ELECTRIC UTILITY RESTRUCTURING

RSA tit. XXXIV, ch. 374-F

in effect

RSA 374-F:1 Purpose.

374-F:1. Purpose. I. The most compelling reason to restructure the New Hampshire electric utility industry is to reduce costs for all consumers of electricity by harnessing the power of competitive markets. The overall public policy goal of restructuring is to develop a more efficient industry structure and regulatory framework that results in a more productive economy by reducing costs to consumers while maintaining safe and reliable electric service with minimum adverse impacts on the environment. Increased customer choice and the development of competitive markets for wholesale and retail electricity services are key elements in a restructured industry that will require unbundling of prices and services and at least functional separation of centralized generation services from transmission and distribution services. II. A transition to competitive markets for electricity is consistent with the directives of part II, article 83 of the New Hampshire constitution which reads in part: "Free and fair competition in the trades and industries is an inherent and essential right of the people and should be protected against all monopolies and conspiracies which tend to hinder or destroy it." Competitive markets should provide electricity suppliers with incentives to operate efficiently and cleanly, open markets for new and improved technologies, provide electricity buyers and sellers with appropriate price signals, and improve public confidence in the electric utility industry. III. The following interdependent policy principles are intended to guide the New Hampshire public utilities commission and the department of energy in implementing a statewide electric utility industry restructuring plan, in establishing interim stranded cost recovery charges, in approving each utility's compliance filing, in streamlining administrative processes to make regulation more efficient, and in regulating a restructured electric utility industry. In addition, these interdependent principles are intended to guide the New Hampshire general court and the department of environmental services and other state agencies in promoting and regulating a restructured electric utility industry. Source. 1996, 129:2, eff. May 21, 1996. 2021, 91:279, eff. July 1, 2021.

RSA 374-F:2 Definitions.

374-F:2. Definitions. In this chapter: I. "Commission" means the public utilities commission. I-a. "Default service" means electricity supply that is available to retail customers who are otherwise without an electricity supplier and are ineligible for transition service and is provided by electric distribution utilities under RSA 374-F:3, V or as an alterative, by municipal or county aggregators under RSA 53-E. I-b. "Department" means the department of energy. II. "Electricity suppliers" means suppliers of electricity generation services and includes actual electricity generators and brokers, aggregators, and pools that arrange for the supply of electricity generation to meet retail customer demand, which may be municipal or county entities. [Paragraph II-a effective Sept. 13, 2026.] II-a. "Advanced nuclear reactor" has the same meaning as that provided in 42 U.S.C. section 16271(b)(1), as amended from time to time. III. "FERC" means the Federal Energy Regulatory Commission. IV. "Stranded costs" means costs, liabilities, and investments, such as uneconomic assets, that electric utilities would reasonably expect to recover if the existing regulatory structure with retail rates for the bundled provision of electric service continued and that will not be recovered as a result of restructured industry regulation that allows retail choice of electricity suppliers, unless a specific mechanism for such cost recovery is provided. Stranded costs may only include costs of: (a) Existing commitments or obligations incurred prior to the effective date of this chapter; (b) Renegotiated commitments approved by the commission; (c) New mandated commitments approved by the commission, including any specific expenditures authorized for stranded cost recovery pursuant to any commission-approved plan to implement electric utility restructuring in the territory previously serviced by Connecticut Valley Electric Company, Inc.; (d) Costs approved for recovery by the commission in connection with the divestiture or retirement of Public Service Company of New Hampshire generation assets pursuant to RSA 369-B:3-a; and (e) All costs incurred as a result of fulfilling employee protection obligations pursuant to RSA 369-B:3-b. V. "Transition service" means electricity supply that is available to existing retail customers prior to each customer's first choice of a competitive electricity supplier and to others, as deemed appropriate by the commission. VI. "Demand response" means a reduction in the use of electricity by retail electricity energy customers in response to power grid needs, economic signals from their electricity supplier based on wholesale market prices, or time varying rates. VII. "Distributed energy resources" or "DER" means demand response, distributed generation, and distributed storage. VIII. "Distributed generation" or "DG" means a customer-generator as defined in RSA 362-A:1-a, II-b or a limited producer as defined in RSA 362-A:1-a, III, excluding qualifying storage systems and grid-interactive electric vehicles. IX. "Distributed storage" or "DS" means qualifying storage systems as defined in RSA 362-A:1-a, IX-a, grid-integrated electric vehicles when they are interconnected to a New Hampshire jurisdictional distribution grid behind a retail electric meter, or energy storage as defined in RSA 374-H:1, III, that are not participating in any wholesale energy markets administered by ISO New England as a registered asset or otherwise. X. "Grid-integrated electric vehicle" or "GIEV" means a battery-run motor vehicle that has the ability for 2-way power flow between the vehicle and the electric grid and the communications hardware and software that allow for the external control of battery charging and discharging by the electric utility customer, an electric distribution company, an electricity supplier, or an aggregator. XI. "Grid modernization" means improvements to electric distribution or transmission infrastructure, including related data analytics equipment, that are designed to accommodate or facilitate the integration of renewable electric generation resources with the electric distribution grid or to otherwise enhance electric distribution or transmission grid reliability, grid security, demand response capability, customer service or energy efficiency, or conservation and includes: (1) Advanced metering infrastructure that facilitates metering and providing related price signals to users to incentivize shifting demand and support transactive energy; (2) Intelligent grid devices for real time system and asset information at key substations and customer locations; (3) Automated control systems for electric distribution circuits and substations; (4) Communications networks for service meters; (5) Energy storage systems and microgrids that support circuit-level grid stability, power quality, reliability or resiliency or provide temporary backup energy supply; (6) Electrical facilities and infrastructure necessary to support electric vehicle charging systems; (7) Interconnection standards and procedures for state jurisdictional DG and DS connection to the distribution grid consistent with New Hampshire's energy policy in RSA 378:37 that reasonably balances reliability and safety risks with costs and benefits; and (8) Other new technologies that may be developed regarding the electric grid. XII. "Transactive energy" or "TE" means a system of economic and control mechanisms that allows the dynamic balance of supply and demand across the entire electrical infrastructure using value as a key operational parameter. [Paragraph II-a effective Sept. 13, 2026.] Source. 1996, 129:2. 1998, 191:3, 4. 2003, 56:2, eff. July 20, 2003. 2014, 310:4, eff. Sept. 30, 2014. 2019, 316:17, eff. Oct. 1, 2019. 2021, 91:280, eff. July 1, 2021. 2023, 243:3, eff. Oct. 7, 2023. 2026, 332:7, eff. Sept. 13, 2026.

RSA 374-F:3 Restructuring Policy Principles.

374-F:3. Restructuring Policy Principles. I. System Reliability. Reliable electricity service must be maintained while ensuring public health, safety, and quality of life. II. Customer Choice. Allowing customers to choose among electricity suppliers will help ensure fully competitive and innovative markets. Customers should be able to choose among options such as levels of service reliability, real time pricing, and generation sources, including interconnected self generation. Customers should expect to be responsible for the consequences of their choices. The department should ensure that customer confusion will be minimized and customers will be well informed about changes resulting from restructuring and increased customer choice. III. Regulation and Unbundling of Services and Rates. When customer choice is introduced, services and rates should be unbundled to provide customers clear price information on the cost components of generation, transmission, distribution, and any other ancillary charges. Generation services should be subject to market competition and minimal economic regulation and at least functionally separated from transmission and distribution services which should remain regulated for the foreseeable future. However, distribution service companies should not be absolutely precluded from owning small scale distributed generation resources as part of a strategy for minimizing transmission and distribution costs. Performance based or incentive regulation should be considered for transmission and distribution services. Upward revaluation of transmission and distribution assets is not a preferred mechanism as part of restructuring. Retail electricity suppliers who do not own transmission and distribution facilities, should, at a minimum, be registered with the department. IV. Open Access to Transmission and Distribution Facilities. Non-discriminatory open access to the electric system for wholesale and retail transactions should be promoted. The commission and the department should monitor companies providing transmission or distribution services and take necessary measures to ensure that no supplier has an unfair advantage in offering and pricing such services. V. Universal Service. (a) Electric service is essential and should be available to all customers. A utility providing distribution services must have an obligation to connect all customers in its service territory to the distribution system. A restructured electric utility industry should provide adequate safeguards to assure universal service. Minimum residential customer service safeguards and protections should be maintained. Programs and mechanisms that enable residential customers with low incomes to manage and afford essential electricity requirements should be included as a part of industry restructuring. (b) [Repealed.] (c) Default service should be designed to provide a safety net and to assure universal access and system integrity. Default service should be procured through the competitive market and may be administered by independent third parties. Any prudently incurred costs arising from compliance with the renewable portfolio standards of RSA 362-F for default service or purchased power agreements shall be recovered through the default service charge. The allocation of the costs of administering default service should be borne by the customers of default service in a manner approved by the commission. If the commission determines it to be in the public interest, the commission may implement measures to discourage misuse, or long-term use, of default service. Revenues, if any, generated from such measures should be used to defray stranded costs. (d) The commission should establish transition and default service appropriate to the particular circumstances of each jurisdictional utility. (e) Notwithstanding any provision of subparagraphs (b) and (c), as competitive markets develop, the commission may approve alternative means of providing transition or default services which are designed to minimize customer risk, not unduly harm the development of competitive markets, and mitigate against price volatility without creating new deferred costs, if the commission determines such means to be in the public interest. No reconciliation of actual and estimated wholesale power supply costs incurred by a utility to provide default service shall be recovered through a non-bypassable charge, except in extraordinary circumstances as found to exist by the commission through an adjudicative proceeding. (f)(1) For purposes of subparagraph (f), "renewable energy source" (RES) means a source of electricity, as defined in RSA 362-F:2, XV, that would qualify to receive renewable energy certificates under RSA 362-F, whether or not it has been designated as eligible under RSA 362-F:6, III. (2) A utility shall provide to its customers one or more RES options, as approved by the commission, which may include RES default service provided by the utility or the provision of retail access to competitive sellers of RES attributes. Costs associated with selecting an RES option should be paid for by those customers choosing to take such option. A utility may recover all prudently incurred administrative costs of RES options from all customers, as approved by the commission. (3) RES default service should have either all or a portion of its service attributable to a renewable energy source component procured by the utility, with any remainder filled by standard default service. The price of any RES default service shall be approved by the commission. (4) Under any option offered, the customer shall be purchasing electricity generated by renewable energy sources or the attributes of such generation, either in connection with or separately from the electricity produced. The regional generation information system of energy certificates administered by the ISO-New England and the New England Power Pool (NEPOOL) should be considered at least one form of certification that is acceptable under this program. (5) A utility that is required by statute to provide default service from its generation assets should use any of its owned generation assets that are powered by renewable energy for the provision of standard default service, rather than for the provision of a renewable energy source component. (6) Utilities should include educational materials in their normal communications to their customers that explain the RES options being offered and the health and environmental benefits associated with them. Such educational materials should be compatible with any environmental disclosure requirements established by the department. (7) For purposes of consumer protection and the maintenance of program integrity, reasonable efforts should be made to assure that the renewable energy source component of an RES option is not separately advertised, claimed, or sold as part of any other electricity service or transaction, including compliance with the renewable portfolio standards under RSA 362-F. (8) If RES default service is not available for purchase at a reasonable cost on behalf of consumers choosing an RES default service option, a utility may, as approved by the commission, make payments to the renewable energy fund created pursuant to RSA 362-F:10 on behalf of customers to comply with subparagraph (f). (9) The commission shall implement subparagraph (f) through utility-specific filings. Approved RES options shall be included in individual tariff filings by utilities. (10) A utility, with commission approval, may require that a minimum number of customers, or a minimum amount of load, choose to participate in the program in order to offer an RES option. VI. Benefits for All Consumers. Restructuring of the electric utility industry should be implemented in a manner that benefits all consumers equitably and does not benefit one customer class to the detriment of another. Costs should not be shifted unfairly among customers. VI-a. System Benefits Charge. (a) A nonbypassable and competitively neutral system benefits charge applied to the use of the distribution system may be used to fund public benefits related to the provision of electricity. This charge, as approved by regulators, may fund: (1) Energy efficiency programs. (2) Programs that promote and describe the consumer advantages of energy efficiency across all ratepayer classes. (3) The electric utility industry's share of commission and department expenses pursuant to RSA 363-A. (4) Support for research and development. (5) Investments in commercialization strategies for new and beneficial technologies. (6) Programs for low-income customers. (b) Up to $400,000 of system benefits charge funds collected annually shall be used to promulgate the benefits of energy efficiency according to guidelines developed as specified in RSA 12-P:2, V as determined by the department of energy. (c) No less than 20 percent of the portion of the funds collected for energy efficiency shall be expended on low-income energy efficiency programs. (d) Notwithstanding any subsequent commission order to the contrary, the joint utility energy efficiency plan and programming framework and components, including utility performance incentive payments, lost base revenue calculations, and Evaluation, Measurement, and Verification process that were in effect on January 1, 2021, shall remain in effect until changed by an order or operation of law as authorized in subparagraphs (3) and (5). The joint utilities shall continue to prepare triennial energy efficiency plans with programming and incentive payments at levels optimized to deliver ratepayer savings as made possible by the funding described as follows: (1) Energy efficiency program funding. The budget for joint energy efficiency planning shall be funded through the system benefits charge, local distribution adjustment charges, the energy efficiency fund established pursuant to RSA 125-O:23, revenues available from wholesale energy and ancillary services markets operated by ISO-New England, and energy efficiency carry-forward or carry-under balances detailed in the most recent Performance Incentive and Fund Balance reports; however, the joint utilities shall continue to seek alternative sources of funding to supplement the aforementioned funding sources. Total plan overspending shall be treated as a carry-under balance, and not as a charge to utility shareholders. (2) System benefits charge and local distribution adjustment charge funding levels. For the year 2022, the energy efficiency portion of the system benefits charge shall be set at the level for 2020 authorized in Order No. 26,323 dated December 31, 2019. The energy efficiency portion of the local distribution adjustment charge shall be set at the level for 2020 authorized in Order No. 26,306 dated October 31, 2019, for Liberty Utilities (Energy North Natural Gas) Corp. and in Order No. 26,303 dated October 29, 2019, for Northern Utilities, Inc. The energy efficiency portion of the system benefits charge and local distribution adjustment charges shall adjust annually beginning January 1, 2023, and shall be calculated using the most recently available 3-year average of the consumer price index (CPI-W) as published by the Bureau of Labor Statistics of the United States Department of Labor as determined and verified by the department of energy. Utilities subject to commission rate regulation shall submit tariff amendments altering solely the system benefits charge and local distribution adjustment charge as described, reconciled for over and under collections already occurred, as soon after the effective date of this subparagraph as possible, and every December 1 for the upcoming year thereafter. (3) 2022-23 plan filing. On March 1, 2022, the joint utilities shall petition the commission to approve any changes to current program offerings that will be available for the period between May 1, 2022, and January 1, 2024, consistent with the system benefits charge and local distribution adjustment charges described in subparagraph (2). The commission shall issue its order approving or denying the joint utility request to alter program offerings no later than May 1, 2022. If the commission fails to issue an order by May 1, 2022, the proposed alterations to programs and budgets shall be deemed approved, except for any changes in performance incentives and recovery of lost base revenues, which the commission shall promptly review and approve by order. If the commission denies a 3-year plan or interim program update, the most recent 3-year plan, as updated, shall remain in effect until the commission approves proposed changes to that plan or program update filing. (4) Cost effectiveness. For the purpose of the March 1, 2022 filing, and future plan offerings, the commission's review of the cost effectiveness shall be based upon the latest completed and available Avoided Energy Supply Cost Study for New England, the results of any Evaluation, Measurement, and Valuation studies contracted for by the department of energy or joint utilities, incorporate savings impacts associated with free-ridership for those programs and measures where such free-ridership may have a material impact on savings figures, and use the Granite State Test as the primary test, with the addition of the Total Resource Cost test as a secondary test. The commission shall use benefit per unit cost as only one factor in considering whether the utilities have prioritized program offerings appropriately among and within customer classes. In no instance shall an electric utility's planned electric system savings fall below 65 percent of its overall planned annual energy savings. (5) Subsequent plan and update filings. On July 1, 2023, the joint utilities shall petition the commission to approve changes to program offerings for the next 3-year period, consistent with the system benefits charge and local distribution adjustment charges described in subparagraph (2). The commission shall issue its order approving or denying a joint utility request to alter program offerings no later than November 30, 2023. Any utility or party may petition the commission to approve interim program updates prior to the next 3-year planning period on July 1 of any year during which a 3-year plan is not filed. The commission shall issue its order approving or denying the interim program updates by the following November 30. If the commission fails to issue an order on either a 3-year plan or an interim program update during the year in which a petition is filed, the proposed alterations to programs and budgets shall be deemed approved except for changes in performance incentives and recovery of lost base revenues, which the commission shall promptly review and approve by order. If the commission denies a 3-year plan or interim program update, the most recent 3-year plan, as updated, shall remain in effect until the commission approves proposed changes to that plan or program update filing. The joint utilities shall present a joint energy efficiency plan to the commission for review and approval no less frequently than every 3 years. Up to 5 percent of the overall program budget shall be expended on Evaluation, Measurement, and Verification studies, which the department or joint utilities shall contract for as the department deems necessary to assure program funds are optimized to deliver ratepayer savings and to secure funds available from wholesale energy and ancillary services markets. VII. Full and Fair Competition. Choice for retail customers cannot exist without a range of viable suppliers. The rules that govern market activity should apply to all buyers and sellers in a fair and consistent manner in order to ensure a fully competitive market. VIII. Environmental Improvement. Continued environmental protection and long term environmental sustainability should be encouraged. Increased competition in the electric industry should be implemented in a manner that supports and furthers the goals of environmental improvement. Over time, there should be more equitable treatment of old and new generation sources with regard to air pollution controls and costs. New Hampshire should encourage equitable and appropriate environmental regulation, based on comparable criteria, for all electricity generators, in and out of state, to reduce air pollution transported across state lines and to promote full, free, and fair competition. As generation becomes deregulated, innovative market-driven approaches are preferred to regulatory controls to reduce adverse environmental impacts. Such market approaches may include valuing the costs of pollution and using pollution offset credits. IX. Renewable Energy Resources. Increased future commitments to renewable energy resources should be consistent with the New Hampshire energy policy as set forth in RSA 378:37 and should be balanced against the impact on generation prices. Over the long term, increased use of cost-effective renewable energy technologies can have significant environmental, economic, and security benefits. To encourage emerging technologies, restructuring should allow customers the possibility of choosing to pay a premium for electricity from renewable resources and reasonable opportunities to directly invest in and interconnect decentralized renewable electricity generating resources. X. Energy Efficiency. Restructuring should be designed to reduce market barriers to investments in energy efficiency and provide incentives for appropriate demand-side management and not reduce cost-effective customer conservation. Utility sponsored energy efficiency programs should target cost-effective opportunities that may otherwise be lost due to market barriers. XI. Near Term Rate Relief. The goal of restructuring is to create competitive markets that are expected to produce lower prices for all customers than would have been paid under the current regulatory system. Given New Hampshire's higher than average regional prices for electricity, utilities, in the near term, should work to reduce rates for all customers. To the greatest extent practicable, rates should approach competitive regional electric rates. The state should recognize when state policies impose costs that conflict with this principle and should take efforts to mitigate those costs. The unique New Hampshire issues contributing to the highest prices in New England should be addressed during the transition, wherever possible. XII. Recovery of Stranded Costs. (a) It is the intent of the legislature to provide appropriate tools and reasonable guidance to the commission in order to assist it in addressing claims for stranded cost recovery and fulfilling its responsibility to determine rates which are equitable, appropriate, and balanced and in the public interest. In making its determinations, the commission shall balance the interests of ratepayers and utilities during and after the restructuring process. Nothing in this section is intended to provide any greater opportunity for stranded cost recovery than is available under applicable regulation or law on the effective date of this chapter. (b) Utilities should be allowed to recover the net nonmitigatable stranded costs associated with required environmental mandates currently approved for cost recovery, and power acquisitions mandated by federal statutes or RSA 362-A. (c) Utilities have had and continue to have an obligation to take all reasonable measures to mitigate stranded costs. Mitigation measures may include, but shall not be limited to: (1) Reduction of expenses. (2) Renegotiation of existing contracts. (3) Refinancing of existing debt. (4) A reasonable amount of retirement, sale, or write-off of uneconomic or surplus assets, including regulatory assets not directly related to the provision of electricity service. (d) Stranded costs should be determined on a net basis, should be verifiable, should not include transmission and distribution assets, and should be reconciled to actual electricity market conditions from time to time. Any recovery of stranded costs should be through a nonbypassable, nondiscriminatory, appropriately structured charge that is fair to all customer classes, lawful, constitutional, limited in duration, consistent with the promotion of fully competitive markets and consistent with these principles. Entry and exit fees are not preferred recovery mechanisms. Charges to recover stranded costs should only apply to customers within a utility's retail service territory, except for such costs that have resulted from the provision of wholesale power to another utility. The charges should not apply to wheeling-through transactions. XIII. Regionalism. New England Power Pool (NEPOOL) should be reformed and efforts to enhance competition and to complement industry restructuring on a regional basis should be encouraged. New Hampshire should work with other New England and northeastern states to accomplish the goals of restructuring. Working with other regional states, New Hampshire should assert maximum state authority over the entire electric industry restructuring process. While it is desirable to design and implement a restructured industry in concert with the other New England and northeastern states, New Hampshire should not unnecessarily delay its timetable. Any pool structure adopted for the restructured industry should not preclude bilateral contracts with pool and non-pool services and should not preclude ancillary pool services from being obtained from non-pool sources. XIV. Administrative Processes. The commission and the department should adapt their administrative processes to make regulation more efficient and to enable competitors to adapt to changes in the market in a timely manner. The market framework for competitive electric service should, to the extent possible, reduce reliance on administrative process. New Hampshire should move deliberately to replace traditional planning mechanisms with market driven choice as the means of supplying resource needs. XV. Timetable. The commission should seek to implement full customer choice among electricity suppliers in the most expeditious manner possible, but may delay such implementation in the service territory of any electric utility when implementation would be inconsistent with the goal of near-term rate relief, or would otherwise not be in the public interest. Source. 1996, 129:2. 1998, 191:5. 2000, 249:3. 2001, 29:5, 6. 2002, 212:6; 268:4. 2006, 294:3. 2007, 26:4, eff. July 10, 2007. 2009, 236:1, eff. Nov. 13, 2009. 2018, 374:1, eff. Oct. 2, 2018. 2019, 346:77, eff. July 1, 2019. 2021, 91:281, eff. July 1, 2021. 2022, 5:1, eff. Jan. 1, 2022; 245:27, 34, V, eff. Aug. 20, 2022. 2023, 162:1, 2, eff. Sept. 26, 2023; 233:5, eff. Oct. 7, 2023. 2026, 147:1, eff. June 16, 2026.

RSA 374-F:4 Implementation.

374-F:4. Implementation. I. The commission is authorized to require the implementation of retail choice of electric suppliers for all customer classes of utilities providing retail electric service under its jurisdiction. The commission shall require such implementation at the earliest date determined to be in the public interest by the commission. However, in no event may the implementation be delayed beyond July 1, 1998 without legislative approval or a finding of public interest by the commission that delay is required due to events beyond the control of the commission or that implementation of retail choice within the service territory of any electric utility would be inconsistent with the goal of near-term rate relief or would otherwise not be in the public interest. In the event that implementation of retail choice is delayed in the service territory of an electric utility, the electric utility shall continue to provide reliable retail service at the lowest reasonable cost in accordance with state law. In addition, at the earliest practical date, the commission should make effective the unbundling of components of rates into at least distribution, transmission, and generation for each jurisdictional utility. II. Upon the effective date of this chapter, the commission shall undertake a generic proceeding to develop a statewide industry restructuring plan in accordance with the above principles, and shall, after public hearings, issue a final order no later than February 28, 1997. In its order, the commission shall establish the interim stranded cost recovery charge for each electric utility as provided in paragraph VI. III. [Repealed.] IV. A utility having less than a 50 percent share of statewide retail electric distribution sales (measured in kilowatt hours per year) may seek a ruling by the commission that it is in the public interest that implementation of such utility's compliance filing be deferred until compliance filings representing 70 percent of retail electric sales have been or are being implemented. V. The commission is authorized to allow utilities to collect a stranded cost recovery charge, subject to its determination in the context of a rate case or adjudicated settlement proceeding that such charge is equitable, appropriate, and balanced, is in the public interest, and is substantially consistent with these interdependent principles. The burden of proof for any stranded cost recovery claim shall be borne by the utility making such claim. VI. (a) In order to facilitate the rapid transition to full competition, the commission is authorized, in its generic restructuring order as provided in paragraph II, to set, without a formal rate case proceeding, an interim stranded cost recovery charge for each electric utility. Such interim stranded cost recovery charges shall be effective for not more than 2 years from the implementation of utility compliance filings and shall be based on the commission's preliminary determination of an equitable, appropriate, and balanced measure of stranded cost recovery that takes into account the near term rate relief principle, is in the public interest, and is substantially consistent with these interdependent principles. The commission shall also consider the potential for future rate impacts due to possible differences between interim stranded cost recovery charges and charges that may finally be approved for stranded cost recovery. (b) Any utility may seek adjustment of the interim stranded cost recovery charge at any time based on severe financial hardship, as determined by the commission. The setting of an interim stranded cost recovery charge shall establish no legal, factual, or policy precedent with respect to the final determination of stranded cost recovery by the commission in any subsequent administrative or judicial proceeding. VII. The interim stranded cost recovery charge established for a utility as provided in paragraph VI may also be adjusted based upon the outcome of rate case proceedings to adjudicate claims for stranded cost recovery pursuant to paragraph V of this section. Any amounts approved by the commission for stranded cost recovery shall be net of amounts previously collected through interim stranded cost recovery charges. VIII. (a) The commission is authorized to order such charges and other service provisions and to take such other actions that are necessary to implement restructuring and that are substantially consistent with the principles established in this chapter. The commission is authorized to require that distribution and electricity supply services be provided by separate affiliates. (b) [Repealed.] (c) Notwithstanding any other provision of law to the contrary, the system benefits charge shall include 1.5 mills per kilowatt-hour to fund an electricity assistance program for low-income customers. The department of energy shall be the agency with authority over any such program. The department of energy may, using a non-adjudicative hearing process, order among other things, eligibility tiers, benefit levels, administrative budgets, expenditures, and modification of any such program. Authority over the low-income assistance program funded through the system benefits charge and implemented by the public utilities commission prior to July 1, 2025, along with the commission orders creating and implementing that program, are transferred to the department of energy to be administered in conformity with this paragraph. If the department of energy determines that the low-income program fund has accumulated an excess of $1,000,000 and that the excess is not likely to be substantially reduced over the next 12 months, it may, using non-adjudicative procedures, suspend by order the collection of some or all of this portion of the system benefits charge for a period of time it deems reasonable to reduce the program fund to the level necessary to achieve the programs' purposes. Actions taken using a non-adjudicative hearing process shall be by written decision of the department, in which the department shall state its reasons for the actions taken. (d) [Repealed.] (e) Targeted conservation, energy efficiency, and load management programs and incentives that are part of a strategy to minimize distribution costs may be included in the distribution charge or the system benefits charge, provided that system benefits charge funds are only used for customer-based energy efficiency measures, and such funding shall not exceed 10 percent of the energy efficiency portion of a utility's annual system benefits charge funds. A proposal for such use of system benefits charge funds shall be presented to the commission for approval. Any such approval shall initially be on a pilot program basis and the results of each pilot program proposal shall be subject to evaluation by the commission. (f) The department of energy shall submit a report to the house science, technology, and energy committee, and the senate energy and natural resources committee by October 1 of each year. The report shall concern the results and effectiveness of the system benefits charge. (g) [Repealed.] VIII-a. Any electric utility that collects funds for energy efficiency programs that are subject to the commission's approval, shall include in its plans to be submitted to the commission program design, and/or enhancements, and estimated participation that maximize energy efficiency benefits to public schools, including measures that help enhance the energy efficiency of public school construction or renovation projects that are designed to improve indoor air quality. The report required under RSA 374-F:4, VIII(f) shall include the results and effectiveness of the energy efficiency programs for schools and, in addition to other requirements, be submitted to the commissioner of the department of education. IX. An electricity supplier shall be eligible to compete, subject to necessary limitations established by the commission, for open access customers only if affiliated utilities file comparable open access transmission and distribution rates with the FERC or the commission, or both as appropriate, for all of their transmission facilities in New Hampshire and to the extent practicable, all of their distribution facilities in New Hampshire. X. Nothing in this chapter shall be construed to prohibit the commission from otherwise exercising its lawful authority under title 34, in proceedings which relate to the introduction of competition in the retail electric utility industry including the retention of experts and consultants to assist the commission in its investigations and the assessment of such costs against utilities and any other parties to the proceedings, consistent with RSA 365:37 and RSA 365:38. XI. Any administrative or adjudicative proceeding or public hearing relating to this chapter shall be subject to the provisions of RSA 541-A. XII. To the extent that the provisions of this chapter are applicable to rural electric cooperatives for which a certificate of deregulation is on file with the commission, the commission shall exercise its authority with regard to such deregulated rural electric cooperatives only when and to the extent that the commission finds, after notice and hearing, that such action is required to ensure that such deregulated rural electric cooperatives do not act in a manner which is inconsistent with the restructuring policy principles of RSA 374-F:3. The commission shall have the authority to require that such deregulated rural electric cooperatives participate in proceedings, answer commission and department for information and file such reports as may be reasonably necessary to permit the commission to make an informed finding concerning the relevant restructuring policy principle actions of such deregulated rural electric cooperatives. Absent such a finding by the commission, the active role of assuring that the restructuring policy principles are appropriately addressed within their service territories shall be reserved to the deregulated rural electric cooperatives. Notwithstanding the foregoing, deregulated rural electric cooperatives shall be subject to the commission's jurisdiction with regard to those provisions of RSA 374-F pertaining to stranded cost recovery, customer choice, open access tariffs, default service, energy efficiency, and low income programs to the same extent as other public utilities. Source.Source. 1996, 129:2. 1997, 298:28. 1998, 191:6; 262:2. 1999, 289:6-9. 2000, 249:4. 2001, 29:12. 2002, 212:7. 2004, 164:1. 2005, 102:2; 228:3. 2007, 208:1, eff. Aug. 24, 2007. 2009, 236:3, 4, I-III, eff. July 16, 2009. 2018, 253:5, eff. Aug. 11, 2018. 2021, 91:251, II, 281, eff. July 1, 2021. 2022, 137:4, eff. Aug. 6, 2022; 346:3, eff. Sept. 15, 2022. 2023, 79:110, eff. July 1, 2023; 181:1, eff. Oct. 3, 2023. 2025, 133:3, eff. Aug. 23, 2025.

RSA 374-F:4-b Ratepayer Protection.

374-F:4-b. Ratepayer Protection. I. Within 60 days of the effective date of this section, the department of energy shall initiate a proceeding to develop rules to allow residential and small commercial customers to choose how they receive communication from competitive electric suppliers and to implement the provisions of this section. Where the department has adopted rules in conformity with this section, complaints to and proceedings before the department shall not be subject to RSA 541-A:29 or RSA 541-A:29-a. II. The department of energy shall enable residential and small commercial customers to compare standard pricing policies and charges and to require competitive electric suppliers to input such information on the department's website. Such information shall be input no less frequently than once per month, unless there is no change in such information. III. The department of energy shall review its website every 2 years and ensure that the site remains an efficient tool for the comparison of pricing policies and charges among competitive electric suppliers. IV. Unless the contract specifies a month-to-month variable rate, no competitive electric supplier shall charge a residential customer a variable rate, including during a contract term or following the expiration of a contract, without first providing written notification in a form approved by the department of energy of the nature of such variable rate 45 days prior to the commencement of the variable rate. The residential customer shall select the method of written notification at the time the contract is signed. Such customer shall have the option to change the method of notification at any time during the contract. V. Competitive electric suppliers shall retain records of any of the notices required in this section for a period of not less than 2 years and shall make such records available to the department of energy upon its request. Source. 2015, 268:1, eff. July 20, 2015. 2018, 279:19, eff. Jan. 1, 2019. 2021, 91:282, eff. July 1, 2021. 2022, 245:28, eff. Aug. 20, 2022. 2025, 294:1, eff. Sept. 30, 2025.

RSA 374-F:7 Competitive Electricity Supplier Requirements.

374-F:7. Competitive Electricity Supplier Requirements. I. Competitive energy suppliers are not public utilities pursuant to RSA 362:2, though a competitive energy supplier may seek public utility status from the department if it so chooses. Notwithstanding a competitive energy supplier's non-utility status, the department is authorized to establish requirements, excluding price regulation, for competitive electricity suppliers, including registration, registration fees, customer information, disclosure, standards of conduct, and consumer protection and assistance requirements. Unless electing to do so, an electricity supplier that offers or sells at retail to consumers within this state products and services that can lawfully be made available to such consumers by more than one supplier shall not, because of such offers or sales, be deemed to be a public utility as defined by RSA 362:2. These requirements shall be applied in a manner consistent with the restructuring principles of this chapter to promote competition among electricity suppliers. II. Aggregators of electricity load that do not take ownership of power or other services and do not represent any supplier interest are not public utilities pursuant to RSA 362:2, but shall notify the department of their intent to do business. Municipalities that aggregate electric power or energy services for their citizens pursuant to RSA 53-E are not public utilities pursuant to RSA 362:2 and are not subject to the provisions of paragraph III and RSA 374-F:4-b. III. The department may investigate and petition the commission to assess fines against, revoke the registration of, order the rescission of contracts with residential customers of, order restitution to the residential customers of, and prohibit from doing business in the state any competitive electricity supplier, including any aggregator or broker, which is found to have: (a) Engaged in any unfair or deceptive acts or practices in the marketing, sale, or solicitation of electricity supply or related services; (b) Violated the requirements of this section or any other provision of this title applicable to competitive electricity suppliers; or (c) Violated any rule adopted by the department pursuant to paragraph V and RSA 374-F:4-b. IV. As a condition of operation, for a 2-year interim period from the date that competition is implemented in one or more areas of the state, competitive energy suppliers and load aggregators shall submit to the jurisdiction of the commission for mediation and resolution of disputes between customers and competitive energy suppliers or aggregators. Municipalities that aggregate electric power or energy service for their citizens pursuant to RSA 53-E are not subject to this paragraph. V. The department shall adopt rules, under RSA 541-A, to implement this section. Where the department has adopted rules in conformity with this section, complaints to and proceedings before the commission shall not be subject to RSA 541-A:29 or RSA 541-A:29-a. Source. 1997, 298:19. 2007, 26:5, eff. July 10, 2007. 2010, 336:2, eff. Oct. 18, 2010. 2015, 268:2, eff. July 20, 2015. 2018, 279:20, eff. Jan. 1, 2019. 2019, 316:18, eff. Oct. 1, 2019. 2021, 91:284, eff. July 1, 2021.

RSA 374-F:8 Participation in Regional Activities.

374-F:8. Participation in Regional Activities. The department shall advocate for New Hampshire interests before the Federal Energy Regulatory Commission and other regional and federal bodies. The commission shall participate in the activities of the New England Conference of Public Utility Commissioners, and the National Association of Regulatory Utility Commissioners as the New Hampshire member agency, and the department shall participate in the activities of the New England States Committee on Electricity, or other similar organizations as the New Hampshire member agency, and work with the New England Independent System Operator and NEPOOL to advance the interests of New Hampshire with respect to wholesale electric issues, including policy goals relating to fuel diversity, renewable energy, and energy efficiency, and to assure nondiscriminatory open access to a safe, adequate, and reliable transmission system at just and reasonable prices. Employees of the commission and the department are not otherwise prohibited from participating in the activities of the aforementioned organizations in which the other agency has the lead role. The department shall advocate against proposed regional or federal rules or policies that are inconsistent with the policies, rules, or laws of New Hampshire. In its participation in regional activities, the commission and the department shall consider how other states' policies will impact New Hampshire rates and work to prevent or minimize any rate impact the commission or department determines to be unjust or unreasonable. Source. 2001, 29:7. 2007, 364:2, eff. July 17, 2007. 2018, 376:1, eff. Oct. 2, 2018. 2021, 91:284, eff. July 1, 2021. 2022, 245:30, eff. Aug. 20, 2022.

RSA 374-F:9 Investments by Electric Distribution Companies in Natural Gas.

374-F:9. Investments by Electric Distribution Companies in Natural Gas. An electric distribution company shall not engage in the acquisition of natural gas capacity or supply, or purchase interests in natural gas infrastructure or the siting thereof, at the expense or financial risk of its ratepayers. Source. 2019, 94:2, eff. Aug. 18, 2019.

RSA 374-F:11 Purchased Power Agreements.

374-F:11. Purchased Power Agreements. [Paragraph I(intro. par.) effective until September 13, 2026; see also paragraph I(intro. par.) set out below.] I. Investor-owned electric distribution utilities may elect to develop and, no later than June 30, 2025, issue a request for proposals for multi-year agreements for energy, in conjunction with or independent of any attendant environmental attributes from electric energy sources. [Paragraph I(intro. par.) effective September 13, 2026; see also paragraph I(intro. par.) set out above.] I. Investor-owned electric distribution utilities may elect to develop and, no later than June 30, 2040, issue a request for proposals for multi-year agreements for energy, in conjunction with or independent of any attendant environmental attributes from electric energy sources. (a) The electric distribution utilities may issue requests for proposals alone or in conjunction with another New Hampshire utility or utilities, or with out of state utilities subject to consultation with the department of energy and the office of the consumer advocate with resulting contracts approved by the public utilities commission. (b) Any costs associated with transmission system upgrades required for interconnecting new or incremental electric energy sources shall be included in responses to the request for proposals and power purchase agreements. (c) Electric distribution utilities shall consult with the department of energy and the office of the consumer advocate on all issues related to such requests for proposals, prior to issuance, including the criteria and scoring to be used in the review of responses to the request for proposals. The department and the office of the consumer advocate shall provide any such consultation within 60 days from the date each draft request for proposals is provided for its review. Within this period the utilities shall solicit public comment. (d) The department of energy may hire consultants to aid in the development of requests for proposals and assess the costs of such consultants to the relevant distribution electric utility or utilities as appropriate and equitable on a case-by-case basis. The department shall not enter into any contract under this section in an amount greater than $10,000, including any contract extension, without the approval of the governor and council. (e) Electric distribution utilities shall engage an independent third party to create appropriate request for proposals and to perform cost benefit analysis of any agreements received in response to the request for proposals. Such analysis shall be provided to the commission as part of the utilities' petition for approval of any purchase power agreements resulting from the request for proposals process. (f) Each investor-owned electric distribution utility may propose more than one agreement, with varying lengths and terms, alone or in conjunction with another utility or utilities, resulting from these requests for proposals, provided that: (1) Agreements shall not exceed 20 years in length. (2) Collectively among all investor-owned electric distribution utilities, agreements will be eligible for approval for up to a total not to exceed 2 million megawatt hours, annually, apportioned to each investor-owned electric distribution utility based upon kWh sales to ultimate customers as reported on the utilities' FERC Form 1. No electric distribution utility may contract in excess of its apportionment. [Paragraph I(g) effective until September 13, 2026; see also paragraph I(g) set out below.] (g) All megawatt hours procured through agreements made pursuant to this section shall come from new or incremental electric energy sources. [Paragraph I(g) effective September 13, 2026; see also paragraph I(g) set out above.] (g) All megawatt hours procured through agreements made pursuant to this section shall come from existing, new, or incremental electric energy sources. (h) For the purposes of this section: (1) "New electric energy sources" are those that are able to provide additional energy into the ISO-NE regional market that first began commercial operation on or after September 1, 2023. (2) "Incremental electric energy sources" are those that as a result of new construction on or after September 1, 2023, are capable of providing additional energy into the ISO-NE regional market. [Paragraphs I(h)(3)-(5) effective Sept. 13, 2026.] (3) "Existing electric energy sources" means all sources that currently provide energy to the ISO-NE regional markets, including nuclear power generation facilities located in the ISO-NE control area that commenced commercial operation before January 1, 2011. (4) Upon the petition of one or more electric distribution utilities, and after notice and hearing, the public utilities commission may authorize such utility or utilities to enter into multi-year agreements with existing, new, or incremental electric energy sources up to a total of 3 million megawatt hours statewide, on an annual basis, if it finds such agreements to be just and reasonable and in the public interest. (5) Further, any single source shall be eligible to procure an amount of energy not to exceed 1 million megawatt hours statewide, on an annual basis, except for advanced nuclear reactors as defined in RSA 374-F:2, II-a, which may procure an amount not to exceed 2 million megawatt hours on an annual basis. (i) Electric distribution utilities shall recover any prudently incurred costs related to complying with this section through distribution rates. [Paragraphs II(intro. par.) and II(a) effective until September 13, 2026; see also paragraphs II(intro. par.) and II(a) set out below.] II. Any investor-owned electric distribution utility electing to enter into an agreement pursuant to this section shall petition the public utilities commission for authorization to enter the agreement no later than June 30, 2026. (a) Upon the petition of one or more electric distribution utilities, and after notice and hearing, the public utilities commission may authorize such utility or utilities to enter into multi-year agreements with new or incremental electric energy sources up to a total of 2 million megawatt hours statewide, on an annual basis, if it finds such agreements to be just and reasonable and in the public interest. [Paragraphs II(intro. par.) and II(a) effective September 13, 2026; see also paragraphs II(intro. par.) and II(a) set out above.] II. Any investor-owned electric distribution utility electing to enter into an agreement pursuant to this section shall petition the public utilities commission for authorization to enter the agreement no later than June 30, 2041. (a) Upon the petition of one or more electric distribution utilities, and after notice and hearing, the public utilities commission may authorize such utility or utilities to enter into multi-year agreements with new or incremental electric energy sources up to a total of 2 million megawatt hours statewide, on an annual basis, if it finds such agreements to be just and reasonable and in the public interest, provided that if at least 1 million megawatt hours are procured from advanced nuclear reactors as defined in RSA 374-F:2, II-a, an additional 1 million megawatt hours may be procured from existing, new, or incremental electric energy sources for a total of up to 3 million megawatt hours statewide annually. (b) The public utilities commission shall review and render a decision on any proposed agreement no later than 9 months after submission of the agreement with the commission. III. In reviewing agreements under this section, the public utilities commission shall consider whether each agreement is, on balance, substantially consistent with the following factors: (a) Cost-effective to electric ratepayers in New Hampshire over the term of the agreement. (b) Creates or supports electric energy sources that are expected to be available during long duration weather events. (c) Fosters price stability and helps reduces exposure to market volatility. (d) Supports the diversification of New Hampshire's electric energy sources. (e) Contains ratepayer protections, which may include such mechanisms as performance incentives, penalties for non-performance, or others as proposed by the utility and determined by the commission to be in the best interest of ratepayers. (f) Any other factors necessary to determine whether the agreement is just and reasonable and in the public interest. IV. Upon receiving public utilities commission approval of an agreement to purchase electric energy, in conjunction with or independent of any attendant environmental attributes, an investor-owned electric distribution utility shall sell such purchased energy into the wholesale market in the manner to minimize costs and maximize benefits to ratepayers. When the electric distribution utility sells into the wholesale market, it shall: (a) Calculate the net cost of payments made under the agreements against the proceeds obtained from the sale of the energy and any environmental attributes. (b) Credit or charge all their distribution ratepayers the difference between the agreement payments and proceeds through a uniform, fully-reconciling annual factor in rates. V. To the extent any proposed agreement to purchase electric energy includes environmental attributes, such as renewable energy credits, the public utilities commission shall approve how such environmental attributes are used or disposed of in a manner expected to minimize costs and maximize benefits to ratepayers. VI. Any rural electric cooperative for which a certificate of deregulation is on file with the department of energy may participate in competitive solicitations for energy or environmental attributes on its own or in conjunction with an investor-owned utility or utilities, but shall not be required to develop or issue requests for proposals or seek authorization for multi-year purchased power agreements under this section. Investor-owned electric distribution utilities, shall, however, be required to consult with the department of energy on any jointly-issued request for proposals and to obtain approval of any contract entered into jointly with a rural electric cooperative. [Paragraph I(intro. par.) effective until September 13, 2026; see also paragraph I(intro. par.) set out below.] [Paragraph I(intro. par.) effective September 13, 2026; see also paragraph I(intro. par.) set out above.] [Paragraph I(g) effective until September 13, 2026; see also paragraph I(g) set out below.] [Paragraph I(g) effective September 13, 2026; see also paragraph I(g) set out above.] [Paragraphs I(h)(3)-(5) effective Sept. 13, 2026.] [Paragraphs II(intro. par.) and II(a) effective until September 13, 2026; see also paragraphs II(intro. par.) and II(a) set out below.] [Paragraphs II(intro. par.) and II(a) effective September 13, 2026; see also paragraphs II(intro. par.) and II(a) set out above.] Source. 2023, 204:2, eff. Oct. 3, 2023. 2026, 332:8-10, eff. Sept. 13, 2026.

Source: New Hampshire General Court (gc.nh.gov)URL: https://gc.nh.gov/rsa/html/NHTOC/NHTOC-XXXIV-374-F.htmFetched: 10/20/2026