AN ACT to authorize the Utilities Commission to (I) take all reasonable steps to achieve a seventy percent reduction in emissions of carbon dioxide from electric public utilities from 2005 levels by the year 2030 and carbon neutrality by the year 2050, (II) authorize performance‑based regulation of electric public utilities, (III) proceed with rulemaking on securitization of certain costs and other matters, and (iV) allow POTENTIAL MODIFICATION OF CERTAIN EXISTING POWER PURCHASE AGREEMENTS WITH eligible SMALL POWER PRODUCERS.

The General Assembly of North Carolina enacts:

PART I. Carbon Reduction/Fuel Transition/Decommissioning
SECTION 1.  The Utilities Commission shall take all reasonable steps to achieve a seventy percent (70%) reduction in emissions of carbon dioxide (CO2) emitted in the State from electric generating facilities owned or operated by electric public utilities from 2005 levels by the year 2030 and carbon neutrality by the year 2050. For purposes of this section, (i) "electric public utility" means any electric public utility as defined in G.S. 62‑3(23) serving at least 150,000 North Carolina retail jurisdictional customers as of January 1, 2021, and (ii) "carbon neutrality" means for every ton of CO2 emitted in the State from electric generating facilities owned or operated by or on behalf of electric public utilities, an equivalent amount of CO2 is reduced, removed, prevented, or offset, provided that the offsets are verifiable and do not exceed five percent (5%) of the authorized reduction goal. In achieving the authorized carbon reduction goals, the Utilities Commission shall:
(1)	Develop a plan, no later than December 31, 2022, with the electric public utilities, including stakeholder input, for the utilities to achieve the authorized reduction goals, which may, at a minimum, consider power generation, transmission and distribution, grid modernization, storage, energy efficiency measures, demand‑side management, and the latest technological breakthroughs to achieve the least cost path consistent with this section to achieve compliance with the authorized carbon reduction goals (the "Carbon Plan"). The Carbon Plan shall be reviewed every two years and may be adjusted as necessary in the determination of the Commission and the electric public utilities.
(2)	Comply with current law and practice with respect to the least cost planning for generation, pursuant to G.S. 62‑2(a)(3a), in achieving the authorized carbon reduction goals and determining generation and resource mix for the future. Any new generation facilities or other resources selected by the Commission in order to achieve the authorized reduction goals for electric public utilities shall be owned and recovered on a cost of service basis by the applicable electric public utility except that:
a.	Existing law shall apply with respect to energy efficiency measures and demand‑side management.
b.	To the extent that new solar generation is selected by the Commission, in adherence with least cost requirements, the solar generation selected shall be subject to the following: (i) forty‑five percent (45%) of the total megawatts alternating current (MW AC) of any solar energy facilities established pursuant to this section shall be supplied through the execution of power purchase agreements with third parties pursuant to which the electric public utility purchases solar energy, capacity, and environmental and renewable attributes from solar energy facilities owned and operated by third parties that are 80 MW AC or less that commit to allow the procuring electric public utility rights to dispatch, operate, and control the solicited solar energy facilities in the same manner as the utility's own generating resources and (ii) fifty‑five percent (55%) of the total MW AC of any solar energy facilities established pursuant to this section shall be supplied from solar energy facilities that are utility‑built or purchased by the utility from third parties and owned and operated and recovered on a cost of service basis by the soliciting electric public utility. These ownership requirements shall be applicable to solar energy facilities (i) paired with energy storage and (ii) procured in connection with any voluntary customer program.
(3)	Ensure any generation and resource changes maintain or improve upon the adequacy and reliability of the existing grid.
(4)	Retain discretion to determine optimal timing and generation and resource‑mix to achieve the least cost path to compliance with the authorized carbon reduction goals, including discretion in achieving the authorized carbon reduction goals by the dates specified in order to allow for implementation of solutions that would have a more significant and material impact on carbon reduction; provided, however, the Commission shall not exceed the dates specified to achieve the authorized carbon reduction goals by more than two years, except in the event the Commission authorizes construction of a nuclear facility or wind energy facility that would require additional time for completion due to technical, legal, logistical, or other factors beyond the control of the electric public utility, or in the event necessary to maintain the adequacy and reliability of the existing grid. In making such determinations, the Utilities Commission shall receive and consider stakeholder input.
SECTION 2.(a)  G.S. 62‑110.8(a) reads as rewritten:
"§ 62‑110.8.  Competitive procurement of renewable energy.
(a)	Each electric public utility shall file for Commission approval a program for the competitive procurement of energy and capacity from renewable energy facilities with the purpose of adding renewable energy to the State's generation portfolio in a manner that allows the State's electric public utilities to continue to reliably and cost‑effectively serve customers' future energy needs. Renewable energy facilities eligible to participate in the competitive procurement shall include those facilities that use renewable energy resources identified in G.S. 62‑133.8(a)(8) but shall be limited to facilities with a nameplate capacity rating of 80 megawatts (MW) or less that are placed in service after the date of the electric public utility's initial competitive procurement. Subject to the limitations set forth in subsections (b) and (c) of this section, the electric public utilities shall issue requests for proposals to procure and shall procure, energy and capacity from renewable energy facilities in the aggregate amount of 2,660 megawatts (MW), and the total amount shall be reasonably allocated over a term of 45 months beginning when the Commission approves the program. The Commission shall require the additional competitive procurement of renewable energy capacity by the electric public utilities in an amount that includes all of the following: (i) any unawarded portion of the initial competitive procurement required by this subsection; (ii) any deficit in renewable energy capacity identified pursuant to subdivision (1) of subsection (b) of this section; and (iii) any capacity reallocated pursuant to G.S. 62‑159.2."
SECTION 2.(b)  G.S. 62‑110.8(h)(5) is repealed.
SECTION 2.(c)  The Commission is authorized to direct the procurement of solar energy facilities in 2022 by the electric public utilities if, after stakeholder participation and review of preliminary analysis developed in preparation of the initial Carbon Plan, the Commission finds that such solar energy facilities will be needed in accordance with the criteria and requirements set forth in Section 1 of this act to achieve the authorized carbon reduction goals.
SECTION 3.  No later than March 1, 2022, the Department of Environmental Quality shall develop a plan to ensure adequate financial resources for the decommissioning of utility‑scale solar projects to be submitted to the General Assembly for legislative action. For purposes of this section, "utility‑scale solar project" means a ground‑mounted photovoltaic (PV), concentrating photovoltaic (CPV), or concentrating solar power (CSP or solar thermal) project capable of generating 1 megawatt (MW) or more directly connected to the electrical grid for sale to wholesale customers. A utility‑scale solar project includes the solar arrays, accessory buildings, transmission facilities, and any other infrastructure necessary for the operation of the project.

PART II. AUTHORIZE PERFORMANCE‑BASED REGULATION OF ELECTRIC PUBLIC UTILITIES
SECTION 4.(a)  Article 7 of Chapter 62 of the General Statutes is amended by adding a new section to read:
"§ 62‑133.16.  Performance‑based regulation authorized.
(a)	Definitions. – For purposes of this section, the following definitions apply:
(1)	"Cost causation principle" means establishment of a causal link between a specific customer class, how that class uses the electric system, and costs incurred by the electric public utility for the provision of electric service.
(2)	"Decoupling rate‑making mechanism" means a rate‑making mechanism intended to break the link between an electric public utility's revenue and the level of consumption of electricity on a per customer basis by its residential customers.
(3)	"Distributed energy resource" or "DER" means a device or measure that produces electricity or reduces electricity consumption and is connected to the electric distribution system, either on the customer's premises or on the electric public utility's primary distribution system. A DER may include any of the following: energy efficiency, distributed generation, demand response, microgrids, energy storage, energy management systems, and electric vehicles.
(4)	"Earnings sharing mechanism" means an annual rate‑making mechanism that shares surplus earnings between the electric public utility and customers over the period of time covered by a MYRP.
(5)	"Multiyear rate plan" or "MYRP" means a rate‑making mechanism under which the Commission sets base rates for a multiyear period that includes authorized periodic changes in base rates without the need for the electric public utility to file a subsequent general rate application pursuant to G.S. 62‑133, along with an earnings sharing mechanism.
(6)	"Performance incentive mechanism" or "PIM" means a rate‑making mechanism that links electric public utility revenue or earnings to electric public utility performance in targeted areas consistent with policy goals, as that term is defined by this section, approved by the Commission, and includes specific performance metrics and targets against which electric public utility performance is measured.
(7)	"Performance‑based regulation" or "PBR" means an alternative rate‑making approach that includes decoupling, one or more performance incentive mechanisms, and a multiyear rate plan, including an earnings sharing mechanism, or such other alternative regulatory mechanisms as may be proposed by an electric public utility.
(8)	"Policy goal" means the expected or anticipated achievement of operational efficiency, cost‑savings, or reliability of electric service that is greater than that which already is required by State or federal law or regulation, including standards the Commission has established by order prior to and independent of a PBR application, provided that, with respect to environmental standards, the Commission may not approve a policy goal that is more stringent than is established by (i) State law, (ii) federal law, (iii) the Environmental Management Commission pursuant to G.S. 143B‑282, or (iv) the United States Environmental Protection Agency.
(9)	"Rate year" means the year of the MYRP for which base rates are effective.
(10)	"Tracking metric" means a methodology for tracking and quantitatively measuring and monitoring outcomes or electric public utility performance.
(b)	Performance‑Based Regulation Authorized. – In addition to the method for fixing base rates established under G.S. 62‑133, the Commission is authorized to approve performance‑based regulation upon application of an electric public utility pursuant to the process and requirements of this section, so long as the Commission allocates the electric public utility's total revenue requirement among customer classes based upon the cost causation principle, including the use of minimum system methodology by an electric public utility for the purpose of allocating distribution costs between customer classes, and interclass subsidization of ratepayers is minimized to the greatest extent practicable by the conclusion of the MYRP period. This section shall not be construed to require the Commission to use the minimum system methodology for the purpose of classifying costs within a customer class when setting a basic facilities charge.
(c)	Application. – An electric public utility shall be permitted to submit a PBR application in a general rate case proceeding initiated pursuant to G.S. 62‑133. A PBR application shall include a decoupling rate‑making mechanism, one or more PIMs, and a MYRP, including both an earnings sharing mechanism and proposed revenue requirements and base rates for each of the years that a MYRP is in effect or a method for calculating the same. The PBR application may also include proposed tracking metrics with or without targets or benchmarks to measure electric public utility achievement. The following additional requirements apply to a PBR application:
(1)	The following shall apply to a MYRP:
a.	The base rates for the first rate year of a MYRP shall be fixed in the manner prescribed under G.S. 62‑133, including actual changes in costs, revenues, or the cost of the electric public utility's property used and useful, or to be used and useful within a reasonable time after the test period, plus costs associated with a known and measurable set of capital investments, net of operating benefits, associated with a set of discrete and identifiable capital spending projects to be placed in service during the first rate year. Subsequent changes in base rates in the second and third rate years of the MYRP shall be based on projected incremental Commission‑authorized capital investments that will be used and useful during the rate year and associated expenses, net of operating benefits, including operation and maintenance savings, and depreciation of rate base associated with the capital investments, that are incurred or realized during each rate year of the MYRP period; provided that the amount of increase in the second rate year under the MYRP shall not exceed four percent (4%) of the electric public utility's North Carolina retail jurisdictional revenue requirement that is used to fix rates during the first year of the MYRP pursuant to G.S. 62‑133 excluding any revenue requirement for the capital spending projects to be placed in service during the first rate year. The amount of increase for the third rate year under the MYRP shall not exceed four percent (4%) of the electric public utility's North Carolina retail jurisdictional revenue requirement that is used to fix rates during the first year of the MYRP pursuant to G.S. 62‑133, excluding any revenue requirement for the capital spending projects placed in service during the first rate year. The revenue requirements associated with any single new generation plant placed in service during the MYRP for which the total plant in service balance exceeds five hundred million dollars ($500,000,000) shall not be included in a MYRP. Instead, the utility may request and the Commission may grant, if it deems appropriate, permission to establish a regulatory asset and defer to such regulatory asset incremental costs related to such electric generation investments to be considered for recovery in a future rate proceeding. In setting the electric public utility's authorized rate of return on equity for an MYRP period, the Commission shall consider any increased or decreased risk to either the electric public utility or its ratepayers that may result from having an approved MYRP.
b.	In a proceeding authorizing a MYRP, the Commission shall establish a rider to refund amounts related to the earnings sharing mechanism, and to refund or collect amounts related to PIM rewards or penalties, and decoupling adjustments.
c.	Within 60 days of the conclusion of each rate year, the Commission shall establish a proceeding to:
1.	Examine the earnings of the electric public utility during the rate year to determine if the earnings exceeded the authorized rate of return on equity determined by the Commission in the proceeding establishing the PBR. If the weather‑normalized earnings exceed the authorized rate of return on equity plus 50 basis points, the excess earnings above the authorized rate of return on equity plus 50 basis points shall be refunded to customers in the rider established by the Commission. If the weather‑normalized earnings fall below the authorized rate of return on equity, the electric public utility may file a rate case pursuant to G.S. 62‑133. Any penalties or rewards from PIM incentives and any incentives related to demand‑side management and energy efficiency measures pursuant to G.S. 62‑133.9(f) will be excluded from the determination of any refund pursuant to earnings sharing mechanism.
2.	Evaluate the performance of the electric public utility with respect to Commission approved PIMs applicable in the rate year. Any financial rewards shall be collected from customers and any penalties refunded to customers, in each case, through the rider established by the Commission.
3.	Evaluate the decoupling rate‑making mechanism, and refund or collect, as applicable, a corresponding amount from residential customers through the rider established by the Commission.
(2)	The proposed decoupling mechanism shall only be applied to residential customer classes. The Commission shall establish an annual revenue requirement per residential customer and an appropriate distribution of said revenue requirement per customer in each month of the year. The established monthly revenue requirements times the actual number of residential customers each month shall become the target revenue for the residential class. Each month, the electric public utility shall defer to a regulatory asset or liability account the difference between the actual revenue and the target revenue for the residential class. The changes in revenue requirements for the second and third rate years shall be allocated to the residential customer class and divided by the number of residential customers to determine the appropriate adjustment to the annual revenue requirement per residential customer that is used to establish the target revenues for the residential class in the second and third rate years of a MYRP. The electric public utility may exclude rate schedules or riders for electric vehicle charging, including EV charging during off‑peak periods on time‑of‑use rates, from the decoupling mechanism to preserve the electric public utility's incentive to encourage electric vehicle adoption.
(3)	The policy goal targeted by a PIM shall be clearly defined, measurable with a defined performance metric, and solely or primarily within the electric public utility's control.
(4)	Any PIM shall be structured to ensure that, pursuant to subdivisions (1) and (2) of this subsection, any penalty shall be refunded to customers and any reward shall be collected from customers and shall be limited such that the total of all potential and actual PIM incentives or penalties does not exceed one percent (1%) of the electric public utility's total annual revenue requirement that is used to fix rates during the first year of the MYRP pursuant to G.S. 62‑133, excluding any revenue requirement for the capital spending projects to be placed in service during the first rate year, where the PIM is approved. Any incentives related to demand‑side management and energy efficiency measures pursuant to G.S. 62‑133.9(f) shall be excluded from the limits established in this section and shall continue to be recovered through the demand‑side management and energy efficiency (DSM/EE) rider.
(5)	Subject to the limitations set out in subdivision (4) of this subsection, any PIMs proposed by an electric public utility shall include one or more of the following:
a.	Rewards based on the sharing of savings achieved by meeting or exceeding a specific policy goal.
b.	Rewards or penalties based on differentiated authorized rates of return on common equity to encourage utility investments or operational changes to meet a specific policy goal, which shall not be greater than 25 basis points.
c.	Fixed financial rewards to encourage achievement of specific policy goals, or fixed financial penalties for failure to achieve policy goals.
(d)	Commission Action on Application. –
(1)	The Commission shall approve a PBR application by an electric public utility only upon a finding that a proposed PBR would result in just and reasonable rates, is in the public interest, and is consistent with the criteria established in this section and rules adopted thereunder. In reviewing any such PBR application under this section, the Commission shall consider whether the PBR application:
a.	Assures that no customer or class of customers is unreasonably harmed and that the rates are fair both to the electric public utility and to the customer.
b.	Reasonably assures the continuation of safe and reliable electric service.
c.	Will not unreasonably prejudice any class of electric customers and result in sudden substantial rate increases or "rate shock" to customers.
(2)	In reviewing any such PBR application under this section, the Commission may consider whether the PBR application:
a.	Encourages peak load reduction or efficient use of the system.
b.	Encourages utility‑scale renewable energy and storage.
c.	Encourages DERs.
d.	Reduces low‑income energy burdens.
e.	Encourages energy efficiency.
f.	Encourages carbon reductions.
g.	Encourages beneficial electrification, including electric vehicles.
h.	Supports equity in contracting.
i.	Promotes resilience and security of the electric grid.
j.	Maintains adequate levels of reliability and customer service.
k.	Promotes rate designs that yield peak load reduction or beneficial load‑shaping.
(3)	When an electric public utility files with the Commission an application for a general rate case pursuant to G.S. 62‑133 and that application includes a PBR application, the Commission shall institute proceedings on the application as provided in this subdivision. The electric public utility shall not make any changes in any rate or implement a PBR except upon 30 days' notice to the Commission, and the Commission may require the electric public utility to provide notice of the pending PBR application to the same extent as provided in G.S. 62‑134(a) and may suspend the effect of the proposed base rates and PBR implementation pending investigation in the same manner as provided in G.S. 62‑134(b), provided that, the Commission may suspend the implementation of the proposed base rates for no longer than 300 days. The electric public utility's application shall plainly state the changes in base rates and the time when the change in rates will go into effect and shall include schedules in the same manner required pursuant to G.S. 62‑134(a). The Commission shall, upon reasonable notice, conduct a hearing concerning the lawfulness of the proposed base rates and the PBR application. After hearing, the Commission shall issue an order approving, modifying, or rejecting the electric public utility's PBR application. In the event that the Commission rejects a PBR application, the Commission shall nevertheless establish the electric public utility's base rates in accordance with G.S. 62‑133 based on the PBR application. If the Commission rejects the PBR application, it shall provide an explanation of the deficiency and an opportunity for the electric public utility to refile, or for the electric public utility and the stakeholders to collaborate to cure the identified deficiency and refile.
(e)	Commission Review. – At any time prior to expiration of a PBR plan period, the Commission, with good cause and upon its own motion or petition by the Public Staff, may examine the reasonableness of an electric public utility's rates under a plan, conduct periodic reviews with opportunities for public hearings and comments from interested parties, and initiate a proceeding to adjust base rates or PIMs as necessary. In addition, the approval of a PBR shall not be construed to limit the Commission's authority to grant additional deferrals between rate cases for extraordinary costs not otherwise recognized in rates.
(f)	Plan Period. – Any PBR application approved pursuant to this section shall remain in effect for a plan period of not more than 36 months.
(g)	Commission Authority Preserved. – Nothing in this section shall be construed to (i) limit or abrogate the existing rate‑making authority of the Commission or (ii) invalidate or void any rates approved by the Commission prior to the effective date of this section. In all respects, the alternative rate‑making mechanisms, designs, plans, or settlements shall operate independently, and be considered separately, from riders or other cost recovery mechanisms otherwise allowed by law, unless otherwise incorporated into such plan.
(h)	Utility Reporting. – For purposes of measuring an electric public utility's earnings under a PBR application approved under this section, an electric public utility shall make an annual filing that sets forth the electric public utility's earned return on equity, the electric public utility's revenue requirement trued‑up with the actual electric public utility revenue, the amount of revenue adjustment in terms of customer refund or surcharge, if applicable, and the adjustments reflecting rewards or penalties provided for in PIMs approved by the Commission.
(i)	Commission Report. – No later than April 1 of each year, the Commission shall submit a report on the activities taken by the Commission to implement, and by electric public utilities to comply with, the requirements of this section to the Governor, the Environmental Review Commission, the Joint Legislative Commission on Energy Policy, the Joint Legislative Oversight Committee on Agriculture and Natural and Economic Resources, the chairs of the Senate Appropriations Committee on Agriculture, Natural, and Economic Resources, the chairs of the House of Representatives Appropriations Committee on Agriculture and Natural and Economic Resources, and the chairs of the House Committee on Energy and Public Utilities. The report shall include a summary of public comments received by the Commission. In developing the report, the Commission shall consult with the Department of Environmental Quality.
(j)	Rulemaking. – The Commission shall adopt rules to implement the requirements of this section. Rules adopted shall include all of the following matters:
(1)	The specific procedures and requirements that an electric public utility shall meet when requesting approval of a PBR application.
(2)	The criteria for evaluating a PBR application.
(3)	The parameters for a technical conference process to be conducted by the Commission prior to submission of any PBR application consisting of one or more public meetings at which the electric public utility presents information regarding projected transmission and distribution expenditures and interested parties are permitted to provide comment and feedback; provided, however, no cross‑examination of parties shall be permitted. The technical conference process to be established shall not exceed a duration of 60 days from the date on which the electric public utility requests initiation of such process.
(4)	In the event the Commission rejects a PBR application, the process by which an electric public utility may address the Commission's reasons for rejection of a PBR application, which process may include collaboration between stakeholders and the electric public utility to cure any identified deficiency in an electric public utility's PBR application."
SECTION 4.(b)  The Commission shall adopt rules as required by G.S. 62‑133.16(j), as enacted by subsection (a) of this section, no later than 120 days after the date this section becomes law.
SECTION 4.(c)  This section is effective when it becomes law and applies to any rate‑making mechanisms filed by an electric public utility on or after the date that rules adopted pursuant to G.S. 62‑133.16, as enacted by subsection (a) of this section, become effective.

PART III. Rulemaking
SECTION 5.  The Utilities Commission is authorized to and shall within 180 days of the effective date of this section, with stakeholder input and participation, establish rules for securitization of costs associated with early retirement of subcritical coal‑fired electric generating facilities. With respect to securitization of costs associated with early retirement of subcritical coal‑fired electric generating facilities, the Commission shall develop rules to determine costs to be securitized at fifty percent (50%) of the remaining net book value of all subcritical coal‑fired electric generating facilities to be retired to achieve the authorized carbon reduction goals set forth in Section 1 of this act, with any remaining non‑securitized costs to be recovered through rates. Rules, procedures, obligations, and protections adopted for securitization of costs associated with retirement of subcritical coal‑fired generating facilities shall be substantively identical to the provisions of Section 1 of S.L. 2019‑244, except with respect to the purposes for which securitization may be used under that section. The Utilities Commission shall also (i) evaluate and modify as necessary existing standby service charges, (ii) revise net metering rates, (iii) establish an on‑utility‑bill repayment program related to energy efficiency investments, and (iv) establish a rider for a voluntary program that will allow industrial, commercial, and residential customers who elect to purchase from the electric public utility renewable energy or renewable energy credits, including in any program in which the identified resources are owned by the utility in accordance with sub‑subdivision b. of subdivision (2) of Section 1 of this act, to offset their energy consumption, which shall ensure that customers who voluntarily elect to purchase renewable energy or renewable energy credits through such programs bear the full direct and indirect cost of those purchases, and that customers that do not participate in such arrangements are held harmless, and neither advantaged nor disadvantaged, from the impacts of the renewable energy procured on behalf of the program customer, and no cross‑subsidization occurs.

PART iv. POTENTIAL MODIFICATION OF CERTAIN EXISTING POWER PURCHASE AGREEMENTS WITH eligible SMALL POWER PRODUCERS
SECTION 6.(a)  Within 120 days after the effective date of this section, the North Carolina Utilities Commission shall initiate a docket to establish the rates to be paid by the electric public utilities in connection with a one‑time option to modify certain existing power purchase agreements with eligible small power producers that would accomplish all of the following:
(1)	Provide eligible small power producers a one‑time option to elect, within 180 days of a Commission order authorizing such action, to amend their existing power purchase agreement, extending into a new longer term power purchase agreement for a term equal to the remaining term of the existing power purchase agreement plus an additional 10 years, notwithstanding the contract term limits prescribed in G.S. 62‑156(c).
(2)	Establish capacity and energy rates to be paid by the electric public utilities under such amended power purchase agreement that:
a.	Take into consideration (i) the currently contracted capacity and energy rates relative to the currently contracted term of the applicable power purchase agreement and (ii) capacity and energy rates at the time the eligible small power producer elects to exercise the option to amend their existing power purchase agreement as provided for in this section relative to the additional 10‑year term.
b.	Are just and reasonable to all classes of customers of the electric public utilities and in the public interest.
c.	Result in (i) an immediate reduction in the cost of electricity for all classes of customers of the electric public utilities and (ii) a reduction in the estimated long‑term cost of electricity for all classes of customers of the electric public utilities.
SECTION 6.(b)  For purposes of this section, the term "eligible small power producers" means small power producers, as that term is defined under G.S. 62‑3(27a), generating solar electricity with a total capacity equal to or less than 5 megawatts alternating current (MW AC) that established a legally enforceable obligation in accordance with the Commission's then applicable requirements on or before November 15, 2016, and have entered into a long‑term contract exceeding two years to sell their full output to the interconnected electric public utility under section 210 of the Public Utility Regulatory Policies Act of 1978.
SECTION 6.(c)  Notwithstanding the forgoing, it is hereby declared appropriate, in the public interest and in an effort to achieve regulatory economy, eligible small power producers and the electric public utilities are encouraged to negotiate amendments to the power purchase agreements of such eligible small power producers in lieu of the aforementioned proceeding, provided that the intent and objectives of this section are accomplished through such negotiation and electing eligible small power producers are treated in a nondiscriminatory manner.

PART v. SEVERABILITY CLAUSE AND EFFECTIVE DATE
SECTION 7.  If any provision of this act or the application thereof to any person or circumstances is held invalid, such invalidity shall not affect other provisions or applications of this act that can be given effect without the invalid provision or application, and, to this end, the provisions of this act are declared to be severable.
SECTION 8.  This act is effective when it becomes law.
In the General Assembly read three times and ratified this the 7th day of October, 2021.

	s/	 Phil Berger
	 President Pro Tempore of the Senate

	s/	 Tim Moore
	 Speaker of the House of Representatives

	s/	 Roy Cooper
	 Governor

Approved 12:22 p.m. this 13th day of October, 2021