Correction: Among the changes made by the Senate committee substitute to the 3rd edition, the act directs the North Carolina Utilities Commission to take reasonable steps to achieve a 70% reduction in emissions of carbon dioxide emitted in the state from electric generating facilities owned or operated by electric public utilities from 2005 levels (not 2015 levels as previously stated) by 2030, and to achieve carbon neutrality by 2050.
Summary date: Nov 18 2021 - More information
Summary date: Oct 14 2021 - More information
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. SL 2021-165. Enacted Oct. 13, 2021. Effective Oct. 13, 2021.
Summary date: Oct 5 2021 - More information
Senate committee substitute to the 3rd edition makes the following changes.
Deletes the content of the previous edition with the exception of Part II. of the act, which enacts GS 62-133.16, allowing the North Carolina Utilities Commission to approve performance-based regulation of electric public utilities upon application. Modifications to Part II. of the act are discussed below.
Includes the following new content.
Directs the North Carolina Utilities Commission (Commission) to take reasonable steps to achieve a 70% reduction in emissions of carbon dioxide emitted in the state from electric generating facilities owned or operated by electric public utilities from 2015 levels by 2030, and to achieve carbon neutrality by 2050. Defines electric public utility and carbon neutrality. Directs the Commission to develop a Carbon Plan by December 31, 2022, with the electric public utilities and stakeholders to achieve the reduction goals and to biennially review the plan for necessary modifications.
Directs the Commission to comply with current law and practice with respect to the least cost planning for generation pursuant to GS 62-2(a)(3a) in achieving the reduction goals and determining generation and resource mix for the future. Requires any new generation facilities or other resources selected by the Commission in order to achieve the reduction goals to be owned and recovered on a cost-of-service basis by the applicable electric public utility, except as follows. Makes existing law applicable with respect to energy efficiency measures and demand-side management. Establishes the following additional requirements for new solar generation selected by the Commission: (1) 45% total megawatts alternating current (MW AC) of any solar energy facilities established must 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 (2) 55% of the total megawatts alternating current (MW AC) of any solar energy facilities established must 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. Makes the ownership requirements applicable to solar energy facilities paired with energy storage and procured in connection with any voluntary customer program.
Requires the Commission to ensure any generation and resource changes maintain or improve upon adequacy and reliability of the existing grid. Directs that the Commission maintain discretion to determine optimal timing and generation and resource-mix to achieve the least cost path to compliance with the reduction goals, including discretion in the reduction goal dates specified in order to allow for implementation of solutions that would have a more significant and material impact on carbon reduction. Prohibits exceeding the dates specified 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, or in the event it is necessary to maintain the adequacy and reliability of the existing grid. Requires the Commission to receive and consider stakeholder input in making such determinations.
Amends GS 62-110.8, which requires electric public utilities to file for Commission approval a program for the competitive procurement of energy and capacity from renewable energy facilities in the aggregate amount of 2,660 megawatts (MW), reasonably allocated over a term of 45 months. Eliminates the provision which directs that the offering of a new renewable energy resources competitive procurement and the amount to be procured at the termination of the initial competitive procurement period of 45 months be determined by the Commission based on a showing of need evidenced by the electric public utility's most recent biennial integrated resource plan or annual update approved by the Commission pursuant to GS 62-110.1(c). Additionally, eliminates the Commission's duty to adopt rules establishing a procedure for the Commission to modify or delay implementation of the statute's provisions in whole or in part if the Commission determines that it is in the public interest to do so.
Authorizes the Commission 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 facilities will be needed to achieve the reduction goals in accordance with the act.
Directs the Department of Environmental Quality (DEQ) to, by March 1, 2022, develop a plan to ensure adequate financial resources for the decommissioning of utility-scale solar projects, as defined, to be submitted to the NCGA for legislative action. Defines utility-scale solar project to include solar arrays, accessory buildings, transmission facilities, and any other infrastructure necessary for the operation of the project.
Maintains the content of Part II. of the previous edition with the following revisions. Modifies proposed GS 62-133.16, Performance-based regulation authorized. Previously, the Commission was explicitly prohibited from modifying an electric public utility's performance-based regulation (PBR) application. Now the Commission is authorized to issue an order modifying the PBR application as an alternative to issuing an order approving or rejecting the application following the required application review procedures established under the proposed statute. Makes technical changes.
Authorizes and directs the Commission to establish rules for securitization of costs associated with early retirement of subcritical coal-fired electric generating facilities within 180 days of the date the act becomes law. Requires stakeholder input and participation. Directs the Commission to develop rules to determine costs to be securitized at 50% of the remaining net book value of all subcritical coal-fired electric generating facilities to be retired to achieve the act's reduction goals, with any remaining non-securitized costs to be recovered through rates. Makes rules, procedures, obligations, and protections adopted for securitization of costs associated with retirement of subcritical coal-fired generating facilities to be substantively identical to the provisions of Section 1 of SL 2019-244 (enacting new GS 62-172, Financing for certain storm recovery costs), except with respect to the purposes for which securitization may be used under that section. Additionally directs the Commission to: (1) evaluate and modify as necessary existing standby service charges; (2) revise net metering rates; (3) establish an on utility bill repayment program related to energy efficiency investments; and (4) 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, to offset their energy consumption, with specified requirements.
Directs the Commission to initiate a docket within 120 days of the date the act becomes law 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 (PPA) with eligible small power producers. Requires: (1) providing those producers a one-time option to elect, within 180 days of an authorizing Commission order, to amend their existing PPA, extending into a new longer term of the existing PPA for a term equal to the remaining term of the existing PPA plus an additional 10 years and (2) establishing capacity and energy rates to be paid by the electric public utilities under an amended PPA that meets specified criteria, including requiring that the capacity and energy rates be just and reasonable to all classes of customers of the electric public utilities, be in the public interest, and result in the immediate reduction in the cost of electricity for all classes of customers and a reduction in the estimated long-term cost of electricity for all classes of customers. Defines eligible small power producers to mean small power producers, as defined in GS 62-3(27a), generating solar electricity with a total capacity equal to or less than five megawatts (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.
Declares it appropriate, in the public interest and in an effort to achieve regulatory economy, to encourage eligible small power producers and electric public utilities to negotiate amendments to the PPAs of eligible small power producers, as specified.
Includes a severability clause.
Changes the act's short and long titles.
House amendment #2 makes the following changes to the 2nd edition.
Adds new Section 8.1, stating four legislative findings regarding the Regional Greenhouse Gas Initiative (RGGI) and related authorities of the state legislative and executive branches to participate in RGGI. Explicitly prohibits the executive branch from taking action to participate in RGGI and implement emissions limitations and cap and trade requirements attendant with the RGGI program until so authorized by the NCGA.
House committee substitute deletes the content of the 1st edition and replaces it with the following.
States legislative findings regarding the transition away from coal-fired electricity generation and the authorization of performance-based regulation for electric utilities. Sets forth four defined terms.
Mandates electric public utilities to retire all subcritical coal-fired generating facilities, as defined, by December 31, 2030, in the manner and subject to the conditions described for each of the following: Allen Plant, Marshall Units 1 and 2, Roxboro Plant, Cliffside Unit 5, and Mayo Plant. Requires the Allen Plant to be retired on or before December 31, 2023, and the Marshall Units 1 and 2 to be retired on or before December 31, 2026, with the utility required to provide updates to the Utilities Commission (Commission) in its integrated resource plans regarding the status of the utility’s efforts to ensure that the designated replacement resources, as defined, are constructed according to a timeline that allows for retirement of the coal-fired generating facility by the targeted retirement dates. Requires that a coal retirement and replacement plan be filed for the Roxboro Plant on or before September 1, 2024, and for the Cliffside Unit 5 and the Mayo Plant on or before September 1, 2027, and sets criteria for designated replacement resources for these facilities. Details requirements of coal retirement and replacement plans, including the proposed retirement date and the reasoning for that date. Requires the Commission to establish a procedural schedule regarding the filing, including opportunities to intervene and party comment, public notice and comment at one or more public hearings, and evidentiary hearing requirements. Requires the Commission to issue an order approving, modifying, or rejecting a coal retirement and replacement plan within 180 days of filing. Lists three criteria that must be met for the Commission to approve a coal replacement and retirement plan, including specified size requirements for the proposed replacement resource in the plan. Requires the Commission to include an approved construction cost for each approved replacement resource, and provides for the Commission’s issuance of a certificate of public convenience and necessity for certain replacement resources as required under GS 62-110.1.
Allows for an electric public utility to file notice with the Commission requesting a delay in the retirement date due to the facility’s retirement compromising the reliability of the utility’s service, with the Commission required to then hold a hearing and approve or reject the request within 90 days of receipt of the notice and request.
Requires the applicable designated replacement resource to be placed in service prior to the retirement of a subcritical coal-fired generating facility unless the utility can maintain reliable service otherwise.
Allows for the applicable utility to establish a regulatory asset for the remaining net book value of each subcritical coal-fired generating facility retired pursuant to Section 1 of the act and amortize the regulatory asset at the same rate the facility was previously depreciated, with the asset included in the rate base for ratemaking purposes and in future general rate proceeding requires the Commission to establish an amortization period for recovery and allow a return on the unamortized balance at the utility’s then authorized, net-of-tax, weighted average cost of capital.
Details requirements for designated replacement resources and renewable generating facilities purchased and owned by the electric public utilities pursuant to Section 1 of the act. For nonrenewable generating facilities procured pursuant to the Section, requires utilities to use competitive procurement for the design, engineering, and construction of such generating facilities. For any renewable energy facilities and the energy storage system (ESS), as defined, procured pursuant to the Section, requires competitive procurement and purchase of such facilities from third parties in compliance with GS 62-110.8 (Competitive procurement of renewable energy), as amended and except as specified (with exceptions related to utility ownership limitations set forth in subsection (b1) and the cost cap set forth in (g1)), for procurements occurring after January 1, 2022. Details further parameters for procurement pursuant to the act, including: (1) deeming the designated replacement resources consistent with the public convenience and necessity and public interest pursuant to GS 62-110.8; (2) requiring the Commission to provide an expedited decision on an application for a certificate of public conveyance for all such resources, subject to notice requirements of the utility and public hearing requirements; and (3) allowing the electric public utilities to recover the reasonably and prudent incurred cost of all generation facilities and ESSs purchased or constructed pursuant to the Section, with rebuttable presumptions set forth for the utility’s actual costs to be reasonable and prudent if at or below the Commission’s approved projected costs of either the facility or the ESS, and allowing utilities to establish a regulatory asset and defer the incremental costs, as described, of all such costs until such time as the costs can be reflected in consumer rates.
Amends GS 62-110.8, which requires electric public utilities to file for Commission approval a program for the competitive procurement of energy and capacity from renewable energy facilities as follows. Limits eligibility to facilities with a nameplate capacity rating of 90 megawatts alternating current (MW AC) or less that are placed in service after the date of the utility’s initial competitive procurement, except as providing in new subsection (b1) regarding procurements commencing after January 1, 2021. Requires procurement of energy and capacity from renewable energy facilities in the aggregate amount of 7,327 MW AC, with the total reasonably allocated over a term of 106 months of Commission approval (was, in the aggregate amount of 2,660 MW with the total reasonably allocated over a term of 45 months of Commission approval). Requires annual procurement of approximately 777 MW AC each calendar year beginning in 2021 and concluding in 2026. Allows utilities to petition the Commission for modification of the procurement schedule. Now requires the Commission to determine whether it is in the interest of ratepayers to require further competitive procurement of renewable generating facilities by the electric public utilities beyond the initial procurement period, with the Commission required to also determine the amount to be procured beyond that required by subsection (a) and the allocation of ownership between third parties and electric public utilities. Requires the Commission's determination to be based on the electric public utility's most recent biennial integrated resource plan or annual update accepted or approved by the Commission, provided that such plan assures adequate, reliable utility service (previously required that after termination of the initial procurement period, the offering of a new renewable energy resources competitive procurement and the amount to be procured to be determined by the Commission, based on a showing of need evidenced by the electric public utility's most recent biennial integrated resource plan or annual update approved by the Commission pursuant to GS 62-110.1(c)). Makes the provisions of subsection (b) regarding utilities jointly or individually implementing the aggregate competitive procurement requirements applicable to procurement commencing prior to January 1, 2021.
Enacts new subsection (b1), providing distinct requirements for procurements commencing after January 1, 2021, and continuing through December 31, 2026, including: (1) requiring 45% of the total MW AC of renewable energy facilities scheduled to be procured for procurements commencing after January 1, 2021, to be supplied through execution of power purchase agreements with third parties pursuant to which the electric public utility purchases the renewable energy, capacity, and environmental and renewable attributes from renewable energy facilities owned and operated by third parties that commit to allow the procuring electric public utility rights to dispatch, operate, and control the solicited renewable energy facilities in the same manner as the utility’s own generating resources and (2) 55% of the total MW AC of renewable energy facilities scheduled to be procured through procurements commencing after January 1, 2021, must be supplied from renewable energy facilities purchased from third parties owned and operated by the soliciting electric public utility, with an exemption to the cap on facility nameplate capacity of 80 MW AC or less.
Makes organizational changes to place the limitations for procured renewable energy capacity in new subsection (b2). Replaces the provisions regarding the reduction of the required procurement if subject utilities have executed a power purchase agreement and interconnection agreement for capacity prior to the end of the initial competitive procurement period within their balancing authority area in excess of 3,500 MW. Now allows for the Commission to reduce the total aggregate MW capacity AC of renewable generating facilities required for procurement if it is reasonably projected that on or before January 1, 2027, the subject utilities will have executed power purchase agreements and interconnection agreements with renewable generating facilities within their balancing authority areas having an aggregate MW AC capacity in excess of 3,500 MW AC (exclusive of power purchase agreements entered into pursuant to the statute, GS 62-159.2, and GS 62-126.8B), by an amount calculated as now specified. No longer requires conducting an additional competitive procurement of a deficit of renewable energy facilities below 3,500 MW at the end of the initial competitive procurement period. Now caps the price to be paid under any power purchase agreement for third-party owned resources combined with the cost of any necessary transmission or distribution upgrade at the utility’s forecast of its avoided cost calculated over the term of the agreement (was, the cap of the utility’s procurement obligation). Makes changes to refer to "power purchase agreement" rather than "contract." Regarding the pro forma power purchase agreement utilities are required to submit to the Commission for approval and make publicly available prior to competitive procurement solicitation, now provides that the resource curtailment included is required to be limited to a percentage of the expected output of the generation facility determined by the Commission to be in the public interest. With respect to procurements commencing prior to January 1, 2021, allows more than 30% of a utility’s competitive procurement requirement to be satisfied through the utility’s own development of renewable energy facilities offered by the utility or subsidiary of the utility located within the utility’s service territory (was, capped at 30% regardless of procurement commencement).
Explicitly requires utilities to be permitted through the competitive processes to solicit bids for the construction of renewable energy facilities on or near property owned or controlled by the utility, including any retiring subcritical coal-fired generating facility, where the sites will provide benefits to customers.
Currently, requires the competitive procurement to be independently administered by a third-party entity approved by the Commission. Now limits this requirement to all procurements commencing prior to January 1, 2022, and requires, for procurements commencing after January 1, 2021, but before January 1, 2022, utilities to be permitted to directly assist the third-party entity and provide input on all aspects of the procurement with required collaboration to develop and publish the methods used to evaluate responses received pursuant to the competitive procurement solicitation and ensuring responses are treated equitably. For procurements commencing after January 1, 2022, requires competitive procurement to be administered by utilities in accordance with Commission rules, subject to oversight and evaluation by a third-party entity to be approved by the Commission. Maintains the provisions that provide for recovery of administrative and related expenses incurred through fees levied upon bidding participants. Makes conforming changes to subsection (e) regarding utility involvement in procurement. Enacts new subsection (e1), prohibiting the utility or any of its affiliates from submitting bids into the competitive procurement process or to have any financial interest in third-party bidders for procurements commencing after January 1, 2021. Enacts new subsection (e2) deeming renewable generating facilities purchased and owned by the electric public utilities pursuant to the statute through procurements occurring after January 1, 2021, consistent with the public convenience and necessity and public interest.
Makes the provisions of subsection (g), regarding authority of the utility to recover costs of all purchases of energy, capacity, and environmental and renewable attributes from third-party renewable energy facilities and to recover the authorized revenue of any utility-owned assets procured under the statute through an annual rider, approved and annually reviewed by the Commission.
Enacts new subsection (g1) to require utilities to recover from their customers the reasonably and prudently incurred costs paid under power purchase agreements under the statute through the rider authorized in subsection (g) for all procurements commencing after January 1, 2021, with utility-owned renewable generating facilities subject to the cost caps established under (b2)(2), as organized and amended at the utility’s current forecast of its avoided cost calculated over the term of the power purchase agreement for third-party owned resources. Allows utilities to establish a regulatory asset and defer the incremental costs, as described, of all such costs until such time as the costs can be reflected in consumer rates.
Enacts new subsection (g2) to require utilities to take into account the cost of any needed transmission or distribution upgrades in determining the most cost-effective proposals in any procurement process under the statute, with such costs not directly assigned to the bidder of the proposal selected but used for ratemaking purposes. Allows utilities to establish a regulatory asset and defer the incremental costs, as described, of all such upgrades along with associated carrying costs, weighted average cost of capital, until such time as the costs can be reflected in consumer rates. Requires the Commission to establish an amortization period for recovery and allow return on the unamortized balance at the electric public utility’s then authorized, net-of-tax, weighted average cost of capital for future general rate capital.
Expands the implementing rules the Commission must adopt pursuant to subsection (h). Now requires rules to include the oversight of the competitive procurement program by the Commission and by independent third parties, as now included in the statute. Requires the Commission’s rules to be amended by May 1, 2022, to provide for the administration of the procurement process by the utility subject to the oversight of an independent evaluator retained by the utility by a contract approved by the Commission; approval by the Commission of the utilities’ selection methodology and the independent evaluator’s review procedures; detailed reports by the independent evaluator to the Commission; and any further changes related to the foregoing, including modification of communication restrictions deemed appropriate by the Commission. Restricts rules regarding the waiver of regulatory conditions or code of conduct requirements unreasonably restricting a utility’s participation in the competitive procurement process to procurements occurring prior to January 1, 2021. Expands the requirement for rules to establish a method to allow a utility to recover its costs under subsection (g) to also include recovery under subsections (g1) and (g2).
Excludes from the above requirements of Section 1 of the act electric public utilities serving fewer than 150,000 NC retail jurisdictional customers as of January 1, 2021.
Amends GS 62-133.2, which allows for the Commission to approve fuel and fuel-related charge adjustments for electric utilities based on adjusted and reasonable costs of fuel and fuel-related costs prudently incurred under efficient management and economic operations. Defines efficient management and economic operations as including actions and decisions that modify commitment and dispatch to manage seasonal demand, mitigate fuel supply security and transportation risk, and maintain dispatchable capacity value.
Enacts GS 62-173, Financing for certain energy transition costs. Sets forth 15 defined terms. Allows a public utility to petition the Commission for a financing order, defined as an order that authorizes the issuance of energy transition bonds; the imposition, collection, and periodic adjustments of an energy transition charge; the creation of energy transition property; and the sale, assignment, or transfer of energy transition property to an assignee. Sets forth five requirements of the petition, including providing the energy transition costs incurred by the utility, as defined, and an estimate of the costs that are being undertaken but are not completed, and an estimate of the energy transition charges necessary to recover the energy transition costs and financing costs and the proposed period for recovery of such costs. Provides further requirements and Commission approval concerning a public utility subject to a settlement agreement that governs the type and amount of principal costs that could be included in energy transition costs.
Requires petition proceedings to be disposed of in accordance with the Chapter and rules and regulations of the Commission for petitions initially filed on or before January 1, 2023, except as follows. Requires the Commission to publish a procedural schedule within 14 days of filing of the petition which permits a decision no later than 135 days from filing. Requires the Commission to issue a financing order or an order rejecting the petition no later than 135 days after the petition is filed. Requires an order rejecting a petition to include the Commission’s reasoning for the rejection; requires the utility to resubmit a petition within 60 days of the order rejecting the earlier petition. Provides for a party to petition the Commission for reconsideration of the order within five days of issuance.
Lists 14 elements that must be included in a financing order, including the amount of energy transition costs to be financed using energy transition bonds, and findings that the proposed issuance of energy transition bonds and the imposition and collection of an energy transition charge are expected to provide quantifiable benefits to customers as compared to the cost that would have been incurred absent their issuance, and that the structuring and pricing of the bonds are reasonably expected to result in the lowest energy transition charges consistent with market conditions at the time the bonds are priced and the terms set forth in such financing order. Also requires inclusion of a mechanism for periodic adjustments in energy transition charges to customers, and energy transition charge allocation among customer classes. Requires the financing order to establish a bond team consisting of representatives of the public utility and its consultant, the Public Staff and its consultant, and the Commission with a designated Commissioner and the Commission's consultant and counsel, and direct the bond team to work together and make all decisions as to the structuring, marketing, and pricing of the energy transition bonds; the selection of the underwriters; and the approval of the transaction documents. Gives the Commission final decision-making authority on all matters considered by the bond team. Allows the financing order to condition the sale or transfer of energy transition property to an assignee. Requires annual filing of a petition or letter concerning adjustment of energy transition charges pursuant to the financing order, and requires the Commission to review and either approve the request or inform the public utility of any errors, which the public utility can correct and then refile the request. Provides that financing orders are irrevocable after the transfer of energy transition property to an assignee or the issuance of authorized energy transition bonds. After issuance of a financing order, the public utility retains sole discretion regarding whether to assign, sell, or otherwise transfer energy transition property.
Provides for instances in which subsequent financing orders may be issued.
Allows an adverse party to petition for judicial review by the Supreme Court within 30 days after the Commission issues a financing order or a decision denying a request for reconsideration, or within 30 days after the commission issues its decision on reconsideration. Sets forth parameters for judicial review.
Establishes that a financing order remains in effect and energy transition property under the order continues to exist until energy transition bonds issued pursuant to the order have been paid in full or defeased, and all Commission-approved financing costs of the bonds have been recovered in full. Further specifies that a financing order issued to a public utility remains in effect and unabated regardless of reorganization, bankruptcy or other insolvency proceedings, merger, or sale of the public utility or its successors or assignees.
Details exceptions to the jurisdiction of the Commission. Establishes duties of a public utility that has obtained a financing order and causes energy transition bonds to be issued concerning customer billing and explanation of charges related to energy transition costs.
Sets forth provisions applicable to energy transition property, including parameters regarding security interests in energy transition property, and the sale, assignment, or transfer of energy transition property.
Requires the description of energy transition property being transferred to any assignee or pledgee in any transfer agreement or security document, or indication in any financing statement, to refer to the financing order that created the energy transition property and state that the agreement or financing statement covers all or part of the property described in the financing order. Specifies that the requirement applies to all purported transfers of, purported grants or liens or security interests in, energy transition property, regardless of whether filed.
Subjects all financing statements under the statute to Part 5, Filing, Article 9 of the Uniform Commercial Code (UCC), except as to continuation statements.
Designates North Carolina in the choice of law provision.
Specifies that energy transition bonds authorized in financing orders are not public debt, and requires all energy transition bonds to contain a statement to that effect, as provided.
Lists entities which may legally invest any sinking funds, moneys, or other funds in energy transition bonds, including State and local governments and officers, except for members of the Commission, banking and credit institutions, personal representatives, guardians, trustees, and other fiduciaries, and all other persons authorized to invest in bonds or other obligations of a similar nature.
Details actions which the State and its agencies are prohibited from taking which would alter the Article's provisions, impair the value of energy transition property or the security for the energy transition bonds or revise energy transition costs, impair the rights and remedies of bondholders, assignees, and other financing parties; or reduce, alter, or impair energy transition charges imposed for the benefit of bondholders, assignees, or other financing parties until all principal, interest, premium, costs and fees, expenses, or charges incurred, and any contracts to be performed, have been paid and performed in full. Allows for the provided limitation language to be included in energy transition bonds issued and related documentation.
Clarifies that an assignee or financing party is not a public utility or person providing electric service by virtue of engaging in a transaction under the statute.
Provides for the statute to govern over any conflicting law.
Authorizes the Commission and/or public staff to engage an outside consultant or counsel in making a determination under the section.
Provides for the continued effectiveness of actions allowed under the statute if any provision of the statute is held invalid or invalidated, superseded, replaced, repealed, or expires for any reason.
Amends GS 25-9-109 to exempt from the provisions of Article 9 of the Chapter (Security Interests under the UCC) the creation, perfection, priority or enforcement of any sale, assignment of, pledge of, security interest in, or other transfer of, any interest or right or portion of any interest or right in any energy recovery property as defined in new GS 62-173.
Authorizes electric utilities operating in the state to jointly or separately incur costs up to an aggregate of $50 million to pursue an Early Site Permit (ESP) from the Nuclear Regulatory Commission for siting of an advanced nuclear facility at a single location in the state. Requires seeking federal funds to offset the costs. Allows each participating electric public utility to establish a regulatory asset and defer the incremental costs incurred along with associated carrying costs based on the utility’s then-authorized, net-of-tax, weighted average cost of capital, until such time the costs can be reflected in customer rates. Requires the Commission to establish an amortization period for recovery for future general rate proceedings and allows a return on the amortized balance at the utility’s then authorized, net-of-tax, weighted average cost of capital. Specifies that this is not a legislative endorsement for the selection of nuclear resources in future electric public utility integrated resource plans, which must be reviewed by the Commission pursuant to state law and regulations.
Directs electric public utilities to prepare and submit Subsequent License Renewal applications with the Nuclear Regulatory Commission for each of the six currently operating nuclear electric generating facility sites in the electric public utilities’ balancing area authority. Requires the utilities to report on the status of the application in their integrated resource plan filings.
Enacts new GS 62-133.16, which provides as follows.
Allows the North Carolina Utilities Commission (Commission), in addition to the method for fixing base rates, to approve performance-based regulation (meaning an alternative ratemaking approach that includes decoupling, one or more performance incentive mechanisms, and a multi-year rate plan, including an earnings sharing mechanism, or other such alternative regulatory mechanisms as may be proposed by an electric public utility) when applied for by an electric public utility if the Commission allocates the electric public utility’s total revenue requirement among customer classes based on 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 inter-class subsidization of ratepayers is minimized to the greatest extent practicable by the conclusion of the multi-year rate plan (MYRP) period. Defines cost causation principle to mean 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 providing electric service. Defines MYRP as a ratemaking mechanism under which the Commission sets base rates for a multi-year period that includes authorized periodic changes in base rates without the electric public utility filing a subsequent general rate application, along with an earnings sharing mechanism.
Allows an electric public utility to submit a performance-based regulation (PBR) application in a general rate case proceeding under GS 62-133. Requires the application to include a decoupling ratemaking mechanism, one or more PIMs, and a MYRP, including both an earning sharing mechanism and proposed revenue requirements and base rates for each of the years that a MYRP is in effect or a method for making the calculation. Defines decoupling ratemaking mechanism as one 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. Defines PIM (performance incentive mechanism) as a ratemaking mechanism that links electric public utility revenue or earnings to electric public utility performance in targeted areas consistent with policy goals (as defined in the act), approved by the Commission, and includes specific performance metrics and targets against which electric public utility performance is measured. Defines an earnings sharing mechanism as an annual ratemaking mechanism that shares surplus earnings between the utility and customers over the time covered by the MYRP and any further authorized period of time. Sets out the following additional requirements for a PBR application. Requires the base rates for the first rate year of the MYRP to be fixed as required under GS 62-133, but in the second and third years, changes in the rate are to 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 operating and maintenance savings, and deprecation of rate base associated with the capital investments, that are incurred or realized during each rate year of the MVP period; sets caps on the increases in the second and third years. Requires the Commission, in a proceeding authorizing a MYRP, to 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. Requires the Commission, within 60 days of the conclusion of each rate year, to establish a proceeding to: (1) examine the earnings of the electric public utility during the rate year to determine if the earnings exceed the authorized rate of return on equity determined by the Commission in the proceeding establishing the PBR; sets out actions that must be taken depending on whether the weather-normalization earnings exceed the authorized rate of return on equity; (2) evaluate the performance of the electric public utility with respect to Commission approved PIMs with financial rewards collected from customers and penalties refunded to customers; (3) evaluate the decoupling ratemaking mechanism and refund or collect a corresponding amount from residential customers. Specifies that the proposed decoupling mechanism is only applicable to residential customer classes. Requires the Commission to establish an annual revenue requirement per residential customer and an appropriate distribution of the revenue requirement per customer in each month of the year; sets out the process for establishing the target revenue for the residential class. Requires the utility to monthly defer the difference between the actual revenue and the target revenue. Requires the changes in revenue requirements for the second and third rate years to be allocated to the residential customer class and divided by the number of residential customers to determine the adjustment to the annual revenue requirement that is used to establish the targeted revenues for the class in the second and third rate years. Requires the policy goal targeted by a PIM to be clearly defined, measurable with a defined performance metric, and within the electric public utility’s control. Requires penalties to be refunded to customers and rewards to be collected from customers with the total of all potential and actual PIM incentives or penalties capped at the specified amount. Requires PIMs to include one or more of the following: (1) rewards based on the sharing of savings achieved by meeting or exceeding a specific policy goal; (2) rewards or penalties based on differentiated authorized rates of return on common equity; and (3) fixed financial rewards.
Requires the Commission to approve a PBR application upon finding that a proposed PBR would result in just and reasonable rates, is in the public interest, and is consistent with criteria established in this statute and any adopted rules. Requires that the Commission consider whether the application: (1) assures that no customer or class is unreasonably harmed and that the rate are fair to the utility and the customer; (2) reasonably assures the continuation of safe and reliable electric service and; (3) will not unreasonably prejudice any class of electric customers and result in sudden substantial rate increase or “rate shock.” Sets out 11 additional factors that the Commission may consider in reviewing the application, including whether the application encourages peak load reduction or efficient use of the system, encourages energy efficiency, encourages carbon reduction, or promotes resilience and security of the electric grid. Sets out the process for the consideration of a PBR application, including suspending rate changes and hearing requirements. Allows the Commission, with good cause, at any time before a PBR plan period expires, to examine the reasonable of an electric public utility’s rates under a plan, conduct periodic review with opportunities for public hearing and comments, and initiate a proceeding to adjust base rates or PIMS as necessary. Provides that an approved PBR application remains in effect for a plan period of no more than 36 months.
Requires an electric public utility to make annual filing that includes 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, and the adjustments reflecting rewards or penalties provided for in approved PIMS.
Requires the Commission to report annually on activities taken by the Commission to implement, and by the electric public utilities to comply with the state’s requirements to the Governor and specified legislative entities. Requires the Commission to adopt rules to implement the statute’s requirements, including addressing specified matters. Requires the rules to be adopted no later than 120 days after the date that the statute becomes law.
Amends GS 62-159.2 which requires electric public utilities providing retail electric service to more than 150,000 North Carolina retail jurisdictional customers as of January 1, 2017, to file an application for approval of a new program applicable to major military installations, UNC, and other new and existing nonresidential customers with either a contract demand (1) equal to or greater than one megawatt (MW) or (2) at multiple service locations that in aggregate, is equal to or greater than 5 MW; the program is required to allow customers to select the new renewable energy facility from which the electric public utility must procure energy and capacity. Adds the following new requirements applicable to participating customers that have not entered into an agreement under the program by January 1, 2021. Prohibits the reasonably projected first year annual energy output of any renewable energy facility(ies) selected by or procured on behalf of a participating customer from exceeding the average annual energy consumption of the eligible customer premises for the most recent three calendar years (or the reasonably projected average annual energy consumption for the first three years of operation for premises not in operation for three years). Requires the participating customers' premises to be in the State and in the retail service territory of the offering utility, and limits participation to the program offered by the electric public utility that provides the customer’s service. Prohibits a single generating facility selected by or procured on behalf of a participating customer from exceed 80 megawatts alternating current (MW AC) in capacity. Requires the electric public utility, the participating customer, and the owner of any renewable energy facility(ies) selected by or procured on behalf of a participating customer to enter into an agreement providing that all environmental and renewable energy attributes generated by the facilities to be transferred to the participating customer for retirement or retired on the customer's behalf. Requires public utilities to also establish reasonable credit requirements for renewable energy suppliers. Changes references in capacity requirements in the statute to megawatts to megawatts alternating current. Requires major military installations and UNC to fully subscribe to all their allocation before December 31, 2022 (was, 2020). Provides that for customers that enter into an agreement after the effective date of the statute, the customer can select one of the following options: (1) a bill credit equal to the hourly real time avoided cost or day ahead avoided cost; or (2) a bill credit equal to avoided cost as determined in the specified manner for a period of two, five, or ten years.
Sets out specified terms and conditions governing participating in the program by major military installations and UNC addressing: (1) providing notice of intent to participate, with UNC desired capacity amount capped at 250 MW AC and major military installations desired capacity amount capped at 100 MWAC of renewable energy capacity; (2) process by which electric public utilities must competitively procure renewable energy and capacity to provide the amount of capacity requested and the requirements for the power purchase agreement; (3) requirement to pay a product charge, and entitlement to bill credits; and (4) termination of an agreement when an electric public utility is prohibited from relying on or receiving credit for any renewable generating facility procured under the program.
Enacts new GS 62-126.8B, providing as follows. Sets out State policy concerning expanding renewable energy options for large commercial or industrial customers, small commercial or industrial customers, local governments, and residential customers. Defines, in GS 62-126.3, large commercial or industrial customer as a commercial or industrial retail customer of an electric public utility whose annual peak demand is more than five megawatts; defines a small commercial or industrial customer as a commercial or industrial retail customer of an electric public utility whose annual peak demand is less than or equal to five megawatts but excluding government customers. Requires electric public utilities providing retail electric service to more than 150,000 North Carolina retail jurisdictional customers as of January 1, 2021, to complete a competitive procurement seeking new solar resources in the total amount of approximately 750 MW AC procured over approximately three years. Requires the offering utilities to enter into power purchase agreements (PPA) with the selected solar generating facilities, with the PPA for a period of 20 years and providing for the purchase of all the energy, capacity, and all environmental and renewable energy attributes. Sets out additional requirements for the PPA. Sets out provisions governing performance standards, and requirements for the renewable generation facilities including capping capacity at no more than 80 MW AC. Sets out requirements for applying for and approving an offering utility’s application requesting approval of a shared solar program. Sets out requirements for each shared solar program related to: (1) location of customer’s premises and which utility to participate with; (2) capacity during the initial enrollment period; (3) allocation of total program volume, with 70% to large commercial or industrial customers and small commercial or industrial customers, 20% to government customers, and 10% to residential customers; (4) cap on the reasonably projected first year’s annual energy output from a participating customer’s capacity allocation from the program; (5) timing of termination or cancelation of a subscription; (6) payment of a product charge; (7) receipt of a bill credit; (8) retirement of environmental and renewable energy attributes produced by any shared renewable facility associated with the customer’s participation in the program, and termination of an agreement when an electric public utility is prohibited from relying on or receiving credit for any renewable generating facility procured under the program; and (9) payment of an administration fee.
Repeals GS 62-126.8, which required each offering utility to file a plan with the Commission to offer a community solar energy facility program for participation by its retail customers, and sets out requirements for the plan. Makes conforming deletion of the term community solar energy facility in GS 62-126.3. Enacts new GS 62-126.8B, concerning community solar gardens. Requires electric public utilities that are subject to the statute to undergo a competitive procurement of solar energy to offer a community solar gardens program for participation by small commercial and industrial government, and residential customers. Defines an offering utility as any electric public utility serving more than 100,000 retail electric customers in the State as of January 1, 2021. Sets out how much of the new distribution-connected solar generation that is to be utility owned must is to be sought in the procurement, with amounts varying based on the number of North Carolina retail jurisdictional customers served. Sets out deadlines and required amounts for the initial procurements. Prohibits offering utilities and its affiliates from participating as bidders, however, provides that if there are an insufficient number of eligible solar generating facilities procured through the process, then an offering utility is allowed to propose self-developed solar generating facilities if the capital costs are below the specified cost cap. Requires solar generation facilities procured this this process to be new solar capacity and located in this State. Requires each facility to be interconnected to the relevant offering utility’s distribution system.
Sets out requirements for applying for and approving a community solar gardens program. Sets out requirements for each community solar garden related to: (1) allocation of total program volume, with 35% to small commercial or industrial customers, 30% to government customers, and 35% to residential customers; (2) cap on the reasonably projected first year’s annual energy output from a participating customer’s capacity allocation from the program; (3) prohibition on a single participating customer from accounting for more than 50% interest in a single facility, and requiring each facility to have at least five subscribers; (4) requirement that participating customers’ premises be in the State and that they be in the territory of the offering utility offering the program; (5) timing of termination or cancelation of a subscription; (6) payment of a monthly product charge; (7) payment of an administration fee; and (8) receipt of a bill credit.
Sets out a cap on the capital cost for the construction of projects procured or construed under this statute and the process for issuing a certificate of public convenience and necessity. Allows an offering utility to establish a regulatory asset and defer to it the incremental costs of all solar generating facilities procured or built under this statute until the cost can be reflected in customer rates; specifies the types of incremental costs that may be deferred. Provides that if at any point after the date that is two years from the date on which the program is opened for subscriptions, less than 50% of the available subscriptions have been claimed, any party may petition the Commission to modify a community solar garden program to enhance participation by adjusting the participating customer product charge and bill credit, and allows the Commission to make the modification if it is in the public interest to do so.
Amends GS 62-2 by amending the State’s public policy related to rates and charges for public utility services, to make it policy to provide efficient use (was, conservation) of energy resources by avoiding wasteful, uneconomic and inefficient uses of energy. Also adds to the State’s public policy providing just and reasonable time-variant rates and other dynamic price offerings to utility customers that are designed to optimize the total cost of energy consumption rather than the total volume of energy consumed.
Amends GS 62-126.2 to state the NCGA’s finding that as a matter of public policy it is in the interest of the State to encourage time-variant pricing structure to promote ne energy metering options. Also states the finding and encourages the time-variant pricing structure to promote net energy metering options and the leasing of and subscription to solar energy facilities, cross-subsidization should be avoided to the greatest extent practicable when balancing the goals of the act. Adds that the NCGA recognizes that due to substantive differences in size, customer bases, access to low-carbon generation, and other factors, this declaration of policy does not apply to electric membership corporations, state owned electric supplies, or municipalities that sell electric power to retail customers in the State.
Amends GS 62-126.5, increasing the cap for the total installed capacity of all solar energy facilities on an offering utility's system that are leased pursuant to the statute from 1% to 5% of the previous five-year average of the North Carolina retail contribution to the offering utility's coincident retail peak demand.
Enacts new GS 62-126.4A, setting out the following. Requires each offering utility to file for Commission approval of a solar choice tariff that become the exclusive option available to customers that apply for net metering service after the Commission’s approval. Defines an offering utility to include all electric public utilities serving more than 100,000 retail electric customers in the State as of January 1, 2021. Requires the Commission to approve an application to establish a solar choice tariff that meets all of the six specified objectives, including: (1) provides rate design options that align the customer generator's ability to achieve bill savings with long-term reductions in the overall cost the offering utility will incur in providing electric service, including, but not limited to, time-variant and dynamic pricing structures; (2) minimizes, to the greatest extent practicable, any intra-class cross-subsidization identified using the offering utility's most recently approved embedded cost of service study; and (3) encourages customer adoption of other energy savings, demand reduction, or grid services technologies and participation in cost-effective programs that can be offered in conjunction with a solar choice tariff to help lower the cost of providing service and maximize grid benefits. Gives customer generators taking service under a pre-existing net metering tariff before the Commission’s approval of a solar choice tariff the option to transition to the new solar choice tariff or continue to take service under the offering utility's pre-existing net metering tariff in effect at the time of interconnection of that customer generator's net metering facility until January 1, 2040. Requires, after January 1, 2027, a non-by-passable charge, based on the DC capacity of the facility, for customers who remain on a pre-existing net metering tariff. Requires an offering utility offering an approved solar choice tariff to continue to be authorized to fully recover its cost of service include the specified costs; exempts from authorized cost recovery customers participating in a retail demand electric tariff in effect on or before July 1, 2021, or a customer who elects to take service under such retail demand tariff. Requires the solar choice tariff to be filed by each offering utility no later than 120 days after the effective date of this section, and requires the Commission to issue an order to approve, modify, or deny the program no later than 90 days after the submission of the program by the electric public utility. Amends the definition of net metering in GS 62-126.3 by adding that a solar choice tariff prospectively constitutes an electric public utility’s net metering arrangement for new customer participation after its effective date.
Amends GS 62-133.8 [Renewable Energy and Energy Efficiency Portfolio Standard (REPS)] by amending the definition of the term energy efficiency measure, as it is used in this statute, to mean an equipment, physical, behavioral, or program change implemented by a retail electric customer after January 1, 2007, that reduces the customer's energy requirements from the electric power supplier to perform the same function. Specifies that the term also includes energy produced by a customer generator as that term is defined under GS 62-126.3, and specifies that term excludes the net monthly exports of energy by a customer under a tariff approved under GS 62-126.4.
Enacts new GS 62-126.4B providing that for any customer participating in an offering utility's net metering tariff or solar choice tariff, standby service is required for customers installing solar or other behind-the-meter generation with a nameplate generation capacity over 100 kW. Sets out the process for calculating the standby service costs for behind-the-meter generation with a planning capacity factor of less than 60%. Exempts from the authorized standby charge customers participating in a retail demand electric tariff in effect on or before July 1, 2021, or a customer who elects to take service under such retail demand tariff.
Requires the Commission, 120 days after the section’s effective date, to initiate a stakeholder process that includes representatives of the three specified entities, to give interested parties the chance to establish the rate to be paid by the electric public utilities in connection with the modification of certain existing power purchase agreements of small power producers (as defined) to present to the Commission that would: (1) provide 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 statutory contract term limits; and (2) establish capacity and energy rates to be paid by the electric public utilities that are designed to take into consideration the currently contracted capacity and energy rates, capacity and energy rates to be computed at the time the small power producer elects to exercise the option to amend their existing power purchase agreement; sets out issues that are to be considered in developing the rates. Requires the stakeholders to present their recommendations to the Commission with 180 days. Requires the Commission to approve the proposed rates and resulting amended power purchase agreements if the Commission finds that the proposed methodology: (1) reduces customer costs in the short term and over the life of the amended power purchase agreement, evaluated from the date of the amendment through to the end of the amended agreement; (2) fairly compensates small power producers that elect such treatment; and (3) is just and reasonable and in the public interest. Declares as appropriate, in the public interest and promoting of regulatory economy, for small power producers and the electric public utilities to negotiate amendments to the power purchase agreements of such small power producers in lieu of the aforementioned stakeholder process, if the intent and objectives of this section are accomplished through such negotiation. Also declares it to be appropriate, in the public interest, and promoting of regulatory economy, for small power producers and the electric public utilities to negotiate amendments to the power purchase agreements of such small power producers in lieu of the aforementioned stakeholder process, provided that the intent and objectives of this section are accomplished through such negotiation.
Includes a severability clause.
Changes the act’s titles.
Summary date: May 11 2021 - More information
Directs the North Carolina Policy Collaboratory at UNC-Chapel Hill (Collaboratory) to study emerging energy generation sources issues and trends, including small modular reactors and their development in the United States, projected costs, technology options, production capabilities, and deployment scenarios.
Appropriates $100,000 in nonrecurring funds from the General Fund to the UNC Board of Governors for the 2021-2022 fiscal year to be allocated to the Collaboratory to implement this study.
Effective July 1, 2021.
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