2023 New Hampshire Revised Statutes › Title XXXIV - Public Utilities › Chapter 374-F - Electric Utility Restructuring › Section 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.
(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.