may not require the use of a berm for a front–of–the–meter energy storage device approved under this section. The buffer required in paragraph (1)(ii) of this subsection shall: be not more than 25 feet in depth; and provide for four–season visual screening of the front–of–the–meter energy storage device. With respect to the site on which a front–of–the–meter energy storage device is proposed for construction, the owner of the energy storage device: shall minimize grading to the maximum extent possible; may not remove topsoil from the parcel, but may move or temporarily stockpile topsoil for grading; and may not use herbicides except to control invasive species in compliance with the Department of Agriculture’s weed control program. A local jurisdiction may not: adopt zoning laws or other laws or regulations that prohibit the construction or operation of front–of–the–meter energy storage devices; or deny site development plans for front–of–the–meter energy storage devices that meet the requirements of subsection (e) of this section. A local jurisdiction shall: expedite the review and approval of site development plans for front–of–the–meter energy storage devices if those plans meet the requirements of this section; and adopt standard processes for the review and approval of site development plans for the construction of front–of–the–meter energy storage devices. The Commission may waive or modify the requirements under subsections (c), (d), and (e) of this section for good cause. The Commission shall adopt regulations to carry out this section.

In this part the following words have the meanings indicated. “Behind–the–meter program” means a program that impacts the customer side of the utility meter. “Beneficial electrification” means the replacement of the direct use of fossil fuels in buildings with the use of electricity in a manner that: reduces overall lifetime greenhouse gas emissions; reduces customers’ energy costs; or enables better management of the electric distribution system. “Carbon dioxide equivalent” means the measurement of a given weight of a greenhouse gas that has the same global warming potential, measured over a specific period of time, as 1 metric ton of carbon dioxide. “Demand response program” means a program established by an electric company, an electricity supplier, or a third party that promotes changes in electric usage by customers from their normal consumption patterns in response to: changes in the price of electricity over time; or incentives designed to: induce lower electricity use at times of high wholesale market prices; or ensure system reliability. “Department” means the Department of Housing and Community Development. “Energy efficiency” means the use of less energy to perform the same task or produce the same result. “Front–of–meter community program” means a program that: is separate from front–of–meter utility programs; impacts the utility side of the meter; and directly benefits a set of customers. “Front–of–meter utility program” means a program that impacts the utility side of a meter and benefits all utility customers. “Greenhouse gas” includes: carbon dioxide; methane; nitrous oxide; hydrofluorocarbons; perfluorocarbons; and sulfur hexafluoride. “Greenhouse gas emissions reduction” means a reduction in greenhouse gas emissions, measured in metric tons of carbon dioxide equivalents, including: greenhouse gas emissions from the generation of electricity delivered to and consumed in the State; and line losses from the transmission and distribution of electricity, regardless of whether the electricity is generated in the State or imported. “Low–income program” means a program that delivers energy efficiency, conservation, and greenhouse gas emissions reduction measures to reduce utility expenses for building owners, managers, and tenants of housing with residents who qualify for the Department’s low–income assistance programs, including: the EmPOWER Maryland Limited Income Energy Efficiency Program; the Multifamily Energy Efficiency and Housing Affordability Program; and the Weatherization Assistance Program. “Low–income residential” means a community, building, or household with residents that: have incomes below 250% of the federal poverty level as determined by the federal census; or meet the eligibility criteria approved by the Commission for low–income programs. “Midsize electric cooperative” means an electric cooperative, including a member–regulated cooperative, that: serves fewer than 75,000 customers in its distribution territory; but is not a small rural electric cooperative. “Nonenergy program” means a program with greenhouse gas emissions reduction benefits that are primarily nonenergy–based. “Plan” means any combination of behind–the–meter programs, front–of–meter community programs, front–of–meter utility programs, or nonenergy programs that: achieve greenhouse gas emissions reductions through energy efficiency, conservation, demand response, and beneficial electrification; and include a cost recovery proposal. “Task Force” means the Green and Healthy Task Force established under § 7–319 of this title.

The General Assembly finds and declares that energy efficiency is: among the least expensive ways to meet the energy demands of the State; a means of affordable, reliable, and clean energy for consumers of Maryland; and one method to achieve Maryland’s climate commitments for reducing statewide greenhouse gas emissions, including those required under Title 2, Subtitle 12 of the Environment Article.

Subject to review and approval by the Commission, each electric company, the Department, and, if required in accordance with subsection (c) of this section, each midsize electric cooperative shall develop and implement programs and services in accordance with §§ 7–223, 7–224, and 7–225 of this subtitle to encourage and promote the efficient use and conservation of energy, demand response, and beneficial electrification by consumers, electric companies, and the Department in support of the greenhouse gas emissions reduction goals and targets required under Title 2, Subtitle 12 of the Environment Article. As directed by the Commission, each municipal electric utility, each small rural electric cooperative, and, if required in accordance with subsection (c) of this section, each midsize electric cooperative shall include energy efficiency and conservation, demand response, and beneficial electrification programs or services as part of their service to their customers. In accordance with this subsection, each midsize electric cooperative shall be subject to either subsection (a) or subsection (b) of this section. Each midsize electric cooperative shall offer programs and services to customers in accordance with: subsection (b) of this section through December 31, 2026; and on or after January 1, 2027, and as the Commission directs, either subsection (a) or subsection (b) of this section. Not later than October 1, 2025, the Commission shall determine if it is in the public interest for a midsize electric cooperative to offer programs and services to customers in accordance with subsection (a) or subsection (b) of this section starting January 1, 2027, and for all subsequent years. Each midsize electric cooperative shall provide the following information to the Commission to assist in making a determination under paragraph (3) of this subsection: anticipated costs and bill impacts; a description of the anticipated program offerings; the anticipated cost–effectiveness of the residential, commercial, and industrial sector subportfolios based on the cost–effectiveness tests in § 7–225(d)(3)(i) of this subtitle; the anticipated electricity savings and greenhouse gas emissions reductions; and any other information the Commission requires. The information provided to the Commission under paragraph (4) of this subsection shall be based on a plan to offer programs and services to customers that complies with the requirements of an electric company subject to subsection (a) of this section for the 3–year program cycle starting January 1, 2027. When making a public interest determination under paragraph (3) of this subsection the Commission, at a minimum, shall consider the requirements under § 7–225(d)(3) of this subtitle that are considered when approving a plan of an electric company that is subject to subsection (a) of this section. Starting October 1, 2025, if the Commission determines that it is in the public interest for a midsize electric cooperative to be subject to subsection (a) of this section, the midsize electric cooperative shall comply with all requirements of an electric company subject to subsection (a) of this section for program cycles starting on and after January 1, 2027. On or before March 1 each year, starting in 2026, each midsize electric cooperative directed by the Commission to include programs or services under subsection (b) of this section shall submit to the Commission a report quantifying the gains in energy efficiency and reductions in greenhouse gas emissions achieved during the previous year. The Commission shall encourage and promote the efficient use and conservation of energy in support of the greenhouse gas emissions reduction goals and targets required under Title 2, Subtitle 12 of the Environment Article, established by the Commission under § 7–223(b) of this subtitle, and specified in § 7–224(a)(2) of this subtitle by: requiring each electric company to establish any program or service that the Commission determines to be appropriate and cost–effective; adopting rate–making policies that provide, through a surcharge line item on customer bills: full cost recovery of reasonably incurred costs for programs and services established under item (1) of this subsection, including full recovery on a current basis on or before January 1, 2028; on or before December 31, 2032, the elimination of any unpaid costs and unamortized costs that: existed on December 31, 2024; or were incurred before January 1, 2028; and were accrued for the purpose of achieving statutory targets for annual incremental gross energy savings; compensation for any unpaid costs and unamortized costs under item (ii) of this item at not more than each electric company’s and each gas company’s average cost of outstanding debt; and reasonable financial performance incentives and penalties for investor–owned electric companies as appropriate; and ensuring that adoption of electric customer choice under Subtitle 5 of this title does not adversely impact these goals and targets. The Commission shall, by regulation or order, require each electric company that has submitted to the Commission, on or before July 1, 2024, a plan for achieving electricity savings and demand reduction targets to disclose the following information in a form and format readily understandable to the average customer: that the surcharge imposed in accordance with subsection (d) of this section includes the cost of paying down the unpaid costs and unamortized costs that were accrued over time by programs and services required by the Commission dating back to 2008; and the period of time that the surcharge will include excess charges to pay down the unpaid costs and unamortized costs. A gas company that provided a program or service under subsection (d)(1) of this section and recovered costs under subsection (d)(2) of this section on or before January 1, 2026, shall: terminate the program on or before December 31, 2026; and continue to recover any program and service costs reasonably incurred through December 31, 2026, including unpaid and unamortized costs under subsection (d)(2)(i) of this section, through the rate–making policies under subsection (d)(2) of this section until all reasonably incurred program and service costs have been recovered.

On or before January 1, 2025, and on or before January 1 every 3 years, starting in 2027, the Commission shall, by regulation or order, require each electric company subject to § 7–222(a) of this subtitle to develop and implement a plan that: covers appropriate ratepayer classes; starting in 2027, covers a 3–year program cycle; and achieves the greenhouse gas emissions reduction target established for the electric company under subsection (b) of this section through cost–effective energy efficiency and conservation programs and services, demand response programs and services, and beneficial electrification programs and services. For 2025 and 2026, and for each 3–year program cycle starting in 2027, the Commission shall establish a greenhouse gas emissions reduction target for each electric company subject to § 7–222(a) of this subtitle as provided in this subsection. When establishing greenhouse gas emissions reduction targets under this subsection, the Commission shall measure the greenhouse gas emissions from electricity and gas, and the intensities of those emissions, using current data and projections from the Department of the Environment. The greenhouse gas emissions reduction targets established under this subsection shall be measured: in metric tons; and relative to the greenhouse gas emissions associated with the electric company’s weather–normalized gross retail sales and losses in a baseline year, as determined by the Commission. By the dates specified in § 7–225(a) of this subtitle, the Commission shall establish greenhouse gas emissions reduction targets for each electric company plan that will achieve at least the greenhouse gas emissions reduction equivalent, measured on a lifecycle basis using the emission intensities under paragraph (2) of this subsection, of the following annual electricity savings percentages, calculated as a percentage of the electric company’s 2016 weather–normalized gross retail sales and electricity losses: 0% in 2024; 25% each year in 2025 and 2026; 75% each year in 2027 through 2029; 0% each year in 2030 through 2032; 25% each year in 2033 through 2035; and 5% each year in 2036 and after. The Commission shall take into consideration the most recent final plan adopted under § 2–1205 of the Environment Article when establishing the greenhouse gas emissions reduction targets under this subsection. For 2025 and 2026: the Commission shall, after making appropriate findings, determine whether existing electric company plans must be modified to comply with § 7–225(d) of this subtitle; and electric companies: shall provide information as required by the Commission to assist in making the determination under item (i) of this paragraph; and are only required to file new plans in accordance with this section if directed by the Commission. The Commission may give priority to long–lived greenhouse gas emissions reduction measures in the plans by establishing a minimum weighted average measure life for the plan of each electric company. Contributions to greenhouse gas emissions reduction goals and targets in a plan of an electric company: may, notwithstanding § 7–222(d)(2) of this subtitle, include recovery of the reasonable and prudent costs from programs that are not behind–the–meter programs in a base rate proceeding, subject to Commission approval; and may not include the increased adoption of electric vehicles. Subject to paragraph (2) of this subsection, beginning January 1, 2025: at least 80% of the greenhouse gas emissions reductions counted toward each electric company’s greenhouse gas emissions reduction targets established under this section shall come from behind–the–meter programs, which may include deployment of energy storage facilities; and subject to paragraph (3) of this subsection, for 2027 through 2029, not more than 20% of the greenhouse gas emissions reductions counted toward each electric company’s greenhouse gas emissions reduction targets established under this section shall include: community solar energy generating systems that are interconnected to the electric company’s distribution system; and solar energy generating facilities that are interconnected to the electric company’s distribution system. Paragraph (1) of this subsection may not be construed to authorize an electric company to build, own, or operate electric generating facilities or energy storage facilities to meet the requirements of this section. Greenhouse gas emissions reductions from sources specified under paragraph (1)(ii) of this subsection may not be used to meet the greenhouse gas emissions reduction targets under paragraph (1)(i) of this subsection.

Beginning January 1, 2025, and on or before January 1 every 3 years, starting in 2027, the Department shall procure or provide to low–income individuals energy efficiency and conservation programs and services, demand response programs and services, and beneficial electrification programs and services that achieve the greenhouse gas emissions reduction targets established for the Department under paragraph (2) of this subsection. For the period 2025–2033, the programs and services required under paragraph (1) of this subsection shall be on a trajectory to achieve greenhouse gas reductions after 2027 of at least 0.9% of the baseline determined under subsection (b) of this section. When establishing greenhouse gas emissions reduction targets under this subsection, the Commission shall measure the greenhouse gas emissions from electricity using current data and projections from the Department of the Environment. The greenhouse gas emissions reduction targets established under this subsection shall be measured in metric tons. The greenhouse gas reductions achieved to meet the targets established under paragraph (2) of this subsection shall count toward the achievement of the greenhouse gas reduction target established under § 7–223(b) of this subtitle. The target greenhouse gas savings shall be achieved based on the 3–year average of the Department’s plan submitted in accordance with subsection (d) of this section. For 2025 and 2026: the Commission shall, after making appropriate findings, determine whether the Department’s existing 2024–2026 plan must be modified to comply with: the targets established in this subsection; and § 7–225(d) of this subtitle; and the Department: shall provide information as required by the Commission to assist in making the determination in item (i) of this paragraph; and is only required to file new plans in accordance with subsection (d) of this section and § 7–225 of this subtitle if directed by the Commission. As a baseline for determining greenhouse gas emissions reduction targets under this section, the Commission shall use the greenhouse gas emissions resulting from the direct consumption of gas and electricity by low–income residential households in 2016, as determined by the Department of the Environment. When calculating the achievement of greenhouse gas emissions reduction targets under this section, the Department may procure or provide savings that are achieved through all funding sources, to the extent that the savings from those funding sources are achieved: in a manner consistent with requirements of the U.S. Department of Energy; or in a manner otherwise consistent with the energy savings requirements applicable to those funding sources. If directed by the Commission in 2024, and on or before September 1 every 3 years, starting in 2026, the Department shall submit its plans for any programs or services procured or provided under subsection (a) of this section to the Commission for review and approval under § 7–225 of this subtitle. For weatherization of leased or rented residences, the Department shall adopt regulations to ensure that: the benefits of weatherization assistance, including utility bill reduction and preservation of affordable housing stock, accrue primarily to low–income tenants occupying a leased or rented residence; and the rent on the residence is not increased and the tenant is not evicted as a result of weatherization provided under this section. The programs and services provided under subsection (a) of this section may not use thermal insulating materials for building elements, including walls, floors, ceilings, attics, and roof insulation, that contain formaldehyde if the formaldehyde: was intentionally added; or is present in the product at greater than 0.1% by weight. The Department’s approved contractors used for the programs under this section shall meet the following job requirements: pay at least 150% of the State minimum wage; provide career advancement training; afford employees the right to bargain collectively for wages and benefits; provide paid leave; be considered covered employment for purposes of unemployment insurance benefits in accordance with Title 8 of the Labor and Employment Article; entitle the employee to workers’ compensation benefits in accordance with Title 9 of the Labor and Employment Article; be compliant with federal and State wage and hour laws for the previous 3 years; offer employer–provided health insurance benefits with monthly premiums that do not exceed 8.5% of the employee’s net monthly earnings; and offer retirement benefits. The Department shall develop a plan to coordinate funding sources and leverage the greatest funding possible to support a whole home approach by addressing: health and safety upgrades; weatherization; energy efficiency; and other general maintenance for low–income housing. The plan shall coordinate funding among: the Strategic Energy Investment Fund; federal weatherization assistance programs; ratepayer contributions to: the EmPOWER Maryland Limited Income Energy Efficiency Program; and the Multifamily Energy Efficiency and Housing Affordability Program; the Maryland Affordable Housing Trust Fund; Department of Housing and Urban Development programs, including: Community Development Block Grants; the Home Investment Partnership Grants Program; and Lead Hazard Control and Healthy Homes Grants; Department of Agriculture programs, including the Home Repair Program; the Healthy Homes for Healthy Kids Program; the Energy Efficiency and Conservation Block Grant program; State appropriations; funds from the federal Inflation Reduction Act of 2022; and any other source of funding that the Department or the Task Force identifies. The Department shall ensure, for any whole home retrofits associated with weatherization provided or developed under the plan, that: there is a single point of contact for low–income residential households; and services are offered in any language needed by the low–income residential households. The Department shall collaborate with the members of the Task Force and identify other interested parties to develop the plan. On or before December 31, 2024, the Department shall submit the plan to the Governor and, in accordance with § 2–1257 of the State Government Article, the General Assembly. The Department, the Maryland Energy Administration, and other State units shall apply for all federal funding that may become available to carry out this section. The Department shall collaborate with the members of the Task Force to develop a plan, including a budget, a timeline, and potential funding sources, to provide energy efficiency retrofits to all low–income households by 2032. On or before December 1, 2024, the Department, in collaboration with the Task Force, shall submit the plan to the General Assembly, in accordance with § 2–1257 of the State Government Article.

As soon as possible in 2024, and at least 8 months before the filing deadline for plans after 2024, the Commission shall issue an order that determines the greenhouse gas emissions reduction targets required under § 7–223(b) of this subtitle and the greenhouse gas emissions reductions required under § 7–224(a)(2) of this subtitle. If directed by the Commission in 2024, and on or before July 1 every 3 years, starting in 2026, each electric company subject to § 7–222(a) of this subtitle that submitted a plan for achieving electricity savings and demand reduction targets to the Commission before July 1, 2024, and the Department, shall consult with the technical staff of the Commission, the Office of People’s Counsel, the Maryland Energy Administration, and the Department of the Environment regarding the design and adequacy of its plans for achieving the greenhouse gas emissions reduction targets established by the Commission under § 7–223(b) of this subtitle and specified in § 7–224(a)(2) of this subtitle. On or before October 1, 2024, and on or before July 1 every 3 years, starting in 2026, each electric company subject to § 7–222(a) of this subtitle that did not submit a plan for achieving electricity savings and demand reduction targets to the Commission before July 1, 2024, shall comply with the consulting requirements under subparagraph (i) of this paragraph. Each electric company subject to § 7–222(a) of this subtitle shall provide the technical staff of the Commission, the Office of People’s Counsel, the Maryland Energy Administration, and the Department of the Environment with any additional information regarding its plan, as requested. If directed by the Commission in 2024, and on or before September 1 every 3 years, starting in 2026, each electric company subject to § 7–222(a) of this subtitle that submitted a plan for achieving electricity savings and demand reduction targets to the Commission before July 1, 2024, and the Department, shall submit its plan to the Commission. On or before December 1, 2024, and on or before September 1 every 3 years, starting in 2026, each electric company that did not submit a plan for achieving electricity savings and demand reduction targets to the Commission before July 1, 2024, shall submit its plan to the Commission. Each plan shall detail a proposal for achieving greenhouse gas emissions reduction targets for 3 subsequent calendar years. Each plan shall: include: a description of the proposed programs and services; anticipated costs; projected benefits, including greenhouse gas emissions reductions and electricity savings; and any other information requested by the Commission; and address residential, commercial, and industrial sectors as appropriate, including low–income communities. A plan of the Department shall include: a definition of “low–income individual” to be used in the procurement or provision of energy efficiency, conservation, and greenhouse gas emissions reduction programs and services; a description of the steps proposed to ensure insulation materials meet the requirements under § 7–224 of this subtitle; and a proposed average lifetime measure threshold that: encourages the delivery of insulation and weatherization measures; and is developed through a stakeholder engagement process. A plan of an electric company shall include the provision or procurement of programs and services for residential beneficial electrification. The Commission shall review the plan of each electric company and the Department to determine whether the plan is adequate and cost–effective in achieving the greenhouse gas emissions reduction targets established by the Commission under §§ 7–223(b) and 7–224(a)(2) of this subtitle. The Commission shall consider any written findings provided by the Maryland Energy Administration, the Department of the Environment, and the Office of People’s Counsel regarding the design and adequacy of the plan. Subject to paragraph (4) of this subsection, in approving, modifying, or denying the plan of an electric company, the Commission shall consider: the cost–effectiveness of the residential, commercial, and industrial sector subportfolios by using: the primary State jurisdiction–specific test, as developed, updated, or approved by the Commission, to determine the cost–effectiveness of a program or service prospectively, including consideration of: participant nonenergy benefits; utility nonenergy benefits; and societal nonenergy benefits; and a total resource cost test to compare the electricity savings and demand reduction targets of the program or service with the results of similar programs or services implemented in other jurisdictions, including: participant nonenergy benefits; and utility nonenergy benefits; the impact on rates of each ratepayer class; the impact on jobs; the impact on the environment; and the impact on the greenhouse gas emissions reduction targets specified in Title 2, Subtitle 12 of the Environment Article, established by the Commission under §§ 7–223(b) and 7–224(a)(2) of this subtitle. Nonenergy benefits considered under paragraph (3) of this subsection shall be quantifiable and directly related to a program or service. In approving, modifying, or denying the plan of the Department, the Commission shall consider: subject to subparagraph (ii) of this paragraph, the cost–effectiveness of the plan by using the primary State jurisdiction–specific test, as developed, updated, or approved by the Commission; the impact on rates of each ratepayer class; the impact on jobs; the impact on the environment; and the impact on the greenhouse gas emissions targets specified in Title 2, Subtitle 12 of the Environment Article, established by the Commission under § 7–223(b) of this subtitle, and specified in § 7–224(a)(2) of this subtitle. The programs and services offered by the Department are not required to be cost–effective. The Department of the Environment shall prepare and submit to the Commission an analysis regarding the adequacy of the plan in supporting the State’s greenhouse gas emissions reduction goals specified in Title 2, Subtitle 12 of the Environment Article, established by the Commission under § 7–223(b) of this subtitle, and required under § 7–224(a)(2) of this subtitle.

Each electric company and the Department shall provide to the Commission every 6 months an update on plan implementation and progress made toward achieving the greenhouse gas emissions reduction targets established by the Commission under § 7–223(b) of this subtitle and required under § 7–224(a)(2) of this subtitle. The Commission shall monitor and analyze the impact of each program and service to ensure that the outcome of each program and service provides the best possible results. In monitoring and analyzing the impact of a program or service under paragraph (2) of this subsection, if the Commission finds that the outcome of the program or service may not be providing the best possible results, the Commission shall direct the electric company or the Department to include in its next update under paragraph (1) of this subsection specific measures to address the findings. At least once each year, each electric company shall notify affected customers of the energy efficiency and conservation and greenhouse gas reduction charges imposed and benefits conferred. The notice shall be provided by publication on the company’s website and inclusion with billing information such as a bill insert or bill message. On or before May 1 each year, the Commission shall report, in accordance with § 2–1257 of the State Government Article, to the General Assembly on: the status of programs and services approved under this subtitle, including an evaluation of the impact of the programs and services that are directed to low–income communities and other particular classes of ratepayers; a recommendation for the appropriate funding level to adequately fund these programs and services; the per capita electricity consumption and the winter and summer peak demand for the previous calendar year; and beginning in 2026, progress made toward reducing greenhouse gas emissions in accordance with §§ 7–223 and 7–224 of this subtitle.

Notwithstanding any other law, the Commission may not require or allow an electric company to require a customer to authorize the electric company to control the amount of the customer’s electricity usage. A customer may provide consent to participate in a program of an electric company that provides direct load control or other utility manipulation of a customer’s electricity usage.

Each electric company shall promote the availability of federal and State rebates, tax credits, and incentives that can be used to support energy efficiency investments, energy efficient and non–fossil–fuel–powered appliances and cooking equipment, breaker box upgrades, and portable heating and cooling equipment. The Commission shall adopt regulations to carry out this section.

Nothing in this part prohibits the Commission from approving a demand response program proposed by an electric company if the demand response program is determined to be cost–effective and improve system reliability.

In this part the following words have the meanings indicated. “District energy system” means an underground infrastructure asset whose primary purpose is to provide thermal energy to multiple buildings from a central energy plant or plants. “Duplicative interconnection request” means an interconnection request that: is substantially similar to another interconnection request submitted by the large load customer or the customer’s parent company or affiliate; is submitted to an electric company in the State or in another state in the PJM region; and if progressed further through the interconnection process, would cause the large load customer to materially change, delay, or withdraw the applicable interconnection request. “Incremental resources” includes one or a combination of the following facilities and resources, located within the applicable locational deliverability area: behind–the–meter energy storage facilities; newly interconnected energy storage facilities; and purchasing or establishing nonemitting resources within the locational deliverability area, including: new clean energy generation assets; new virtual power plant aggregations; and a demand response program that the Commission determines meets the goals established under § 7–234 of this subtitle, including programs administered by PJM. “Large load customer” means a commercial or industrial customer for retail electric service that: has or is projected to have an aggregate monthly demand of at least 25 megawatts; and has or is projected to have a load factor of more than 60%. “Large load customer” does not include a commercial or industrial customer for retail electric service whose primary purpose is to operate as: a water company or sewage disposal company; a manufacturing facility; a hospital; a district energy system; an agricultural facility; or at the discretion of the Commission, another industrial facility. “Manufacturing facility” means a facility where the process of substantially transforming, or a substantial step in the process of substantially transforming, tangible personal property into a new and different article of tangible personal property by the use of labor or machinery occurs. “On–site backup generating facility” means a generating facility that is not connected to the electric system. “Virtual power plant” means an aggregation of distributed clean energy resources and energy storage owned by a customer or a third party that: provides electric system services; and may be used by the customer or the third party for other applications when not providing electric system services. “Voluntary clean capacity rating program” means the program developed by the Commission under § 7–234 of this subtitle.

On or before July 1, 2027, the Commission, by order or regulation, shall establish a large load customer registry to: provide information relevant to planning at the electric distribution, State, and PJM levels; and assist in ensuring accurate load forecasts at the electric distribution, State, and PJM levels. The Commission shall develop a process for registration under this section. The process shall: apply to new or expanded interconnection of large load customers; require a large load customer to: disclose all information about the large load customer as specified in this section; disclose each of the large load customer’s duplicative interconnection requests and any associated information, as described in this section; explain how the large load customer’s energy and capacity needs will be served and describe any anticipated arrangements, including arrangements: with third parties; and for new or existing generation and energy storage, whether on–site or off–site; disclose information about the anticipated type of on–site backup generating facility that would be used in the event of a system outage; disclose information about: the amount of water that the large load customer will use each month; the source of the water that will be used; and the status of an application for a water appropriation or use permit submitted to the Department of the Environment or a water utility; disclose the status and type of site control for the proposed location of the large load customer’s facility, including ownership or lease control; disclose energy characteristics of the customer, including: peak load; anticipated load factor; timing of requested service; load ramp period; annual energy usage; and load profile or, if unavailable, a description of the large load customer’s average hourly use; provide a description of the large load customer’s operation; disclose the point of interconnection and address or coordinates of the large load customer; and provide any other information the Commission considers necessary for the purposes identified in subsection (a) of this section; and establish any other standards that the Commission considers necessary. Except as provided in subsection (e) of this section, a large load customer shall register with the Commission in accordance with this section: within 30 days after signing a Federal Energy Regulatory Commission–Jurisdictional Agreement with an electric company; or within 30 days after an electric company provides to the Commission and the large load customer the information required in paragraph (2) of this subsection. An electric company shall provide written notice to the Commission and a large load customer when the electric company provides to PJM information related to the large load customer that may impact PJM forecasts or markets. Electric companies and large load customers shall provide to the Commission within the timelines set by the Commission: updated information regarding a registered large load customer, including if: a new duplicative interconnection request becomes known; or there is a change in the status of a duplicative interconnection request; and any other information that the Commission considers relevant. Within 60 days after receiving an application for registration under this section, including all information required under subsection (b) of this section, the Commission shall certify whether a registration under this section is complete. If the Commission determines that the registration information is incomplete, the Commission may extend any time frame provided in an order or regulation adopted in accordance with this section. The Commission shall charge a registration fee of not less than $1,000 per megawatt of the peak load of the large load customer. The fee revenue received under paragraph (1) of this subsection shall be used only as follows: 50% for the electric universal service program established under § 5–5A–08 of the Human Services Article; and 50% for the program established under § 7–224 of this subtitle. The Commission shall impose penalties against a large load customer if the large load customer: fails to register in accordance with this section; or intentionally misleads the Commission in its registration. The Commission may direct proceeds collected from a penalty imposed under paragraph (1) of this subsection to be provided to existing electric customers in the same service territory as the large load customer. Except as specified in paragraph (2) of this subsection, confidential commercial or financial information disclosed to the Commission by a large load customer in accordance with subsection (b)(2)(ii) of this section: shall be considered protected from disclosure under § 4–335 of the General Provisions Article before the large load customer is operational; and may be disclosed by the Commission: in a manner that is consistent with Title 4 of the General Provisions Article when the large load customer becomes operational; or notwithstanding item (i) of this paragraph: in accordance with paragraph (2) of this subsection; if the information has been made public by any person; or if the information is aggregated and anonymized as described in subsection (j)(2) of this section. The Commission shall establish a procedure for the disclosure of confidential commercial and financial information provided in accordance with subsection (b)(2)(ii) of this section to a unit of State government, PJM, or another person if considered appropriate by the Commission and only for the purpose of accurate load forecasting, transmission planning, or other reasons the Commission considers necessary. A person authorized to access confidential information under paragraph (2) of this subsection shall keep the information accessed confidential. Beginning July 1, 2027, an electric company may not submit a large load adjustment request to PJM unless the large load customer has completed the registration process under this section. On or before October 1, 2027, and each October 1 thereafter, the Commission shall report to the Senate Committee on Education, Energy, and the Environment and the House Environment and Transportation Committee, in accordance with § 2–1257 of the State Government Article, on the large load customer registry required under this section. The report: shall include information disclosed in subsection (b)(2)(ii) of this section aggregated by each electric company service territory; may not disclose confidential commercial or financial information as described in subsection (b)(2)(ii) of this section unless the information: consists of energy characteristics identified in subsection (b)(2)(ii)7A, C, and D of this section, provided that the information has been anonymized and projects are only identified by electric company service territory; is: used by an electric company for the identification of duplicative interconnection requests both in and outside the State; and anonymized and projects are identified only by electric company service territory; or has been previously disclosed to the public; and shall include any other information regarding large load customers as a whole in an electric company’s service territory that the Commission considers appropriate. If there is only one large load customer identified within an electric company service territory that is not the subject of a duplicative interconnection request, the Commission may report that large load customer’s information in an aggregated manner in conjunction with data from an adjacent electric company’s service territory in order to preserve anonymity. All information provided in the report submitted under this subsection may be used publicly by the Commission.

On or before December 15, 2027, the Commission shall develop a voluntary clean capacity rating program that establishes clean capacity ratings for large load customers that elect to participate in the program, including platinum and gold rating designations. The rating system shall: account for a large load customer’s voluntary adoption of demand response and incremental resources; and evaluate the extent to which the large load customer provides adequate incremental resources to meet a percentage of its peak load as assigned by PJM and grossed up by the appropriate reserve margin. A large load customer may be eligible for a gold or platinum rating under this section only if the large load customer: ensures that workers constructing the large load customer’s facility are paid not less than the prevailing wage rate determined by the Commissioner of Labor and Industry under Title 17, Subtitle 2 of the State Finance and Procurement Article; and enters into a memorandum of understanding with the Commission that: confirms the large load customer’s commitment to provide and maintain the capacity referenced in subsections (c) and (d) of this section for the life of the facility; and provides that the large load customer consents to the Commission’s jurisdiction for enforcement of penalty provisions established under paragraph (2) of this subsection. The Commission shall establish penalties for a large load customer that violates a memorandum of understanding entered into under paragraph (1)(ii) of this subsection. The penalties shall account for both the benefits received by the large load customer and the harm done to the State and ratepayers by the violation. Consent under paragraph (1)(ii)2 of this subsection to the enforcement of penalties established in this paragraph shall continue until the Commission provides written notice to the large load customer that relieves the customer from the obligation. A large load customer may receive a gold rating only if the customer demonstrates that it has adequate incremental resources sufficient to cover the customer’s capacity for at least 80% of the customer’s peak load as assigned by PJM and added together with the appropriate reserve margin through a combination of incremental resources. A large load customer may receive a platinum rating only if the customer demonstrates that it has adequate incremental resources sufficient to cover the customer’s capacity for 100% of the customer’s peak load as assigned by PJM and added together with the appropriate reserve margin through a combination of incremental resources. Benefits of receiving a gold or platinum rating include: for a large load customer that has received a gold rating, prioritization for load studies and interconnection over large load customers that do not have a gold or platinum rating; and for a large load customer that has received a platinum rating: prioritization for load studies and interconnection over other large load customers that do not have a platinum rating; a guarantee that permit applications submitted to the Department of the Environment shall be processed within 12 months after submission, pending compliance with applicable State and federal laws, including existing environmental justice requirements; and the opportunity to procure and provide, before permits are issued, equipment for any substation needed to interconnect the large load customer to the electric system. A large load customer that does not have a gold or platinum rating is not entitled to the benefits listed in subsection (e) of this section. If a large load customer with a platinum rating elects to procure and provide equipment for a substation in accordance with subsection (e)(2)(iii) of this section, the large load customer: shall provide all the necessary equipment for constructing the substation infrastructure; may procure the equipment before the electric company in whose service territory the large load customer is or will be located has issued final permitting approvals; and may enter into an agreement with the electric company that details what equipment the electric company may purchase for the construction of the substation, but the entirety of the equipment shall be funded or provided by the large load customer. Any equipment procured by the large load customer for the construction of a substation under this subsection shall meet the necessary interconnection requirements of the electric company in whose service territory the substation will be located. Costs incurred as a result of constructing a substation under this subsection may not be passed on to other customers, either through an electric company’s rates or otherwise, and shall be fully borne by the large load customer. Each electric company shall develop processes and tariffs for review and approval by the Commission to allow for the large load customer to procure and provide equipment under this subsection. Nothing in this subsection shall relieve a large load customer that does not have a voluntary clean capacity rating from any requirement to pay the cost of constructing a substation completed through the standard permitting and interconnection processes. Subject to Commission approval, each electric company shall establish an interconnection process for large load customers that participate in the voluntary clean capacity rating program. The interconnection process established under this section may not unduly impact the time frame or ability of customers that are not large load customers to interconnect with the electric system. The interconnection process shall include: a standard timeline for large load customers that participate in the voluntary clean capacity rating program but do not have a gold or platinum rating; and a prioritization process for large load customers with a gold or platinum rating. Before entering into a contract for electric service, a large load customer that participates in the voluntary clean capacity rating program shall submit a request for a load study under § 4–212 of this article to determine the necessary contract capacity for the large load customer.