In this subtitle the following words have the meanings indicated. “Administration” means the Maryland Energy Administration. “Fund” means the Maryland Strategic Energy Investment Fund established under § 9–20B–05 of the State Government Article. “Geothermal heating and cooling system” means a system that: exchanges thermal energy from groundwater or a shallow ground source to generate thermal energy through a geothermal heat pump or a system of geothermal heat pumps interconnected with any geothermal extraction facility that is: a closed loop or a series of closed loop systems in which fluid is permanently confined within a pipe or tubing and does not come in contact with the outside environment; or an open loop system in which ground or surface water is circulated in an environmentally safe manner directly into the facility and returned to the same aquifer or surface water source; meets or exceeds the current federal Energy Star product specification standards; is manufactured, installed, and operated in accordance with applicable government and industry standards; and does not feed electricity back to the grid. “Industrial process load” means the consumption of electricity by a manufacturing process at an establishment classified in the manufacturing sector under the North American Industry Classification System, Codes 31 through 33. “Legacy geothermal system” means a geothermal heating and cooling system that was placed in service on or before December 31, 2022. “Offshore wind energy” means energy generated by a qualified offshore wind project. “Offshore wind renewable energy credit” or “OREC” means a renewable energy credit equal to the generation attributes of 1 megawatt–hour of electricity that is derived from offshore wind energy. “Offshore wind transmission project” means an electric transmission project selected by the Commission under § 7–704.3 of this subtitle to interconnect directly or indirectly with one or more qualified offshore wind projects. “Old growth timber” means timber from a forest: at least 5 acres in size with a preponderance of old trees, of which the oldest exceed at least half the projected maximum attainable age for the species; and that exhibits several of the following characteristics: shade–tolerant species are present in all age and size classes; randomly distributed canopy gaps are present; a high degree of structural diversity characterized by multiple growth layers reflecting a broad spectrum of ages is present; an accumulation of dead wood of varying sizes and stages of decomposition accompanied by decadence in live dominant trees is present; and pit and mound topography can be observed. “Post–2022 geothermal system” means a geothermal heating and cooling system that is placed in service on or after January 1, 2023. “Poultry litter” means the fecal and urinary excretions of poultry, including wood shavings, sawdust, straw, rice hulls, and other bedding material for the disposition of manure. “Qualified offshore wind project” means a wind turbine electricity generation facility, including the associated transmission–related interconnection facilities and equipment, that: is located: on the outer continental shelf of the Atlantic Ocean in an area that the United States Department of the Interior designates for leasing; and more than 10 miles off the coast of the State for a project selected under § 7–704.4 of this subtitle or approved under § 7–704.1 of this subtitle after June 1, 2023; and interconnects to the PJM Interconnection grid: at a point located on the Delmarva Peninsula; or through an offshore wind transmission project selected under § 7–704.3 of this subtitle. “Qualifying biomass” means a nonhazardous, organic material that is available on a renewable or recurring basis, and is: waste material that is segregated from inorganic waste material and is derived from sources including: except for old growth timber, any of the following forest–related resources: mill residue, except sawdust and wood shavings; precommercial soft wood thinning; slash; brush; or yard waste; a pallet, crate, or dunnage; agricultural and silvicultural sources, including tree crops, vineyard materials, grain, legumes, sugar, and other crop by–products or residues; or gas produced from the anaerobic decomposition of animal waste or poultry waste; or a plant that is cultivated exclusively for purposes of being used at a Tier 1 renewable source or a Tier 2 renewable source to produce electricity. “Qualifying biomass” includes biomass listed in paragraph (1) of this subsection that is used for co–firing, subject to § 7–704(d) of this subtitle. “Qualifying biomass” does not include: unsegregated solid waste or postconsumer wastepaper; black liquor, or any product derived from black liquor; or an invasive exotic plant species. “Renewable energy credit” or “credit” means a credit equal to the generation attributes of 1 megawatt–hour of electricity that is derived from a Tier 1 renewable source or a Tier 2 renewable source that is located: in the PJM region; outside the area described in item (1) of this subsection but in a control area that is adjacent to the PJM region, if the electricity is delivered into the PJM region; or on the outer continental shelf of the Atlantic Ocean in an area that: the United States Department of the Interior designates for leasing after coordination and consultation with the State in accordance with § 388(a) of the Energy Policy Act of 2005; and is between 10 and 80 miles off the coast of the State. “Renewable energy portfolio standard” or “standard” means the percentage of electricity sales at retail in the State that is to be derived from Tier 1 renewable sources and Tier 2 renewable sources in accordance with § 7–703(b) of this subtitle. “Renewable on–site generator” means a person who generates electricity on site from a Tier 1 renewable source or a Tier 2 renewable source for the person’s own use. “Round 1 offshore wind project” means a qualified offshore wind project that: is between 10 and 30 miles off the coast of the State; and the Commission approved under § 7–704.1 of this subtitle before July 1, 2017. “Round 2 offshore wind project” means a qualified offshore wind project that: is not less than 10 miles off the coast of the State; and the Commission approves under § 7–704.1 of this subtitle on or after July 1, 2017. “Solar water heating system” means a system that: consists of glazed liquid–type flat–plate or tubular solar collectors or concentrating solar thermal collectors as defined and certified to the OG–100 standard of the Solar Ratings and Certification Corporation; generates energy using solar radiation for the purpose of heating water; and does not feed electricity back to the electric grid. “Solar water heating system” does not include a system that generates energy using solar radiation for the sole purpose of heating a hot tub or swimming pool. “Thermal biomass system” means a system that: uses: primarily animal manure, including poultry litter, and associated bedding to generate thermal energy; and food waste or qualifying biomass for the remainder of the feedstock; is used in the State; and complies with all applicable State and federal statutes and regulations, as determined by the appropriate regulatory authority. “Tier 1 renewable source” means one or more of the following types of energy sources: solar energy, including energy from photovoltaic technologies and solar water heating systems; wind; qualifying biomass; methane from the anaerobic decomposition of organic materials in a landfill or wastewater treatment plant; geothermal, including energy generated through geothermal exchange from or thermal energy avoided by, groundwater or a shallow ground source; ocean, including energy from waves, tides, currents, and thermal differences; a fuel cell that produces electricity from a Tier 1 renewable source under item (3) or (4) of this subsection; a small hydroelectric power plant of less than 30 megawatts in capacity that is licensed or exempt from licensing by the Federal Energy Regulatory Commission; poultry litter–to–energy; thermal energy from a thermal biomass system; and raw or treated wastewater used as a heat source or sink for a heating or cooling system. “Tier 2 renewable source” means hydroelectric power other than pump storage generation.

It is the intent of the General Assembly to: recognize the economic, environmental, fuel diversity, and security benefits of renewable energy resources; reduce greenhouse gas emissions and eliminate carbon–fueled generation from the State’s electric grid by using these resources; establish a market for electricity from these resources in Maryland; and lower the cost to consumers of electricity produced from these resources. The General Assembly finds that: the benefits of electricity from renewable energy resources, including long–term decreased emissions, a healthier environment, increased energy security, and decreased reliance on and vulnerability from imported energy sources, accrue to the public at large; electricity suppliers and consumers share an obligation to develop a minimum level of these resources in the electricity supply portfolio of the State; and the State needs to increase its reliance on renewable energy in order to: reduce greenhouse gas emissions and meet the State’s greenhouse gas emissions reduction goals under § 2–1205 of the Environment Article; and provide opportunities for small, minority, women–owned, and veteran–owned businesses to participate in and develop a highly skilled workforce for clean energy industries in the State.

The Commission shall implement a renewable energy portfolio standard that, except as provided under paragraphs (2) and (3) of this subsection, applies to all retail electricity sales in the State by electricity suppliers. If the standard becomes applicable to electricity sold to a customer after the start of a calendar year, the standard does not apply to electricity sold to the customer during that portion of the year before the standard became applicable. A renewable energy portfolio standard may not apply to electricity sales at retail by any electricity supplier: in excess of 300,000,000 kilowatt–hours of industrial process load to a single customer in a year; to residential customers in a region of the State in which electricity prices for residential customers are subject to a freeze or cap contained in a settlement agreement entered into under § 7–505 of this title until the freeze or cap has expired; or to a customer served by an electric cooperative under an electricity supplier purchase agreement that existed on October 1, 2004, until the expiration of the agreement, as the agreement may be renewed or amended. The portion of a renewable energy portfolio standard that represents offshore wind energy: applies only to the distribution sales of electric companies; and may not apply to distribution sales by any electric company in excess of: 75,000,000 kilowatt–hours of industrial process load to a single customer in a year; and 3,000 kilowatt–hours of electricity in a month to a customer who is an owner of agricultural land and files an Internal Revenue Service form 1040, schedule F. Except as provided in subsections (e) and (f) of this section, the renewable energy portfolio standard shall be as follows: in 2006, 1% from Tier 1 renewable sources and 2.5% from Tier 2 renewable sources; in 2007, 1% from Tier 1 renewable sources and 2.5% from Tier 2 renewable sources; in 2008, 2.005% from Tier 1 renewable sources, including at least 0.005% derived from solar energy, and 2.5% from Tier 2 renewable sources; in 2009, 2.01% from Tier 1 renewable sources, including at least 0.01% derived from solar energy, and 2.5% from Tier 2 renewable sources; in 2010, 3.025% from Tier 1 renewable sources, including at least 0.025% derived from solar energy, and 2.5% from Tier 2 renewable sources; in 2011, 5.0% from Tier 1 renewable sources, including at least 0.05% derived from solar energy, and 2.5% from Tier 2 renewable sources; in 2012, 6.5% from Tier 1 renewable sources, including at least 0.1% derived from solar energy, and 2.5% from Tier 2 renewable sources; in 2013, 8.2% from Tier 1 renewable sources, including at least 0.25% derived from solar energy, and 2.5% from Tier 2 renewable sources; in 2014, 10.3% from Tier 1 renewable sources, including at least 0.35% derived from solar energy, and 2.5% from Tier 2 renewable sources; in 2015, 10.5% from Tier 1 renewable sources, including at least 0.5% derived from solar energy, and 2.5% from Tier 2 renewable sources; in 2016, 12.7% from Tier 1 renewable sources, including at least 0.7% derived from solar energy, and 2.5% from Tier 2 renewable sources; in 2017: 1% from Tier 1 renewable sources, including: at least 1.15% derived from solar energy; and an amount set by the Commission under § 7–704.2(a) of this subtitle, not to exceed 2.5%, derived from offshore wind energy; and 5% from Tier 2 renewable sources; in 2018: 8% from Tier 1 renewable sources, including: at least 1.5% derived from solar energy; and an amount set by the Commission under § 7–704.2(a) of this subtitle, not to exceed 2.5%, derived from offshore wind energy; and 5% from Tier 2 renewable sources; in 2019: 7% from Tier 1 renewable sources, including: at least 5.5% derived from solar energy; and an amount set by the Commission under § 7–704.2(a) of this subtitle, not to exceed 2.5%, derived from offshore wind energy; and 5% from Tier 2 renewable sources; in 2020: 28% from Tier 1 renewable sources, including: at least 6% derived from solar energy; and an amount set by the Commission under § 7–704.2(a) of this subtitle, not to exceed 2.5%, derived from offshore wind energy; and 5% from Tier 2 renewable sources; in 2021: 8% from Tier 1 renewable sources, including: at least 7.5% derived from solar energy; and an amount set by the Commission under § 7–704.2(a) of this subtitle derived from offshore wind energy; and 5% from Tier 2 renewable sources; in 2022: 1% from Tier 1 renewable sources, including: at least 5.5% derived from solar energy; and an amount set by the Commission under § 7–704.2(a) of this subtitle derived from offshore wind energy; and 5% from Tier 2 renewable sources; in 2023: 9% from Tier 1 renewable sources, including: at least 6% derived from solar energy; an amount set by the Commission under § 7–704.2(a) of this subtitle derived from offshore wind energy; and at least 0.05% derived from post–2022 geothermal systems; and 5% from Tier 2 renewable sources; in 2024: 7% from Tier 1 renewable sources, including: at least 6.5% derived from solar energy; an amount set by the Commission under § 7–704.2(a) of this subtitle derived from offshore wind energy; and at least 0.15% derived from post–2022 geothermal systems; and 5% from Tier 2 renewable sources; in 2025: 5% from Tier 1 renewable sources, including: at least 7% derived from solar energy; an amount set by the Commission under § 7–704.2(a) of this subtitle, not to exceed 10%, derived from offshore wind energy; and at least 0.25% derived from post–2022 geothermal systems; and 5% from Tier 2 renewable sources; in 2026: 38% from Tier 1 renewable sources, including: at least 8% derived from solar energy; an amount set by the Commission under § 7–704.2(a) of this subtitle derived from offshore wind energy, including at least 400 megawatts of Round 2 offshore wind projects; and at least 0.5% derived from post–2022 geothermal systems; and 5% from Tier 2 renewable sources; in 2027: 5% from Tier 1 renewable sources, including: at least 9.5% derived from solar energy; an amount set by the Commission under § 7–704.2(a) of this subtitle derived from offshore wind energy, including at least 400 megawatts of Round 2 offshore wind projects; and at least 0.75% derived from post–2022 geothermal systems; and 5% from Tier 2 renewable sources; in 2028: 43% from Tier 1 renewable sources, including: at least 11% derived from solar energy; an amount set by the Commission under § 7–704.2(a) of this subtitle derived from offshore wind energy, including at least 800 megawatts of Round 2 offshore wind projects; and at least 1% derived from post–2022 geothermal systems; and 5% from Tier 2 renewable sources; in 2029: 5% from Tier 1 renewable sources, including: at least 12.5% derived from solar energy; an amount set by the Commission under § 7–704.2(a) of this subtitle derived from offshore wind energy, including at least 800 megawatts of Round 2 offshore wind projects; and at least 1% derived from post–2022 geothermal systems; and 5% from Tier 2 renewable sources; and in 2030 and later: 50% from Tier 1 renewable sources, including: at least 14.5% derived from solar energy; an amount set by the Commission under § 7–704.2(a) of this subtitle derived from offshore wind energy, including at least 1,200 megawatts of Round 2 offshore wind projects; and at least 1% derived from post–2022 geothermal systems; and 5% from Tier 2 renewable sources. Before calculating the number of credits required to meet the percentages established under subsection (b) of this section, an electricity supplier shall exclude from its total retail electricity sales all retail electricity sales described in subsection (a)(2) and (3) of this section. Subject to subsections (a) and (c) of this section, an electricity supplier shall meet the renewable energy portfolio standard for all Tier 1 and Tier 2 renewable sources except offshore wind by accumulating the equivalent amount of renewable energy credits that equal the percentages required under this section. An electric company shall meet the renewable energy portfolio standard for offshore wind in accordance with § 7–704.2 of this subtitle. The required percentage of an electric cooperative’s renewable energy portfolio standard derived from solar energy shall be 2.5% in 2020 and later. The required percentage of a municipal electric utility’s renewable energy portfolio standard shall be: in 2021: 4% from Tier 1 renewable sources, including: at least 1.95% derived from solar energy; and an amount set by the Commission under § 7–704.2(a) of this subtitle, not to exceed 2.5%, derived from offshore wind energy; and 5% from Tier 2 renewable sources; and in 2022 and later, 20.4% from Tier 1 renewable sources, including: at least 1.95% derived from solar energy; and an amount set by the Commission under § 7–704.2(a) of this subtitle, not to exceed 2.5%, derived from offshore wind energy. In this subsection the following words have the meanings indicated. “Area median income” has the meaning stated in § 4–1801 of the Housing and Community Development Article. “Low or moderate income housing” means housing that is affordable for a household with an aggregate annual income that is below 120% of the area median income. At least 25% of the required percentage of the renewable energy portfolio for each year as set forth in subsection (b) of this section derived from post–2022 geothermal systems shall be derived from systems that were installed: at single or multifamily housing units that qualified as low or moderate income housing on the date the system was installed on the property; or at institutions that primarily serve low and moderate income individuals and families, including: schools with a majority of students who are eligible for free and reduced price meals; hospitals with a majority of patients eligible for financial assistance or who are enrolled in Medicaid; and other institutions that serve individuals and families where the majority of those served are eligible based on income for federal or State safety net programs.

Energy from a Tier 1 renewable source: is eligible for inclusion in meeting the renewable energy portfolio standard regardless of when the generating system or facility was placed in service; and may be applied to the percentage requirements of the standard for either Tier 1 renewable sources or Tier 2 renewable sources. Energy from a Tier 1 renewable source under § 7–701(s)(1), (5), or (9) of this subtitle is eligible for inclusion in meeting the renewable energy portfolio standard only if the source is connected with the electric distribution grid serving Maryland. Energy from a Tier 1 renewable source under § 7–701(s)(11) of this subtitle is eligible for inclusion in meeting the renewable energy portfolio standard only if the source: is connected with the electric distribution grid serving Maryland; or processes wastewater from Maryland residents. If the owner of a solar generating system in this State chooses to sell solar renewable energy credits from that system, the owner must first offer the credits for sale to an electricity supplier or electric company that shall apply them toward compliance with the renewable energy portfolio standard under § 7–703 of this subtitle. Energy from a Tier 1 renewable source under § 7–701(s)(8) of this subtitle is eligible for inclusion in meeting the renewable energy portfolio standard if it is generated at a dam that existed as of January 1, 2004, even if a system or facility that is capable of generating electricity did not exist on that date. Energy from a Tier 2 renewable source under § 7–701(t) of this subtitle is eligible for inclusion in meeting the renewable energy portfolio standard if it is generated at a system or facility that existed and was operational as of January 1, 2004, even if the facility or system was not capable of generating electricity on that date. On or after January 1, 2004, an electricity supplier may: receive renewable energy credits; and accumulate renewable energy credits under this subtitle. This subsection applies only to a generating facility that is placed in service on or after January 1, 2004. On or before December 31, 2005, an electricity supplier shall receive 120% credit toward meeting the renewable energy portfolio standard for energy derived from wind. After December 31, 2005, and on or before December 31, 2008, an electricity supplier shall receive 110% credit toward meeting the renewable energy portfolio standard for energy derived from wind. On or before December 31, 2008, an electricity supplier shall receive 110% credit toward meeting the renewable energy portfolio standard for energy derived from methane under § 7–701(r)(4) of this subtitle. An electricity supplier shall receive credit toward meeting the renewable energy portfolio standard for electricity derived from the biomass fraction of biomass co–fired with other fuels. In this subsection, “customer” means: an industrial electric customer that is not on standard offer service; or a renewable on–site generator. This subsection does not apply to offshore wind renewable energy credits. A customer may independently acquire renewable energy credits to satisfy the standards applicable to the customer’s load, including credits created by a renewable on–site generator. Credits that a customer transfers to its electricity supplier to meet the standard and that the electricity supplier relies on in submitting its compliance report may not be resold or retransferred by the customer or by the electricity supplier. A renewable on–site generator may retain or transfer at its sole option any credits created by the renewable on–site generator, including credits for the portion of its on–site generation from a Tier 1 renewable source or a Tier 2 renewable source that displaces the purchase of electricity by the renewable on–site generator from the grid. A customer that satisfies the standard applicable to the customer’s load under this subsection may not be required to contribute to a compliance fee recovered under § 7–706 of this subtitle. The Commission shall adopt regulations governing the application and transfer of credits under this subsection consistent with federal law. In order to create a renewable energy credit, a Tier 1 renewable source or Tier 2 renewable source must substantially comply with all applicable environmental and administrative requirements, including air quality, water quality, solid waste, and right–to–know provisions, permit conditions, and administrative orders. This paragraph applies to Tier 1 renewable sources that incinerate solid waste. At least 80% of the solid waste incinerated at a Tier 1 renewable source facility shall be collected from: for areas in Maryland, jurisdictions that achieve the recycling rates required under § 9–505 of the Environment Article; and for other states, jurisdictions for which the electricity supplier demonstrates recycling substantially comparable to that required under § 9–505 of the Environment Article, in accordance with regulations of the Commission. An electricity supplier may report credits received under this paragraph based on compliance by the facility with the percentage requirement of subparagraph (ii) of this paragraph during the year immediately preceding the year in which the electricity supplier receives the credit to apply to the standard. Energy from a solar water heating system is eligible for inclusion in meeting the renewable energy portfolio standard. A person that owns and operates a solar water heating system shall receive a renewable energy credit equal to the amount of energy, converted from BTUs to kilowatt–hours, that is generated by the system that is used by the person for water heating. The total amount of energy generated and consumed for a nonresidential or commercial solar water heating system shall be measured by an on–site meter that meets the required performance standards of the International Organization of Legal Metrology. The total amount of energy generated and consumed by a residential solar water heating system shall be: measured by a meter that meets the required standards of the International Organization of Legal Metrology; or measured by the Solar Ratings and Certification Corporation’s OG–300 thermal performance rating for the system or an equivalent certification that the Commission approves in consultation with the Administration; and certified to the OG–300 standard of the Solar Ratings and Certification Corporation or an equivalent certification body that the Commission approves in consultation with the Administration. A residential solar water heating system shall be installed in accordance with applicable State and local plumbing codes. A residential solar water heating system may not produce more than five solar renewable energy credits in any 1 year. Except as provided in paragraph (6) of this subsection, energy from a geothermal heating and cooling system, including energy from a legacy geothermal system and energy from a post–2022 geothermal system, is eligible for inclusion in meeting the renewable energy portfolio standard. A person shall receive a renewable energy credit equal to the amount of energy, converted from BTUs to kilowatt–hours, that is generated by a geothermal heating and cooling system for space heating and cooling or water heating if the person: owns and operates the system; leases and operates the system; or contracts with a third party who owns and operates the portion of the system that consists of: a closed loop or a series of closed loop systems in which fluid is permanently confined within a pipe or tubing and does not come in contact with the outside environment; or an open loop system in which ground or surface water is circulated in an environmentally safe manner directly into the facility and returned to the same aquifer or surface water source. To determine the energy savings of a geothermal heating and cooling system for a residence, the Commission shall: identify available energy consumption calculators developed by the geothermal heating and cooling industry; collect the following data provided in the renewable energy credit application that: describes the name of the applicant and the address at which the geothermal heating and cooling system is installed; and provides the annual BTU energy savings attributable to home heating, cooling, and water heating; and in determining the annual amount of renewable energy credits awarded for the geothermal heating and cooling system, convert the annual BTUs into annual megawatt–hours. To determine the energy savings of a nonresidential geothermal heating and cooling system, the Commission shall: use the geothermal heating and cooling engineering technical system designs provided with the renewable energy credit application; and in determining the annual amount of renewable energy credits awarded for the geothermal heating and cooling system, convert the annual BTUs into annual megawatt–hours. A geothermal heating and cooling system shall be installed in accordance with applicable State well construction and local building code standards. A post–2022 geothermal system with a 360,000 BTU capacity is eligible for inclusion in meeting the renewable energy portfolio standard only if the company installing the system provides for its employees: family–sustaining wages; employer–provided health care with affordable deductibles and co–pays; career advancement training, as provided in subparagraph (ii) of this paragraph; fair scheduling; employer–paid workers’ compensation and unemployment insurance; a retirement plan; paid time off; and the right to bargain collectively for wages and benefits. As part of the career advancement training the installation company provides, the company shall ensure that a minimum of 10% of the employees working on the installation are enrolled in an apprenticeship program approved by and registered with the State or the federal government. Compliance with this paragraph shall be regulated and enforced by the Maryland Department of Labor. Energy from a thermal biomass system is eligible for inclusion in meeting the renewable energy portfolio standard. A person that owns and operates a thermal biomass system that uses anaerobic digestion is eligible to receive a renewable energy credit. A person that owns and operates a thermal biomass system that uses a thermochemical process is eligible to receive a renewable energy credit if the person demonstrates to the Maryland Department of the Environment that the operation of the thermal biomass system: is not significantly contributing to local or regional air quality impairments; and will substantially decrease emissions of oxides of nitrogen beyond that achieved by a direct burn combustion unit through the use of precombustion techniques, combustion techniques, or postcombustion techniques. A person that is eligible to receive a renewable energy credit under paragraph (2) of this subsection shall receive a renewable energy credit equal to the amount of energy, converted from BTUs to kilowatt–hours, that is generated by the thermal biomass system and used on site. The total amount of energy generated and consumed for a residential, nonresidential, or commercial thermal biomass system shall be measured by an on–site meter that meets the required performance standards established by the Commission. The Commission shall adopt regulations for the metering, verification, and reporting of the output of thermal biomass systems. Energy from a wastewater heating or cooling system is eligible for inclusion in meeting the renewable energy portfolio standard. A person shall receive a renewable energy credit equal to the amount of energy, converted from BTUs to kilowatt–hours, that is generated by a wastewater heating or cooling system for space heating or cooling, industrial heating or cooling, or another useful thermal purpose, if the person: owns and operates the system; leases and operates the system; or contracts with a third party who owns and operates the system. To determine the energy savings of a wastewater heating or cooling system, the Commission shall: use the wastewater heating or cooling engineering technical system designs provided with the renewable energy credit application; and in determining the annual amount of renewable energy credits awarded for the wastewater heating or cooling system, convert the annual BTUs into annual megawatt–hours. The Commission shall adopt regulations for the metering, verification, and reporting of the output of wastewater heating or cooling systems.

The General Assembly finds and declares that: the State has a goal of reaching 8,500 megawatts of offshore wind energy capacity by 2031, including Round 1 offshore wind projects, Round 2 offshore wind projects, and any other procurement efforts; the General Assembly anticipates the issuance of sufficient wind energy leases in the central Atlantic region to satisfy the goal stated in item (i) of this paragraph; the development of offshore wind energy is important to the economic well–being of the State and the nation; offshore wind can provide clean energy at the scale needed to help achieve the State’s economy–wide net–zero greenhouse gas emissions reduction targets established in Chapter 38 of the Acts of the General Assembly of 2022; it is in the public interest of the State to facilitate the construction of at least 1,200 megawatts of Round 2 offshore wind projects in order to: position the State to take advantage of the economic development benefits of the emerging offshore wind industry; promote the development of renewable energy sources that increase the nation’s independence from foreign sources of fossil fuels; reduce the adverse environmental and health impacts of traditional fossil fuel energy sources; and provide a long–term hedge against volatile prices of fossil fuels; and it is in the public interest of the State to maximize the opportunities for obtaining and using federal funds for offshore wind and related transmission projects through the inclusion of specified labor standards and goals, domestic content requirements, and other provisions to align State law with provisions of the federal Infrastructure Investment and Jobs Act of 2021 and the federal Inflation Reduction Act of 2022. After the effective date of Commission regulations implementing this section and § 7–704.2 of this subtitle, and before June 30, 2017, a person may submit an application to the Commission for approval of a proposed Round 1 offshore wind project. On receipt of the application for approval of a Round 1 offshore wind project, the Commission shall: open an application period when other interested persons may submit applications for approval of Round 1 offshore wind projects; and provide notice that the Commission is accepting applications for approval of Round 1 offshore wind projects. The Commission shall set the closing date for the application period to be no sooner than 90 days after the notice provided under subparagraph (i) of this paragraph. The Commission shall provide additional application periods beginning, respectively: January 1, 2020, for consideration of Round 2 offshore wind projects to begin creating ORECs not later than 2026; January 1, 2021, for consideration of Round 2 offshore wind projects to begin creating ORECs not later than 2028; and January 1, 2022, for consideration of Round 2 offshore wind projects to begin creating ORECs not later than 2030. In its discretion, the Commission may provide for additional application periods that meet the requirements of this section. Unless extended by mutual consent of the parties, the Commission shall approve, conditionally approve, or deny an application within 180 days after the close of the application period. An application shall include: a detailed description and financial analysis of the offshore wind project; the proposed method of financing the offshore wind project, including documentation demonstrating that the applicant has applied for all current eligible State and federal grants, rebates, tax credits, loan guarantees, or other programs available to offset the cost of the project or provide tax advantages; a cost–benefit analysis that shall include at a minimum: a detailed input–output analysis of the impact of the offshore wind project on income, employment, wages, and taxes in the State with particular emphasis on in–State manufacturing employment; detailed information concerning assumed employment impacts in the State, including the expected duration of employment opportunities, the salary of each position, and other supporting evidence of employment impacts; an analysis of the anticipated environmental benefits, health benefits, and environmental impacts of the offshore wind project to the citizens of the State; an analysis of any impact on residential, commercial, and industrial ratepayers over the life of the offshore wind project; an analysis of any long–term effect on energy and capacity markets as a result of the proposed offshore wind project; an analysis of any impact on businesses in the State; and other benefits, such as increased in–State construction, operations, maintenance, and equipment purchase; a proposed OREC pricing schedule for the offshore wind project that shall specify a price for the generation attributes, including the energy, capacity, ancillary services, and environmental attributes; a decommissioning plan for the project, including provisions for decommissioning as required by the United States Department of the Interior; a commitment to: abide by the requirements set forth in subsection (f) of this section; and deposit at least $6,000,000, in the manner required under subsection (h) of this section, into the Maryland Offshore Wind Business Development Fund established under § 9–20C–03 of the State Government Article; a description of the applicant’s plan for engaging small businesses, as defined in § 14–501 of the State Finance and Procurement Article; a commitment that the applicant will: use best efforts to apply for all eligible State and federal grants, rebates, tax credits, loan guarantees, or other similar benefits as those benefits become available; and subject to subsection (k) of this section, pass along to ratepayers, without the need for any subsequent Commission approval, 80% of the value of any State or federal grants, rebates, tax credits, loan guarantees, or other similar benefits received by the project and not included in the application; and any other information the Commission requires. The following are subject to a community benefit agreement under subsection (f) of this section: an application for any new qualified offshore wind project; and a proposal selected by the Commission under § 7–704.3 of this subtitle for an offshore wind transmission project. The Commission shall use the following criteria to evaluate and compare proposed offshore wind projects submitted during an application period: lowest cost impact on ratepayers of the price set under a proposed OREC pricing schedule; potential reductions in transmission congestion prices within the State; potential changes in capacity prices within the State; potential reductions in locational marginal pricing; potential long–term changes in capacity prices within the State from the offshore wind project as it compares to conventional energy sources; the extent to which the cost–benefit analysis submitted under subsection (c)(3) of this section demonstrates positive net economic, environmental, and health benefits to the State; the extent to which an applicant’s plan for engaging small businesses meets the goals specified in Title 14, Subtitle 5 of the State Finance and Procurement Article; the extent to which an applicant’s plan provides for the use of skilled labor, particularly with regard to the construction and manufacturing components of the project, through outreach, hiring, or referral systems that are affiliated with registered apprenticeship programs under Title 11, Subtitle 4 of the Labor and Employment Article; the extent to which an applicant’s plan provides for the use of an agreement designed to ensure the use of skilled labor and to promote the prompt, efficient, and safe completion of the project, particularly with regard to the construction, manufacturing, and maintenance of the project; the extent to which an applicant’s plan provides for compensation to its employees and subcontractors consistent with wages outlined under §§ 17–201 through 17–228 of the State Finance and Procurement Article; siting and project feasibility; the extent to which the proposed offshore wind project would require transmission or distribution infrastructure improvements in the State; estimated ability to assist in meeting the renewable energy portfolio standard under § 7–703 of this subtitle; and any other criteria that the Commission determines to be appropriate. In evaluating and comparing an applicant’s proposed offshore wind project under paragraph (1) of this subsection, the Commission shall contract for the services of independent consultants and experts. The Commission shall verify that representatives of the United States Department of Defense and the maritime industry have had the opportunity, through the federal leasing process, to express concerns regarding project siting. In this paragraph, “minority” means an individual who is a member of any of the groups listed in § 14–301(k)(1)(i) of the State Finance and Procurement Article. If an applicant is seeking investors in a proposed offshore wind project, it shall take the following steps before the Commission may approve the proposed project: make serious, good–faith efforts to solicit and interview a reasonable number of minority investors; as part of the application, submit a statement to the Commission that lists the names and addresses of all minority investors interviewed and whether or not any of those investors have purchased an equity share in the entity submitting an application; as a condition to the Commission’s approval of the offshore wind project, sign a memorandum of understanding with the Commission that requires the applicant to again make serious, good–faith efforts to interview minority investors in any future attempts to raise venture capital or attract new investors to the offshore wind project; and as a condition to the Commission’s approval of the offshore wind project, sign a memorandum of understanding with the Commission that requires the applicant to use best efforts and effective outreach to obtain, as a goal, contractors and subcontractors for the project that are minority business enterprises, to the extent practicable, as supported by a disparity study. The Governor’s Office of Small, Minority, and Women Business Affairs, in consultation with the Office of the Attorney General, shall provide assistance to all potential applicants and potential minority investors to satisfy the requirements under subparagraph (ii)1 and 3 of this paragraph. As a condition of the Commission’s approval of the offshore wind project, the applicant shall sign a memorandum of understanding with the Commission and skilled labor organizations that requires the applicant to follow the portions of the applicant’s plan that relate to the criteria set forth in paragraph (1)(viii) and (ix) of this subsection. In this paragraph, “community benefit agreement” means an agreement applicable to the development of any qualified offshore wind project or offshore wind transmission facility that: promotes increased opportunities for local businesses and small, minority, women–owned, and veteran–owned businesses in the clean energy industry; ensures the timely, safe, and efficient completion of the project by: facilitating a steady supply of highly skilled craft workers who shall be 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 guaranteeing that the construction work performed in connection with the project will be subject to an agreement that: is with one or more labor organizations; and II.    establishes, in accordance with paragraph (3) of this subsection, the terms and conditions of employment at the construction site of the project or a portion of the project; promotes safe completion of the project by ensuring that at least 80% of the craft workers on the project have completed an Occupational Safety and Health Administration 10–hour or 30–hour course; promotes career training opportunities in the manufacturing, maintenance, and construction industries for local residents, veterans, women, and minorities; provides for best efforts and effective outreach to obtain, as a goal, the use of a workforce including minorities, to the extent practicable; reflects a 21st–century labor–management approach by developers and suppliers based on cooperation, harmony, and partnership that proactively seeks to ensure that workers can freely choose to both organize and collectively bargain; provides plans to use domestic iron, steel, and manufactured goods to the greatest extent practicable by disclosing contracted suppliers; uses locally and domestically manufactured construction materials and components; and maximizes the use of skilled local labor, particularly with regard to the construction and manufacturing components of the project, using methods including outreach, hiring, or referral methods that are affiliated with registered apprenticeship programs under Title 11, Subtitle 4 of the Labor and Employment Article. If the Commission receives reasonable proposals that demonstrate positive net economic, environmental, and health benefits to the State, based on the criteria specified in subsection (c)(3) of this section, and subject to subparagraph (iii) of this paragraph, the Commission shall approve orders to facilitate the financing of qualified offshore wind projects, including at least 1,200 megawatts of Round 2 offshore wind projects. The Commission may not approve an applicant’s proposed offshore wind project unless: for a Round 1 offshore wind project application: the projected net rate impact for an average residential customer, based on annual consumption of 12,000 kilowatt–hours, combined with the projected net rate impact of other Round 1 offshore wind projects, does not exceed $1.50 per month in 2012 dollars, over the duration of the proposed OREC pricing schedule; the projected net rate impact for all nonresidential customers considered as a blended average, combined with the projected net rate impact of other Round 1 offshore wind projects, does not exceed 1.5% of nonresidential customers’ total annual electric bills, over the duration of the proposed OREC pricing schedule; and the price specified in the proposed OREC pricing schedule does not exceed $190 per megawatt–hour in 2012 dollars; and for a Round 2 offshore wind project application: the projected incremental net rate impact for an average residential customer, based on annual consumption of 12 megawatt–hours, combined with the projected incremental net rate impact of other Round 2 offshore wind projects, does not exceed 88 cents per month in 2018 dollars, over the duration of the proposed OREC pricing schedule; the projected incremental net rate impact for all nonresidential customers considered as a blended average, combined with the projected net rate impact of other Round 2 offshore wind projects, does not exceed 0.9% of nonresidential customers’ total annual electric bills during any year of the proposed OREC pricing schedule; and the project is subject to a community benefit agreement. When calculating the net benefits to the State under paragraph (1)(ii) of this subsection, the Commission shall contract for the services of independent consultants and experts. When calculating the projected net average rate impacts for Round 1 offshore wind projects under paragraph (1)(iii)1A and B of this subsection and for Round 2 offshore wind projects under paragraph (1)(iii)2A and B of this subsection, the Commission shall apply the same net OREC cost per megawatt–hour to residential and nonresidential customers. An agreement required under paragraph (1)(i)2B of this subsection shall: guarantee against strikes, lockouts, and similar disruptions; ensure that all work on the project fully conforms to all relevant State and federal laws, rules, and regulations; create mutually binding procedures for resolving labor disputes arising during the term of the project; set forth other mechanisms for labor–management cooperation on matters of mutual interest and concern, including productivity, quality of work, safety, and health; and bind all contractors and subcontractors to the terms of the agreement through the inclusion of appropriate provisions in all relevant solicitation and contract documents. An order the Commission issues approving a proposed offshore wind project shall: specify the OREC pricing schedule, which may not authorize an OREC price greater than, for a Round 1 offshore wind project, $190 per megawatt–hour in 2012 dollars; specify the duration of the OREC pricing schedule, not to exceed 20 years; specify the number of ORECs the offshore wind project may sell each year; provide that: a payment may not be made for an OREC until electricity supply is generated by the offshore wind project; and ratepayers, purchasers of ORECs, and the State shall be held harmless for any cost overruns associated with the offshore wind project; and require that any debt instrument issued in connection with a qualified offshore wind project include language specifying that the debt instrument does not establish a debt, obligation, or liability of the State. An order approving a proposed offshore wind project vests the owner of the qualified offshore wind project with the right to receive payments for ORECs according to the terms in the order. On or before March 1 each year, the Commission shall report to the Governor and, in accordance with § 2–1257 of the State Government Article, to the Senate Committee on Education, Energy, and the Environment and the House Economic Matters Committee on: compliance by applicants with the minority business enterprise participation goals under subsection (e)(4) of this section; and with respect to the community benefit agreement under subsection (f)(1) of this section: the availability and use of opportunities for local businesses and small, minority, women–owned, and veteran–owned businesses; the success of efforts to promote career training opportunities in the manufacturing, maintenance, and construction industries for local residents, veterans, women, and minorities; and compliance with the minority workforce goal under subsection (f)(1)(i)5 of this section. For Round 2 offshore wind project applications, the Commission shall approve OREC orders representing a minimum of 400 megawatts of nameplate capacity proposed during each application period unless: not enough Round 2 offshore wind project applications are submitted to meet the net benefit test under subsection (c)(3) of this section; or the cumulative net ratepayer impact exceeds the maximums provided in subsection (f)(1)(ii)2 of this section. Within 60 days after the Commission approves the application of a proposed offshore wind project, the qualified offshore wind project shall deposit $2,000,000 into the Maryland Offshore Wind Business Development Fund established under § 9–20C–03 of the State Government Article. Within 1 year after the initial deposit under paragraph (1) of this subsection, the qualified offshore wind project shall deposit an additional $2,000,000 into the Maryland Offshore Wind Business Development Fund. Within 2 years after the initial deposit under paragraph (1) of this subsection, the qualified offshore wind project shall deposit an additional $2,000,000 into the Maryland Offshore Wind Business Development Fund. The findings and evidence relied on by the General Assembly for the continuation of the Minority Business Enterprise Program under Title 14, Subtitle 3 of the State Finance and Procurement Article are incorporated in this subsection. To the extent practicable and authorized by the United States Constitution, approved applicants for a proposed offshore wind project shall comply with the State’s Minority Business Enterprise Program. On or before 6 months after the issuance of an order approving an OREC application, the Office of Small, Minority, and Women Business Affairs, in consultation with the Office of the Attorney General and an approved applicant, shall establish a clear plan for setting reasonable and appropriate minority business enterprise participation goals and procedures for each phase of the qualified offshore wind project. To the extent practicable, the goals and procedures specified in subparagraph (i) of this paragraph shall be based on the requirements of Title 14, Subtitle 3 of the State Finance and Procurement Article and the regulations implementing that subtitle. Every 6 months following the issuance of an order approving an OREC application, an approved applicant shall submit a report on its progress establishing and implementing minority business enterprise goals and procedures to the Commission. On and after July 1, 2031, the provisions of this subsection and any regulations adopted in accordance with this subsection shall be of no effect and may not be enforced. A developer of a Round 1 offshore wind project or Round 2 offshore wind project approved under this section may apply to the Commission for a full or partial exemption from the requirements in subsection (c)(8)(ii) of this section for any federal Inflation Reduction Act of 2022 grants, rebates, tax credits, or loan guarantees received by the project if at least 15% of the total labor hours of construction, alteration, or repair work for the project, including any construction, alteration, or repair work performed by a contractor or subcontractor, is performed by qualified apprentices consistent with federal law. A developer seeking an exemption under paragraph (1) of this subsection shall certify that the exemption is required to fulfill the developer’s obligations under an approved OREC order. The Commission shall: establish an application process for a developer to apply for an exemption under paragraph (1) of this subsection; approve, deny, or request additional information regarding an application submitted under this subsection within 60 days after receipt of the application; in evaluating an application submitted under this subsection, take into consideration the potential benefits and impacts of approving the application, including: the State’s goals for developing offshore wind energy; workforce and supply chain impacts; and the risk that price inflation may have on achieving the State’s offshore wind energy goals; and keep any proprietary information submitted by an applicant confidential. If the Commission approves a partial exemption under paragraph (1) of this subsection, the nonexempt value of any federal Inflation Reduction Act of 2022 grants, rebates, tax credits, or loan guarantees received by the project shall be passed along to ratepayers. In this subsection, “revised Round 2 offshore wind project” means a Round 2 offshore wind project that has filed an application with the Commission for revised project schedules, sizes, or pricing, including OREC pricing, under this subsection. This subsection applies to Round 1 offshore wind projects and Round 2 offshore wind projects that: are to be located in a wind energy area authorized by the Bureau of Ocean Energy Management; and possess ORECs, or are subject to a Commission order approving an OREC price schedule, as of June 1, 2024. On June 1, 2024, the Commission shall open a revised Round 2 offshore wind project proceeding that is limited to evaluating revised project schedules, sizes, or pricing, including OREC pricing, for a previously approved Round 2 offshore wind project. Any previously approved Round 2 offshore wind project may submit a revised plan for the project by filing an application with the Commission. An application for a revised Round 2 offshore wind project shall be limited to addressing revised project schedules, sizes, or pricing, including OREC pricing. On receipt of an application for approval of a revised Round 2 offshore wind project, the Commission shall conduct an expedited review of the application. Unless extended by mutual consent of the parties, the Commission shall approve, conditionally approve, or deny an application within 90 days after the application is filed and found by the Commission to be administratively complete. Except as provided in subsubparagraphs 2 and 3 of this subparagraph, an application for a revised Round 2 offshore wind project shall be subject to all criteria set forth in this section for Round 2 offshore wind projects. An application for a revised Round 2 offshore wind project is not subject to the requirements of subsections (c)(6)(ii) and (i) of this section. If in a revised Round 2 offshore wind project proceeding the Commission reviews multiple reasonable proposals meeting the requirements of this section for Round 2 offshore wind projects, the Commission shall issue orders approving the revised Round 2 offshore wind projects necessary to facilitate as much energy capacity as is consistent with the Round 2 offshore wind project ratepayer protections under this section, including at least 800 megawatts of capacity from revised Round 2 offshore wind projects, if practicable, even if the revised Round 2 offshore wind project applications may result in lower total energy capacity awarded than was previously awarded to the revised Round 2 offshore wind project in its previously approved Round 2 offshore wind project application. When evaluating an application for a revised Round 2 offshore wind project, the Commission shall, to the extent practicable, extend prior or existing proceedings for applicants that have a previously approved order for a Round 2 offshore wind project. The Commission may not approve an application for a revised Round 2 offshore wind project unless the application includes commitments for in–State expenditures and investments in a local supply chain that the Commission determines are reasonably related to the size and requirements of the project. The Administration shall have access to all confidential information produced by any party relating to a revised Round 2 offshore wind project proceeding, subject to an agreement to protect the confidentiality of the information. In order to maximize the amount of renewable energy generated by a Round 1 offshore wind project, any Round 1 offshore wind project may seek approval from the Commission to amend its previously approved Round 1 offshore wind project order to: increase the maximum amount of ORECs sold under the previous order, consistent with the Round 1 offshore wind project ratepayer protections under this section; and modify its project schedule. The Commission may approve a request for an increased amount of ORECs sold under a previously approved Round 1 offshore wind project order on a showing that: the unit pricing of the additional ORECs does not exceed the pricing under the previously approved Round 1 offshore wind project order; and the Round 1 offshore wind project is in compliance with the ratepayer protection provisions required for Round 1 offshore wind projects, taking into consideration changes in economic conditions since the original Round 1 offshore wind project awards. The Commission, with the assistance of the Administration, the Department of General Services, and other interested State units shall develop a plan for achieving a total of 8,500 megawatts of offshore wind energy capacity by 2031. The plan: shall include a schedule of offshore wind energy procurements and proposed amounts of offshore wind energy for procurement through 2031; and may include recommendations on multijurisdictional offshore wind energy procurements and any additional offshore wind energy procurement recommendations. On or before January 1, 2025, the Commission shall submit a report on the plan to the General Assembly, in accordance with § 2–1257 of the State Government Article.

The Commission shall determine the offshore wind energy component of the renewable energy portfolio standard under § 7–703(b)(12) through (25) of this subtitle based on the projected annual creation of ORECs by qualified offshore wind projects. The Commission shall establish the renewable energy portfolio standard obligation for ORECs on a forward–looking basis that includes a surplus to accommodate reasonable forecasting error in estimating overall electricity sales in the State. Any positive adjustment to the renewable energy portfolio standard shall be on a forward–looking basis and sufficiently in advance to allow an electric company to reflect OREC costs as a nonbypassable surcharge to distribution customers. The Commission shall adopt regulations that establish: the offshore wind purchase obligation sufficiently in advance to allow an electric company to reflect OREC costs as a nonbypassable surcharge paid by all distribution customers of the electric company; a mechanism to adjust the renewable energy portfolio standard obligation in a given year to accommodate a shortfall of ORECs in one or more earlier years that is the result of the variation between the quantity of ORECs calculated from the renewable energy portfolio standard obligation and the quantity of ORECs approved in the Commission order for the same years; and a nonbypassable surcharge that allows an electric company to recover all costs associated with the purchase of ORECs from all distribution customers of the electric company. The Commission shall adopt regulations establishing an escrow account under Commission supervision and defining rules that facilitate and ensure the secure and transparent transfer of revenues and ORECs among the parties. Each electric company shall purchase from the escrow account established under this section the number of ORECs required to satisfy the offshore wind energy component of the renewable energy portfolio standard under § 7–703(b)(12) through (25) of this subtitle. Subject to any escrow account reserve requirement the Commission establishes, if there are insufficient ORECs available to satisfy the electric companies’ OREC obligation, the overpayment shall be distributed to electric companies to be refunded or credited to each distribution customer based on the customer’s consumption of electricity supply that is subject to the renewable energy portfolio standard. Subject to any escrow account reserve requirement the Commission establishes, the calculation of an electric company’s OREC purchase obligation shall be based on final electricity sales data as reported by the PJM Interconnection as measured at the customer meter. For each OREC for which a qualified offshore wind project receives payment, a qualified offshore wind project shall: sell all energy, capacity, and ancillary services associated with the creation of ORECs into the markets operated by PJM Interconnection; and distribute the proceeds received from the sales to PJM Interconnection markets, under item (i) of this paragraph to electric companies to be refunded or credited to each distribution customer based on the customer’s consumption of electricity supply that is subject to the renewable energy portfolio standard. Notwithstanding § 7–709 of this subtitle, the Commission shall adopt regulations regarding the transfer and expiration of ORECs created by a qualified offshore wind project in excess of the OREC pricing schedule. If, within 2 years before the expiration of an OREC term, a qualified offshore wind project is anticipated to receive PJM revenues greater than the project operating costs for the 5 years immediately following the expiration of the term of the OREC pricing schedule, the Commission may extend the term of the OREC pricing schedule for an additional 5 years at an OREC price that equals one–half of the sum of: anticipated market revenues generated by the project during the additional 5–year period; and anticipated project operating costs during the additional 5–year period. If, within 2 years before the expiration of an additional 5–year term extended under paragraph (1) of this subsection, a qualified offshore wind project is anticipated to receive PJM revenues greater than the project operating costs for the 5 years immediately following the expiration of the additional 5–year term, the Commission may extend the term of the OREC pricing schedule for an additional 5 years at an OREC price that equals one–half of the sum of: anticipated market revenues generated by the project during the additional 5–year period; and anticipated project operating costs during the additional 5–year period. Except as provided in paragraphs (1) and (2) of this subsection, an OREC transaction that takes place during an additional 5–year term is subject to the provisions and regulations applicable to the original OREC order. A debt, obligation, or liability of a qualified offshore wind project, or an owner or operator of a qualified offshore wind project, may not be considered a debt, obligation, or liability of the State. On or before July 1, 2014, the Commission shall adopt regulations to carry out this section and § 7–704.1 of this subtitle.

The General Assembly finds and declares that it is in the public interest to upgrade and expand the transmission system to accommodate the buildout of at least 8,500 megawatts of offshore wind energy from qualified offshore wind projects serving the State by 2031. To meet the goals established under § 7–703 of this subtitle and subsection (a) of this section, the Commission, in consultation with the Maryland Energy Administration, shall request that PJM Interconnection conduct an analysis of transmission system upgrade and expansion options that take into consideration both onshore and offshore infrastructure. The Commission: shall consult with other states served by PJM Interconnection to evaluate regional transmission cooperation that could help achieve the State’s renewable energy and offshore wind energy goals with greater efficiency; shall work with PJM Interconnection to ensure that the analysis requested under paragraph (1) of this subsection includes an analysis of solutions that: use an open–access collector transmission system to allow for the interconnection of multiple qualified offshore wind projects at a single substation; avoid a significant outage, or single contingency, of any part of the transmission system; reduce permitting risks, impacts on communities, and unnecessary high costs; leverage existing infrastructure; offer benefits that address additional grid challenges; and address any other issues that the Commission identifies; and may consult with owners of transmission facilities in the State to gather relevant technical information. The Commission may enter into any necessary agreements with PJM Interconnection for transmission planning to: initiate PJM Interconnection’s analysis; or assist with the solicitation of proposals for offshore wind transmission projects. On or before July 1, 2024, the Commission shall submit a status update on the analysis requested under paragraph (1) of this subsection to the General Assembly, in accordance with § 2–1257 of the State Government Article. On or before July 1, 2025, the Commission shall issue, or request that PJM Interconnection issue, one or more competitive solicitations for proposals for open access offshore wind transmission facilities and complementary onshore transmission upgrades and expansions. The Commission may issue, or request that PJM Interconnection issue, further solicitations for proposals after this date if determined necessary by the Commission. In developing criteria for selecting a proposal under this section, the Commission: shall consider the analysis required under subsection (b) of this section, including a consideration of potential interconnection points; shall evaluate the potential for cooperating with other states in the PJM region to maximize consumer benefits that will best achieve the State’s renewable energy and offshore wind energy goals; and may consult with the Administration, electric companies, transmission facility owners, and other states or entities designated by those states in developing or coordinating equivalent standards for the approval of transmission projects under this section that will facilitate the integration of multiple offshore wind energy projects and potential multistate offshore wind transmission projects. The Commission shall include, or work with PJM Interconnection to include, specifications in the solicitation that require proposals to: allow future transmission lines to connect in a meshed manner and share landing points; consider other onshore and offshore clean energy generation and storage facilities; incorporate community benefit agreements in accordance with § 7–704.1 of this subtitle; address the siting, environmental, and socioeconomic information required to be considered by the Commission under § 7–207 of this title for an application for a certificate of public convenience and necessity, including opportunities for public engagement and comment with units of State and local government and the general public; demonstrate net benefits to ratepayers in the State when compared with an alternative baseline scenario under which 8,500 megawatts of offshore wind energy capacity is connected to PJM Interconnection independent of an offshore wind transmission project to achieve the goal established under § 7–704.1(a)(1)(i) of this subtitle; and ensure a competitive bidding process by redacting proprietary information provided to the Commission or to PJM Interconnection. The Commission may evaluate, or request that PJM Interconnection assist with the evaluation of, proposals that include: upgrading the existing transmission grid; extending the existing transmission grid onshore and offshore to be closer to offshore wind energy locations; interconnecting between offshore substations; adding energy storage; and the use of HVDC converter technology to support potential weaknesses in the transmission grid. The Commission may select a proposal or proposals that include: federal funding in the form of a match, grant, loan, or ownership and operation by the United States government; cost sharing among states or recovery of transmission costs through federal transmission rates, consistent with the policies and tariffs of the Federal Energy Regulatory Commission; a combination of the funding methods outlined in items (i) and (ii) of this paragraph; or any other available funding mechanisms. Each proposal should maximize access to and be consistent with the terms of the U.S. Department of Energy funding programs, including those established: under the federal Infrastructure Investment and Jobs Act; under the federal Inflation Reduction Act of 2022; through the U.S. Department of Energy Transmission Facilitation Program; and through any loan programs, office programs, or resiliency funding. The solicitation process shall: include a prequalification process to ensure the financial and technical competence and capabilities of the entities responding to the solicitation for proposals; provide for rigorous separation between individuals or firms participating in the review, analysis, and selection of the proposals by or on behalf of the Commission and those participating in the development or management of proposals; and promote rigorous competition among prequalified entities in the preparation and submission of their proposals. The Commission may modify, or request that PJM Interconnection modify, a solicitation for proposals at any time in order to satisfy eligibility criteria for U.S. Department of Energy funding programs. In selecting a proposal under this section, the Commission shall take into consideration the total amount of new transmission infrastructure needed to: maintain electric system reliability; achieve the State’s offshore wind, renewable energy, and decarbonization goals; obtain demonstrable benefits to the consumer and environment; and foster economic development and job creation in the State. The Commission shall: request that PJM Interconnection assist with the evaluation of each proposal submitted in accordance with this section; and after notice, one or more hearings to receive public comment, and an evidentiary hearing, and subject to subsection (j) of this section, on or before December 1, 2027, by order, select a proposal or proposals for development: using a funding mechanism or combination of funding mechanisms identified in subsection (e)(3) of this section; and that demonstrate net benefits to ratepayers in the State when compared with an alternative baseline scenario under subsection (e)(1)(v) of this section. If the Commission finds that none of the proposals adequately support the goals established under this section or demonstrate net benefits to ratepayers in the State when compared with an alternative baseline scenario under subsection (e)(1)(v) of this section, then the Commission may end the solicitation process without selecting a proposal. The Commission may, for a proposal selected under subsection (i) of this section: adopt conditions for the construction and operation of facilities included in the proposal; and consider any conditions proposed by the Power Plant Research Program. The requirement to obtain a certificate of public convenience and necessity under § 7–207 or § 7–208 of this title does not apply to a proposal selected under subsection (i) of this section. An order selecting a proposal under subsection (i) of this section constitutes authorization by the Commission to construct and operate facilities that would otherwise require a certificate of public convenience and necessity under § 7–207 or § 7–208 of this title. Except as provided in subsection (k) of this section, a proposal selected under this section is subject to all other relevant requirements for the siting and construction of transmission lines. Selection of coordinated transmission proposals may not impact the interconnection plans of earlier offshore wind projects, including OCS–A 0490 (US Wind) and OCS–A 0519 (Skipjack), unless the leaseholders for these projects opt to participate in the proposal by notifying the Commission by mail or e–mail before the completion of the analysis of transmission system expansion options under subsection (b) of this section. If no proposal has been selected under this section by December 1, 2027, the Commission shall submit a statement of determination to the Governor and General Assembly that: provides a comprehensive explanation of the Commission’s determination; and recommends a path forward to achieve the State’s goal under subsection (a) of this section. After the Commission selects a proposal or proposals, the Commission shall work with the Maryland Energy Administration, transmission developer or developers, transmission facility owners, PJM Interconnection, the Federal Energy Regulatory Commission, and any other states that voluntarily participate, to facilitate the development of the proposal or proposals and the construction of the proposed offshore wind project or projects. The Commission: shall carry out the provisions of this section by obtaining information through request, cooperation, subpoena, or any other legal method from transmission owners, PJM Interconnection, or any other entity; and may retain consultants.

In this section the following words have the meanings indicated. “Community benefit agreement” has the meaning stated in § 7–704.1(e) of this subtitle. “Social cost of greenhouse gases” means the most recent social cost of greenhouse gases adopted by the U.S. Environmental Protection Agency. The Department of General Services, in consultation with the Public Service Commission, shall issue a competitive sealed procurement solicitation and may enter into at least one contract for a power purchase agreement to procure offshore wind energy and associated renewable energy credits from one or more qualified offshore wind projects. Each agreement entered into under paragraph (1) of this subsection shall have a term of not less than 20 years. When issuing the invitation for bids under this subsection, the Department shall take into consideration: the social cost of greenhouse gas emissions; the State’s climate commitments; and the State’s commitments under § 7–704.1(a) of this subtitle. The evaluation criteria for bids shall include: comparing the social cost of greenhouse gas emissions for offshore wind with the social cost of greenhouse gas emissions for nonrenewable power purchased from wholesale electric markets administered by PJM Interconnection; and the extent to which an applicant’s proposal provides for financial and technical assistance to support monitoring and mitigation of wildlife and habitat impacts associated with the proposed offshore wind project. Each agreement entered into under paragraph (1) of this subsection shall include: a community benefit agreement and domestic content preferences; and a description of: initial plans for mitigating the impacts of the construction and operation of the proposed offshore wind project on fisheries and the environment; and the extent to which an applicant will provide for financial and technical assistance to support the monitoring and mitigation of wildlife and habitat impacts associated with the project. The Department of General Services shall identify the amount of energy necessary to meet the State’s energy needs. The State shall use the energy procured under subsection (b) of this section to meet the State’s energy needs and retire the associated renewable energy credits to meet its obligations under the renewable energy portfolio standard and Chapter 38 of the Acts of the General Assembly of 2022. The State shall be exempted from the renewable energy portfolio standard requirements under § 7–703 of this subtitle if the Department of General Services procures 100% of the State’s energy needs from the power purchase agreement required under subsection (b) of this section. The State shall offer for sale any energy or renewable energy credits remaining after the requirements under paragraph (2) of this subsection have been met on the competitive wholesale power market operated by PJM Interconnection, through bilateral sales to credit–worthy counterparties, or into renewable energy credit markets. The State shall: issue a draft solicitation for procurement of offshore wind energy for public comment and review on or before June 1, 2024; issue a procurement for offshore wind energy on or before July 31, 2024; provide a procurement submission process window of not less than 180 days; and award contracts in a timely manner. Subject to subparagraph (ii) of this paragraph, on or before September 1, 2025, the State may enter into a contract or contracts for the procurement issued under paragraph (1) of this subsection. The State may modify the date established in subparagraph (i) of this paragraph if an unforeseen circumstance adversely affects the procurement submission process. In addition to the solicitation and procurement issued under subsection (d) of this section, the State: shall issue a draft solicitation for procurement of offshore wind energy for public comment and review on or before September 1, 2025; and shall issue a procurement for offshore wind energy on or before December 31, 2025. Subject to paragraph (3) of this subsection and in addition to any contract entered into under subsection (d) of this section, on or before March 31, 2027, the State may enter into a contract or contracts for the procurement issued under paragraph (1) of this subsection. The State may modify the date established in paragraph (2) of this subsection if an unforeseen circumstance adversely affects the procurement submission process. The State shall incorporate in the offshore wind energy procurement contract terms to facilitate low–cost project development and traditional project financing terms, including: terms that waive the automatic termination clause required under § 13–217 of the State Finance and Procurement Article; terms that establish remedies to reimburse costs incurred by the contractor directly attributable to the failure of the State to appropriate funds for the contract; and any other appropriate mechanisms to ensure that offshore wind energy projects that meet the terms of the contract will have certainty of payment through the duration of the contract. Within 90 days after the operational commencement date of the power purchase agreement, any contractor providing operations and maintenance services under an agreement with the Department of General Services shall submit to the Department attestation that the contractor has entered into a labor peace agreement with each labor organization that is actively engaged in representing or attempting to represent employees performing operations and maintenance work on the projects that: prohibits strikes, lockouts, or any other economic interference with the contracted project; describes the class or classes of covered employees to whom the labor peace agreement applies; describes any class or classes of employees not currently represented by a labor organization; describes the classes of covered employees for which labor peace agreement negotiations have not yet concluded; and for classes of employees that are not covered by a labor peace agreement, provides an attestation that no labor organization has sought to negotiate such an agreement. A labor peace agreement required under paragraph (1) of this subsection shall be: valid and enforceable under 29 U.S.C. § 158; and maintained as an ongoing material condition of any continuation of payments under any agreement required by this subsection. Nothing in this section may be construed to prevent the procurement of new offshore wind energy generation in accordance with the current or any future solicitation schedule.

On or before December 31, 2024, and on or before each December 31 thereafter, the Commission shall submit a report to the General Assembly, in accordance with § 2–1257 of the State Government Article, on the information collected under the Commission’s Supplier Diversity Program regarding offshore wind developers. The report required under subsection (a) of this section shall include: efforts to promote opportunities for small, minority, women–owned, and veteran–owned businesses; information on participating offshore wind developers; participation of small, minority, women–owned, and veteran–owned businesses in offshore wind projects, including: the number of small, minority, women–owned, and veteran–owned businesses that receive contracts or subcontracts for offshore wind projects; and the percentage of contractors and subcontractors on offshore wind projects that are small, minority, women–owned, or veteran–owned businesses; and plans to increase future participation of small, minority, women–owned, and veteran–owned businesses in offshore wind projects.

Except as provided in paragraph (2) of this subsection, each electricity supplier shall submit a report to the Commission each year in a form and by a date specified by the Commission that: demonstrates that the electricity supplier has complied with the applicable renewable energy portfolio standard under § 7–703 of this subtitle and includes the submission of the required amount of renewable energy credits; or demonstrates the amount of electricity sales by which the electricity supplier failed to meet the applicable renewable energy portfolio standard; documents the level of participation of minority business enterprises and minorities in the activities that support the creation of renewable energy credits used to satisfy the standard under § 7–703 of this subtitle, including development, installation, and operation of generating facilities that create credits; documents the amounts and types of generation associated with renewable energy credits purchased in compliance with § 7–707(c) of this subtitle during the reporting period; and documents the amount of renewable energy certificates that do not qualify as renewable energy credits as defined in § 7–701 of this subtitle, including, for each certificate: the energy source associated with the certificate, including its location, when it was constructed, and which electric distribution system received the energy; whether the purchase of the certificate was bundled with a power purchase agreement from the energy source associated with the certificate; whether the certificate was purchased directly from the operator of the energy source or through a third party; and any other information required by the Commission. Paragraph (1)(iii) and (iv) of this subsection does not apply to: the Department of General Services’ sale of energy under § 7–704.4 of this subtitle; or a community choice aggregator under § 7–510.3 of this title. This subsection does not apply to a shortfall from the required Tier 1 renewable sources that is to be derived from post–2022 geothermal systems. If an electricity supplier fails to comply with the renewable energy portfolio standard for the applicable year, the electricity supplier shall pay into the Maryland Strategic Energy Investment Fund established under § 9–20B–05 of the State Government Article: except as provided in item (ii) of this paragraph, a compliance fee of: the following amounts for each kilowatt–hour of shortfall from required Tier 1 renewable sources other than the shortfall from the required Tier 1 renewable sources that is to be derived from solar energy: 4 cents through 2016; 75 cents in 2017 and 2018; 3 cents in 2019 through 2023; 75 cents in 2024; 5 cents in 2025; 475 cents in 2026; 45 cents in 2027; 25 cents in 2028 and 2029; and 235 cents in 2030 and later; the following amounts for each kilowatt–hour of shortfall from required Tier 1 renewable sources that is to be derived from solar energy: 45 cents in 2008; 40 cents in 2009 through 2014; 35 cents in 2015 and 2016; 5 cents in 2017; 5 cents in 2018; 10 cents in 2019; 10 cents in 2020; 8 cents in 2021; 6 cents in 2022; 6 cents in 2023; 6 cents in 2024; 5 cents in 2025; 5 cents in 2026; 5 cents in 2027; 25 cents in 2028; 5 cents in 2029; and 25 cents in 2030 and later; and 5 cents for each kilowatt–hour of shortfall from required Tier 2 renewable sources; or for industrial process load: for each kilowatt–hour of shortfall from required Tier 1 renewable sources, a compliance fee of: 8 cents in 2006, 2007, and 2008; 5 cents in 2009 and 2010; 4 cents in 2011 and 2012; 3 cents in 2013 and 2014; 25 cents in 2015 and 2016; and except as provided in paragraph (3) of this subsection, 0.2 cents in 2017 and later; and nothing for any shortfall from required Tier 2 renewable sources. For industrial process load, the compliance fee for each kilowatt–hour of shortfall from required Tier 1 renewable sources is nothing for the year following any year during which, after final calculations, the net rate impact per megawatt–hour from Round 1 offshore wind projects exceeded $1.65 in 2012 dollars. If an electricity supplier fails to comply with the renewable energy portfolio standard that is required to be derived from post–2022 geothermal systems for the applicable year, the electricity supplier shall pay into the Maryland Strategic Energy Investment Fund established under § 9–20B–05 of the State Government Article a compliance fee of the following amounts for each kilowatt–hour of shortfall from required post–2022 geothermal systems: 10 cents in 2023 through 2025; 9 cents in 2026; 8 cents in 2027; and 5 cents in 2028 and later. The Commission may allow an electricity supplier to submit the report required under § 7–505(b)(4) of this title to demonstrate compliance with the renewable energy portfolio standard. An aggregator or broker who assists an electricity customer in purchasing electricity but who does not supply the electricity or take title to or ownership of the electricity may require the electricity supplier who supplies the electricity to demonstrate compliance with this subtitle. Notwithstanding the requirements of § 7–703(b) of this subtitle, if the actual or projected dollar–for–dollar cost incurred or to be incurred by an electricity supplier solely for the purchase of Tier 1 renewable energy credits derived from solar energy in any 1 year is greater than or equal to, or is anticipated to be greater than or equal to, 6.0% of the electricity supplier’s total annual electricity sales revenues in Maryland, the electricity supplier may request that the Commission: delay by 1 year each of the scheduled percentages for solar energy under § 7–703(b) of this subtitle that would apply to the electricity supplier; and allow the renewable energy portfolio standard for solar energy for that year to continue to apply to the electricity supplier for the following year. In making its determination under paragraph (1) of this subsection, the Commission shall consider the actual or projected dollar–for–dollar compliance costs of other electricity suppliers. If an electricity supplier makes a request under paragraph (1) of this subsection based on projected costs, the electricity supplier shall provide verifiable evidence of the projections to the Commission at the time of the request. If the Commission allows a delay under paragraph (1) of this subsection: the renewable energy portfolio standard for solar energy applicable to the electricity supplier under the delay continues for each subsequent consecutive year that the actual or projected dollar–for–dollar costs incurred, or to be incurred, by the electricity supplier solely for the purchase of solar renewable energy credits is greater than or equal to, or is anticipated to be greater than or equal to, 6.0% of the electricity supplier’s total annual retail electricity sales revenues in Maryland; and the renewable energy portfolio standard for solar energy applicable to the electricity supplier under the delay is increased to the next scheduled percentage increase under § 7–703(b) of this subtitle for each year in which the actual or projected dollar–for–dollar costs incurred, or to be incurred, by the electricity supplier solely for the purchase of solar renewable energy credits is less than, or is anticipated to be less than, 6.0% of the electricity supplier’s total annual retail electricity sales revenues in Maryland.

Except as provided in paragraph (2) of this subsection, in accordance with the obligation to provide standard offer service through the bid process created under § 7–510 of this title, the Commission shall allow an electricity supplier to recover actual dollar–for–dollar costs incurred, including a compliance fee under § 7–705 of this subtitle, in complying with a State–mandated renewable energy portfolio standard. In accordance with the Phase II settlement agreement approved by the Commission in Order No. 78710 in Case No. 8908 on September 30, 2003, for any full–service agreement executed before the renewable energy standard under this subtitle applies to an electric company, the electric company and its wholesale electricity suppliers may pass through their commercially reasonable additional costs, if any, associated with complying with the standard, through the end of the year of standard offer service in which the requirement took effect. An electricity supplier may recover a compliance fee if: the payment of a compliance fee is the least–cost measure to customers as compared to the purchase of Tier 1 renewable sources to comply with a renewable energy portfolio standard; there are insufficient Tier 1 renewable sources available for the electricity supplier to comply with a renewable energy portfolio standard; or a wholesale electricity supplier defaults or otherwise fails to deliver renewable energy credits under a supply contract approved by the Commission. Any cost recovery under this section: for all electricity suppliers, may be in the form of a generation surcharge payable by all current electricity supply customers, except as otherwise provided in § 7–704(e) of this subtitle; shall be disclosed to customers in a manner to be determined by the Commission; and may not include the costs for a power purchase contract under the federal Public Utility Regulatory Policy Act contemplated in rates or restructuring proceedings. In accordance with regulations adopted by the Commission in consultation with the Department of Commerce, the Commission may waive the recovery of all or part of the compliance fee assessed on the load of a particular industrial or nonretail commercial customer for a particular year, based on a demonstration by the applicant of an extreme economic hardship that significantly impairs the continued operation of the applicant. Any compliance fee recovery that is waived under this subsection may not be assessed against other customers. An electricity supplier is not liable for any compliance fee that is waived under this subsection.

In this section, “green power” means energy sources or renewable energy credits that are marketed as clean, green, eco–friendly, environmentally friendly or responsible, carbon–free, renewable, 100% renewable, 100% wind, 100% hydro, 100% solar, 100% emission–free, or similar claims. This section does not apply to: the Department of General Services when the Department of General Services sells energy under § 7–704.4 of this subtitle; a community choice aggregator under § 7–510.3 of this title; or an electricity supplier when supplying electricity to commercial retail electric customers. An electricity supplier that supplies electricity to residential retail electric customers may not market electricity as green power unless: the percentage of the electricity being offered, or the equivalent number of renewable energy credits associated with the electricity being marketed as green power, that is eligible for inclusion in meeting the renewable energy portfolio standard equals or exceeds the greater of: 51%; or 1% higher than the renewable energy portfolio standard for the year the electricity is provided to the customer; the Commission approves the price of the electricity being marketed as green power in accordance with subsection (d) of this section; and the electricity supplier submits an application to the Commission that: describes the electricity being marketed as green power, including the green power source and percentage of the electricity that is green power; describes how the green power complies with State law and regulations; and includes any other information the Commission considers necessary. The price approved by the Commission under subsection (c)(2) of this section shall be determined through: a proceeding held in accordance with paragraph (2) of this subsection; or a proceeding held in accordance with paragraph (3) of this subsection. Each year the Commission shall hold a proceeding to set a price per megawatt–hour for electricity marketed as green power under this section that may not be exceeded by an electricity supplier except as provided in paragraph (3) of this subsection. Subject to paragraph (4) of this subsection, the price set by the Commission under subparagraph (i) of this paragraph may: exceed the maximum price per megawatt–hour that is authorized under § 7–510(d)(2)(i) of this title; and differ based on the amount and source of the electricity generation. During a proceeding held under subparagraph (i) of this paragraph, the Commission: shall consider: the price of the energy purchased, including the total cost of the renewable energy credits; the amount of electricity that is eligible for inclusion in meeting the renewable energy portfolio standard; the state in which the electricity was generated; and applicable market data; and may consider whether the purchase of renewable energy credits was bundled with a power purchase agreement from the energy sources associated with the credit. On request by an electricity supplier, the Commission shall hold a proceeding to set a price per megawatt–hour for electricity marketed as green power for that electricity supplier. Subject to paragraph (4) of this subsection, at a proceeding held under this paragraph the Commission may set a price per megawatt–hour that is higher than the price determined in the proceeding held under paragraph (2) of this subsection for an electricity supplier if: the electricity supplier demonstrates to the Commission’s satisfaction, based on an independent third–party audit, that the actual cost to the electricity supplier for the generation or supply of electricity exceeds that of the price determined through the proceeding held in accordance with paragraph (2) of this subsection; the increased price reflects only the cost of the electricity marketed as green power and is not associated with any of the electricity supplier’s other costs; and the electricity supplier demonstrates to the Commission’s satisfaction that the electricity supplier has a significant long–term investment in renewable energy that meets the renewable energy portfolio standard under § 7–703 of this subtitle. During a proceeding held under this paragraph, the Commission shall consider: whether the purchase of renewable energy credits was bundled with a power purchase agreement from the energy sources associated with the credit; the price of the energy purchased, including the total cost of the renewable energy credits or power purchase agreements; the amount of electricity that is eligible for inclusion in meeting the renewable energy portfolio standard; the state in which the electricity was generated; and applicable market data. A price approved by the Commission under this subsection may not exceed 150% of the maximum price per megawatt–hour that is authorized under § 7–510(d)(2)(i) of this title unless the Commission determines that the actual cost of the green power exceeds that amount. Within 120 days after approving a price for green power that exceeds 150% of the maximum price per megawatt–hour that is authorized under § 7–510(d)(2)(i) of this title, and annually for as long as the price exceeds that amount, the Commission shall submit a report to the General Assembly, in accordance with § 2–1257 of the State Government Article, that: demonstrates that the approved price represents only the actual price of the green power; and includes the Commission’s order authorizing the price of the green power. If the Commission has approved for 3 consecutive years a price for green power that exceeds 150% of the maximum price per megawatt–hour that is authorized under § 7–510(d)(2)(i) of this title, the Commission shall include in the annual report required under subparagraph (ii) of this paragraph: information on market conditions that necessitate the approved price of the green power that exceeds 150% of the maximum price per megawatt–hour that is authorized under § 7–510(d)(2)(i) of this title; and a recommendation of whether to increase the limitation on the maximum price of green power above which the Commission is required to make a determination under this paragraph. The Commission: shall annually review a price approved under paragraph (3) of this subsection; and may, on its own initiative, or on petition by the Office of People’s Counsel, require an electricity supplier offering green power under a price established under paragraph (3) of this subsection to demonstrate that the price continues to meet the requirements of paragraph (3) of this subsection. On and after January 1, 2025, an electricity supplier shall purchase renewable energy credits for each year the electricity supplier offers green power for sale to residential retail electric customers. A renewable energy credit an electricity supplier purchases under paragraph (1) of this subsection shall be retired in a PJM Environmental Information Services, Inc., generation attribute tracking system reserve subaccount accessible by the Commission. This subsection does not apply to: the Department of General Services when the Department of General Services sells energy under § 7–704.4 of this subtitle; or a community choice aggregator under § 7–510.3 of this title. An electricity supplier that claims in the electricity supplier’s marketing of electricity to residential retail electric customers that the customer will be purchasing green power shall include the following disclosure or a similar disclosure approved by the Commission: “We deliver energy through the purchase of Renewable Energy Credits (RECs). A REC represents the social good that accompanies 1 megawatt–hour of renewable electricity generation. RECs may be sold separately from renewable electricity itself. Renewable electricity and RECs may be sold to different entities. The purchase of a REC does not indicate that renewable electricity itself has been purchased by the entity that purchased the REC.”. In addition to the disclosure required under subsection (f) of this section, the Commission shall adopt regulations that require an electricity supplier, other than the Department of General Services when the Department of General Services sells energy under § 7–704.4 of this subtitle or a community choice aggregator under § 7–510.3 of this title, that offers green power for sale to residential retail customers to include in the electricity supplier’s marketing materials a disclosure, written in plain language, that explains: what the customer will actually be paying for when the customer purchases green power from the electricity supplier; how the electricity that the customer has purchased is generated; how the green power will benefit the environment; the percentage of electricity that would be provided by the electricity supplier that is eligible for inclusion in meeting the renewable energy portfolio standard; and the state in which the electricity was generated. The Commission, in its discretion, may determine whether an electricity supplier is marketing electricity in accordance with this section.

The Commission shall establish and maintain a market-based renewable electricity trading system to facilitate the creation and transfer of renewable energy credits. To the extent practicable, the trading system shall be consistent with and operate in conjunction with the trading system developed by PJM Interconnection, Inc., if available. The Commission may contract with a for-profit or a nonprofit entity to assist in the administration of the electricity trading system required under paragraph (1) of this subsection. The system shall include a registry of pertinent information regarding all: available renewable energy credits; and renewable energy credit transactions among electricity suppliers in the State, including: the creation and application of renewable energy credits; the number of renewable energy credits sold or transferred; and the price paid for the sale or transfer of renewable energy credits. The registry shall provide current information to electricity suppliers and the public on the status of renewable energy credits created, sold, or transferred in the State. Registry information shall be available by computer network access through the Internet.

An electricity supplier may use accumulated renewable energy credits to meet the renewable energy portfolio standard, including credits created by a renewable on–site generator. A renewable energy credit may be sold or otherwise transferred. If an electricity supplier purchases solar renewable energy credits directly from a renewable on–site generator with a capacity that exceeds 10 kilowatts to meet the solar component of the Tier 1 renewable energy portfolio standard, the duration of the contract term for the solar renewable energy credits may not be less than 15 years. The minimum required term under subparagraph (i) of this paragraph does not affect the ability of the parties to negotiate a price for a solar renewable energy credit that varies over time in any manner. An electricity supplier that purchases solar renewable energy credits from a renewable on–site generator with a capacity not exceeding 10 kilowatts shall purchase the credits with a single initial payment representing the full estimated production of the system for the life of the contract. The Commission shall: develop a method for estimating annual production from the type of system described in subparagraph (i) of this paragraph and allocating the credits to the electricity supplier in a manner that is consistent with the duration of the contract; and determine the rate for a payment made to a renewable on–site generator under subparagraph (i) of this paragraph. Except as authorized under paragraph (2) of this subsection, a renewable energy credit shall exist for 5 years from the date created. A renewable energy credit may be diminished or extinguished before the expiration of 5 years by: the electricity supplier that received the credit; a nonaffiliated entity of the electricity supplier: that purchased the credit from the electricity supplier receiving the credit; or to whom the electricity supplier otherwise transferred the credit; or demonstrated noncompliance by the generating facility with the requirements of § 7–704(f) of this subtitle. Notwithstanding subsection (d)(2)(iii) of this section, and only if the demonstrated noncompliance does not result in environmental degradation, an electricity supplier that reasonably includes in its annual report under § 7–705 of this subtitle a renewable energy credit that is extinguished for noncompliance with § 7–704(f)(1) or (2) of this subtitle: may continue to rely on that credit for that year; but for later years must: demonstrate a return to compliance of the generating facility under § 7–704(f) of this subtitle; or replace the credit with a renewable energy credit from another source. The Commission by regulation shall establish requirements for documentation and verification of renewable energy credits by licensed electricity suppliers and other generators that create and receive credits for compliance with the standards for Tier 1 renewable sources and Tier 2 renewable sources.

In this section the following words have the meanings indicated. “Brownfield” has the meaning stated in § 7–207 of this title. “Certified SREC” means a solar renewable energy credit generated by a certified system. “Certified system” means a solar energy generating system certified by the Commission under the Program to generate certified SRECs with the compliance value specified in subsection (c) of this section. “Program” means the Small Solar Energy Generating System Incentive Program. The Commission shall establish a Small Solar Energy Generating System Incentive Program. Under the Program, a certified system shall generate certified SRECs. Except as provided in paragraph (3) of this subsection, the provisions of this subtitle relating to renewable energy credits shall apply to certified SRECs. A certified SREC shall have a compliance value of 150% for electricity suppliers to put toward meeting the renewable energy portfolio standard for energy derived from solar energy under § 7–703 of this subtitle. To be eligible for certification under the Program, a solar energy generating system shall: be located in the State; be eligible for inclusion in meeting the renewable energy portfolio standard; have a generating capacity of 5 megawatts or less, as measured by the alternating current rating of the system’s inverter; be placed in service between July 1, 2024, and January 1, 2028, inclusive; and be one of the following types of systems: a system with a generating capacity of 20 kilowatts or less, as measured by the alternating current rating of the system’s inverter; a system with a generating capacity of 2 megawatts or less, as measured by the alternating current rating of the system’s inverter, if the system is used for aggregate net metering; or a system with a generating capacity of between 20 kilowatts and 5 megawatts, as measured by the alternating current rating of the system’s inverter, if the system is located on or over: a rooftop; a parking canopy; a brownfield; or a water retention pond or quarry currently or previously designated for industrial use. Except as provided in subsection (f) of this section, the Commission, at the time of certifying a solar energy generating system as a Tier 1 renewable source, shall certify the system as eligible to generate certified SRECs in accordance with subsection (c) of this section if the applicant submits with its application for certification as a Tier 1 renewable source: a form requesting to be certified to receive certified SRECs with the value specified in subsection (c) of this section; a copy of the interconnection agreement between the applicant and the applicant’s electric company indicating that the size of the system is eligible; if seeking certification as a system located on or over an area specified under subsection (d)(5)(iii) of this section, a copy of the final approval of the local building permit; if seeking certification as a system located on a brownfield, documentation demonstrating that the system is located on a brownfield; if seeking certification based on aggregated net metering, a copy of the aggregated net energy metering rider submitted with the interconnection agreement; and any other information required by the Commission. The owner of a solar energy generating system may apply to the Commission to be certified under the Program if the system meets the requirements under subsection (d) of this section. The owner of a solar energy generating system that is placed in service between July 1, 2024, and January 1, 2025, may apply to the Commission: before January 1, 2025, for certification as a Tier 1 renewable source; and on or after January 1, 2025, for certification under the Program. The total amount of in–State generating capacity for certified systems, as measured by the alternating current rating of the systems’ inverters, under the Program may not exceed: 300 megawatts for systems with a generating capacity of less than 20 kilowatts, as measured by the alternating current rating of the system’s inverter; and 270 megawatts for systems with a generating capacity of between 20 kilowatts and 5 megawatts, as measured by the alternating current rating of the system’s inverter. At the time a solar energy generating system is certified as a Tier 1 renewable source, the owner of the system shall pay to the Commission a one–time fee of: up to $50 for each system with a generating capacity of less than 20 kilowatts, as measured by the alternating current rating of the system’s inverter; and up to $200 for each system with a generating capacity of more than 20 kilowatts, as measured by the alternating current rating of the system’s inverter. The Commission shall use the fees collected under paragraph (1) of this subsection to pay for costs associated with administering the Program. A certified system shall continue to be eligible to generate certified SRECs for 15 years after the date of certification by the Commission, or January 1, 2025, whichever is later, after which the system shall be eligible to generate noncertified solar renewable energy credits as long as the system meets the requirements as a Tier 1 renewable source under this subtitle. The Commission shall: on or before January 1, 2025, begin determining eligibility of solar energy generating systems to be certified under the Program; and on or before July 1, 2026, implement a revised system to review and ensure compliance with the renewable energy portfolio standard. An electricity supplier may apply the certified SRECs generated in accordance with this section toward the renewable energy portfolio standard starting with the 2025 compliance year. Notwithstanding any other law, the Commission shall allow electricity suppliers to demonstrate compliance with the renewable energy portfolio standard for the 2025 compliance year by submitting information between July 1, 2026, and December 31, 2026, using the revised system developed in accordance with paragraph (2)(ii) of this subsection.

The Commission may impose an administrative fee on a renewable energy credit transaction, but the amount of the fee may not exceed the Commission’s actual direct cost of processing the transaction.

The Commission has the same power and authority with respect to an electricity supplier under this subtitle that the Commission has with respect to any public service company under this division for the purposes of investigating and examining the electricity supplier to determine compliance with this subtitle and with other applicable law. Beginning January 1, 2008, the Commission shall designate an individual to be responsible for the oversight of compliance with the requirements of Tier 1 renewable sources that are to be derived from solar energy. The individual designated under paragraph (1) of this subsection shall: develop the program for the requirements for Tier 1 renewable sources derived from solar energy; provide education and outreach to promote the use of solar energy; and make policy recommendations to the Commission regarding improving the State’s use of solar energy, including the development of clear, simple, and straightforward forms, requirements, and procedures to facilitate participation by homeowners and small businesses in deployment of solar generation in the State.

Subject to § 2–1257 of the State Government Article, on or before December 1 of each year the Commission shall report to the General Assembly on the status of implementation of this subtitle, including: the availability of Tier 1 renewable sources; projects supported by the Fund; information regarding the status of the Small Solar Energy Generating System Incentive Program established under § 7–709.1 of this subtitle, including the total amount of generating capacity of the systems certified under the Program; and other pertinent information.

The Commission shall adopt regulations to implement the provisions of this subtitle.

The developer of a solar energy generating system that has a generating capacity over 1 megawatt, as measured by the alternating current rating of the system’s inverter, 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.