2024 -- S 2956

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LC005194

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     STATE OF RHODE ISLAND

IN GENERAL ASSEMBLY

JANUARY SESSION, A.D. 2024

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A N   A C T

RELATING TO PUBLIC UTILITIES AND CARRIERS -- PUBLIC UTILITIES COMMISSION

     Introduced By: Senators Euer, DiMario, Gu, Sosnowski, Valverde, Murray, Cano,
Kallman, and Mack

     Date Introduced: April 05, 2024

     Referred To: Senate Environment & Agriculture

     It is enacted by the General Assembly as follows:

     SECTION 1. Sections 39-1-1, 39-1-27.6 and 39-1-27.7.1 of the General Laws in Chapter

39-1 entitled "Public Utilities Commission" are hereby amended to read as follows:

     39-1-1. Declaration of policy — Purposes.

     (a) The general assembly finds and therefore declares that:

     (1) The businesses of distributing electrical energy, producing and transporting

manufactured and natural gas, operating water works and furnishing supplies of water for domestic,

industrial, and commercial use, offering to the public transportation of persons and property,

furnishing and servicing telephonic and wireless audio and visual communication systems, and

operation of community antenna television systems are affected with a public interest;

     (2) Supervision and reasonable regulation by the state of the manner in which the

businesses construct their systems and carry on their operations within the state are necessary to

protect and promote the convenience, health, comfort, safety, accommodation, and welfare of the

people, and are a proper exercise of the police power of the state; and

     (3) Preservation of the state’s resources, commerce, and industry requires the assurance of

adequate public transportation and communication facilities, water supplies, and an abundance of

energy, all supplied to the people with reliability, at economical cost, and with due regard for the

preservation and enhancement of the environment, the conservation of natural resources, including

scenic, historic, and recreational assets, and the strengthening of long-range, land-use planning.

     (b) It is hereby declared to be the policy of the state to provide fair regulation of public

utilities and carriers in the interest of the public, to promote availability of adequate, efficient, and

economical energy, communication, and transportation services and water supplies to the

inhabitants of the state, to provide just and reasonable rates and charges for such services and

supplies, without unjust discrimination, undue preferences or advantages, or unfair or destructive

competitive practices, and to cooperate with other states and agencies of the federal government in

promoting and coordinating efforts to achieve realization of this policy.

     (c) To this end, there is hereby vested in the public utilities commission and the division of

public utilities and carriers the exclusive power and authority to supervise, regulate, and make

orders governing the conduct of companies offering to the public in intrastate commerce energy,

communication, and transportation services and water supplies for the purpose of increasing and

maintaining the efficiency of the companies, according desirable safeguards and convenience to

their employees and to the public, and protecting them and the public against improper and

unreasonable rates, tolls, and charges by providing full, fair, and adequate administrative

procedures and remedies, and by securing a judicial review to any party aggrieved by such an

administrative proceeding or ruling.

     (d) The legislature also finds and declares, as of 1996, the following:

     (1) That lower retail electricity rates would promote the state’s economy and the health and

general welfare of the citizens of Rhode Island;

     (2) That current research and experience indicates that greater competition in the electricity

industry would result in a decrease in electricity rates over time;

     (3) That greater competition in the electricity industry would stimulate economic growth;

     (4) That it is in the public interest to promote competition in the electricity industry and to

establish performance-based ratemaking for regulated utilities;

     (5) That in connection with the transition to a more competitive electric utility industry,

public utilities should have a reasonable opportunity to recover transitional costs associated with

commitments prudently incurred in the past pursuant to their legal obligations to provide reliable

electric service at reasonable costs;

     (6) That it shall be the policy of the state to encourage, through all feasible means and

measures, states where fossil-fueled, electric-generating units producing air emissions affecting

Rhode Island air quality are located to reduce such emissions over time to levels that enable cost-

effective attainment of environmental standards within Rhode Island; and

     (7) That in a restructured electrical industry the same protections currently afforded to low-

income customers shall continue.

     (e) The legislature further finds and declares as of 2006:

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     (1) That prices of energy, including especially fossil-fuels and electricity, are rising faster

than the cost of living and are subject to sharp fluctuations, which conditions create hardships for

many households, institutions, organizations, and businesses in the state;

     (2) That while utility restructuring has brought some benefits, notably in transmission and

distribution costs and more efficient use of generating capacities, it has not resulted in competitive

markets for residential and small commercial-industrial customers, lower overall prices, or greater

diversification of energy resources used for electrical generation;

     (3) That the state’s economy and the health and general welfare of the people of Rhode

Island benefit when energy supplies are reliable and least-cost; and

     (4) That it is a necessary move beyond basic utility restructuring in order to secure for

Rhode Island, to the maximum extent reasonably feasible, the benefits of reasonable and stable

rates, least-cost procurement, and system reliability that includes energy resource diversification,

distributed generation, and load management.

     (f) In discharging its responsibilities under this chapter, the public utilities commission

shall, with respect to itself and the entities it regulates, prioritize safety, security, reliability of

service, affordability, equity, environmental justice, and reductions in greenhouse gas emissions to

meet statewide greenhouse gas emission limits established pursuant to § 42-6.2-2.

     39-1-27.6. Standards of conduct.

     (a) An electric distribution company must conduct its business to conform with the

standards of conduct specified in subsections (b) through (e).

     (b)(1) Except as provided in subsection (b)(2) and as authorized by the commission

pursuant to § 39-1-27(g), the employees of the electric distribution company engaged in

distribution-system operations must function independently of its employees, or the employees of

any of its affiliates, who are engaged in the business of a nonregulated power producer.

     (2) Notwithstanding any other provisions in this section, in emergency circumstances

affecting system reliability, electric distribution companies may take whatever steps are necessary

to keep the system in operation. Electric distribution companies must report to the commission each

emergency that resulted in any deviation from the standards of conduct, within twenty-four (24)

hours of such deviation.

     (c)(1) Any employee of any affiliate of an electric distribution company who is engaged in

the business of a nonregulated power producer is prohibited from: conducting distribution-system

operations or reliability functions; and having access to the system control center or similar

facilities used for distribution operations or reliability functions that differs in any way from the

access available to other nonregulated power producers.

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     (2) Employees engaged in either an affiliated nonregulated power producer function or an

electric distribution function are not precluded from transferring between such functions as long as

such transfer is not used as a means to circumvent the standards of conduct of this section. Notices

of any employee transfer to or from electric distribution company operation or reliability functions

must be reported to the commission. The information to be reported must include: the name of the

transferring employee; the respective titles held while performing each function (i.e., on behalf of

the electric distribution company and the nonregulated power producer); and the effective date of

the transfer.

     (3) Any employee of any affiliate of an electric distribution company who is engaged in

the nonregulated power producer function must not have preferential access to any information

about the electric distribution company’s distribution system that is not available to all nonregulated

power producers.

     (4) An electric distribution company is responsible for ensuring that any employee of the

electric distribution company may not disclose to employees of any affiliate engaged in a

nonregulated power producer function any information concerning the distribution system of the

electric distribution company or the distribution system of another (including information received

from nonaffiliates or information about distribution-system operations, capability, price,

curtailments, auxiliary services, and the like) through nonpublic communications that is not at the

same time available to all nonregulated power producers without restriction. If an employee of the

electric distribution company engaged in distribution-system operations or reliability functions

discloses information in a manner contrary to the requirements of the standards of conduct, the

electric distribution company must immediately report that information to the commission. An

electric distribution company may not share any market information acquired from nonaffiliated,

nonregulated power producers or developed in the course of responding to requests for distribution

service with any employee of an affiliate engaged in a nonregulated power producer function.

     (5) All employees of the electric distribution company must apply all tariff provisions in a

fair and impartial manner that treats all customers (including those of an affiliated nonregulated

power producer) in a nondiscriminatory manner. The electric distribution company may not offer

a discount on purchases of distribution service where this discount is conditioned upon customers

purchasing power from a nonregulated power producer that is affiliated with the electric

distribution company, nor shall an electric distribution company give preferences of any type in the

provision of distribution service for customers purchasing power supply from a nonregulated power

producer that is affiliated with the electric distribution company.

     (d) An electric distribution company must maintain its books of accounts and records

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separately from those of its affiliates and these must be available for commission inspection.

     (e) The electric distribution company must maintain in a public place, and file with the

commission, current written procedures implementing the standards of conduct in such detail as

will enable customers and the commission to determine that the electric distribution company is in

compliance with the requirements of this section.

     (f) An electric distribution company must maintain an open and competitive procurement

process for goods and services needed or the ongoing maintenance and improvement of the electric

distribution system. Consistent with this section, any expenditure of ratepayer funds in excess of

one hundred thousand dollars ($100,000) shall utilize a request for proposals process that shall be

available to the public, including responses to any issued request for proposals, subject to

maintaining confidentiality of any documents that would be exempt from disclosure under chapter

2 of title 38 ("public records act"). The commission may deny recovery of any expenditure if the

procurement was done in a manner inconsistent with provisions of the section.

     39-1-27.7.1. Revenue decoupling.

     (a) The general assembly finds and declares that electricity and gas revenues shall be fully

decoupled from sales pursuant to the provisions of this chapter and further finds and declares that

any decoupling proposal submitted by an electric distribution company as defined in § 39-1-

2(a)(12) or gas distribution company included as a public utility in § 39-1-2(a)(20) that has greater

than one hundred thousand (100,000) customers, shall be for the following purposes:

     (1) Increasing efficiency in the operations and management of the electric and gas

distribution system;

     (2) Achieving the goals established in the electric distribution company’s plan for system

reliability and energy efficiency and conservation procurement as required pursuant to § 39-1-

27.7(d);

     (3) Increasing investment in least-cost resources that will reduce long-term electricity

demand;

     (4) Reducing risks for both customers and the distribution company including, but not

limited to, societal risks, weather risks, and economic risks;

     (5) Increasing investment in end-use energy efficiency;

     (6) Eliminating disincentives to support energy-efficiency programs;

     (7) Facilitating and encouraging investment in utility infrastructure, safety, and reliability;

and

     (8) Considering the reduction of fixed, recurring customer charges and transition to

increased unit charges that more accurately reflect the long-term costs of energy production and

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delivery.

     (b) Each electric distribution company as defined by § 39-1-2(a)(12) and gas distribution

company included as a public utility in § 39-1-2(a)(20) having greater than one hundred thousand

(100,000) customers shall file proposals at the commission to implement the policy set forth in

subsection (a) of this section. The commission shall approve these proposals, provided they contain

the features and components set forth in subsection (c) of this section, and that they are consistent

with the intent and objectives contained in subsection (a) of this section. Actions taken by the

commission in the exercise of its ratemaking authority for electric and gas rate cases shall be within

the norm of industry standards and recognize the need to maintain the financial health of the

distribution company as a stand-alone entity in Rhode Island.

     (c) The proposals shall contain the following features and components:

     (1) A revenue decoupling reconciliation mechanism that reconciles annually the revenue

requirement allowed in the company’s base distribution-rate case to revenues actually received for

the applicable twelve-month (12) period. Any revenues over-recovered or under-recovered shall be

credited to, or recovered from, customers, as applicable; and

     (2) An annual infrastructure, safety, and reliability spending plan for each fiscal year and

an annual rate-reconciliation mechanism that includes a reconcilable allowance for the anticipated

capital investments and other spending pursuant to the annual pre-approved budget as developed

in accordance with subsection (d) of this section.

     (d) Prior to the beginning of each fiscal year, gas and electric distribution companies shall

consult with the division of public utilities and carriers regarding their infrastructure, safety, and

reliability spending plan for the following fiscal year, addressing the following categories:

     (1) Capital spending on utility infrastructure;

     (2) For electric distribution companies, operation and maintenance expenses on vegetation

management;

     (3) For electric distribution companies, operation and maintenance expenses on system

inspection, including expenses from expected resulting repairs; and

     (4) Any other costs relating to maintaining safety and reliability that are mutually agreed

upon by the division and the company.

     The distribution company shall submit a plan to the division and the division shall

cooperate in good faith to reach an agreement on a proposed plan for these categories of costs for

the prospective fiscal year within sixty (60) days. To the extent that the company and the division

mutually agree on a plan, such plan shall be filed with the commission for review and approval

within ninety (90) days. If the company and the division cannot agree on a plan, the company shall

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file a proposed plan with the commission and the commission shall review and, if the investments

and spending are found to be reasonably needed to maintain safe and reliable distribution service

over the short and long term, approve the plan within ninety (90) days. The commission may limit

or otherwise amend the budget proposed by the distribution company if it finds that it will not

impact safety or reliability standards. The commission shall be under no obligation to approve any

expenditures it finds to be unnecessary to maintain standards, and the company may still seek

recovery through standard rate proposals of any investment denied by the commission in an

infrastructure, safety, and reliability spending plan.

     (e) The commission shall have the following duties and powers, in addition to its existing

authorities established in this title:

     (1) To maintain reasonable and adequate service-quality standards, after decoupling, that

are in effect at the time of the proposal and were established pursuant to § 39-3-7.

     (2) The commission may exclude the low-income rate class from the revenue decoupling

reconciliation-rate mechanism for either electric or gas distribution. The commission also may

exclude customers in the large commercial and industrial rate class from the gas-distribution

mechanism.

     (3) The commission may adopt performance incentives for the electric distribution

company that provide a shared-savings mechanism whereby the company would receive a

percentage of savings realized as a result of achieving the purposes of this section while the

remaining savings are credited to customers.

     (4) The commission shall review and approve, with any necessary amendments,

performance-based, energy-savings targets developed and submitted by the Rhode Island energy

efficiency and resources management council. The performance-based targets shall also be used as

a consideration in any shared-savings mechanism established by the commission pursuant to

subsection (e)(3) of this section.

     (5) Notwithstanding other provisions of the general or public laws to the contrary, the

commission has the authority to limit the proposed budget of any proposal received under this

section.

     (f) The Rhode Island energy efficiency and resources management council shall propose

performance-based, energy-savings targets to the commission no later than September 1, 2010. The

targets shall include, but not be limited to, specific energy kilowatt-hour savings overall and peak-

demand savings for both summer and winter peak periods expressed in total megawatts as well as

appropriate targets recommended in the opportunities report filed with the commission pursuant to

§ 39-1-27.7(d)(3). The council shall revise, as necessary, these targets on an annual basis prior to

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the reconciliation process established pursuant to subsection (c) of this section and submit its

revisions to the commission for approval.

     (g) Reporting. Every electric distribution company, as defined in subsection (a) of this

section, shall report to the governor, general assembly, division of public utilities and carriers, and

public utilities commission on or before September 1, 2012. The report shall include, but not be

limited to, the following elements:

     (1) A comparison of revenues from traditional rate regulation and how the revenues have

differed as part of an approved decoupling structure;

     (2) A summary of how the company is achieving the performance-based targets that may

have been adopted pursuant to subsection (e)(4) of this section;

     (3) A summary of any shared savings the company may have received pursuant to the

performance incentives authorized in subsection (e)(3) of this section;

     (4) A summary of how the company is achieving the service-quality standards required in

subsection (e)(1) of this section;

     (5) An overview of how decoupling is impacting revenue stabilization goals that have

resulted from decoupling; and

     (6) A summary of any customer education programs provided.

     (h) By October 1, 2024, and every subsequent five (5) years, the distribution company shall

file with the commission for its review and consideration a grid modernization and resilience plan

that contains, at a minimum, the following components:

     (1) All issues referenced in PUC Order Number 23823, Section 6, addressing minimum

requirements for a grid modernization plan;

     (2) Standardized, qualitative method to assess the potential and known greenhouse gas

emissions that will result from the expenditure of any ratepayer funds;

     (3) An evaluation of the climate science and projected extreme weather and other climate-

related risks for the service territory including changes in temperature extremes, humidity,

precipitation, sea level rise, and extreme storms;

     (4) An evaluation and risk assessment of potential impacts of climate change on existing

operation, planning, and physical assets, including any design and construction standards or

maintenance and operations practices that require changes to address current and future climate

conditions as it relates to reliability and resilience of the grid;

     (5) An evaluation of the vulnerability of existing infrastructure based on location and

whether and when certain facilities may require retrofitting or relocation;

     (6) Identification and prioritization of adaptation options to increase asset and system-wide

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resilience over time;

     (7) An evaluation of costs and benefits against a range of possible future scenarios and

adaptation options;

     (8) An implementation timeline, including benchmarks over time, for making changes in

line with the findings of the study such as modifying design and construction standards, modifying

operations and planning processes, and upgrades to existing infrastructure to ensure reliability and

resilience of the grid; and

     (9) Any other item ordered by the commission.

     SECTION 2. Section 39-2-1.2 of the General Laws in Chapter 39-2 entitled "Duties of

Utilities and Carriers" is hereby amended to read as follows:

     39-2-1.2. Utility base rate — Advertising, demand-side management, and renewables

Utility base rate -- Demand-side management and renewables.

     (a) In addition to costs prohibited in § 39-1-27.4(b), no public utility distributing or

providing heat, electricity, or water to or for the public shall include as part of its base rate any

expenses for advertising, either direct or indirect, that promotes the use of its product or service, or

is designed to promote the public image of the industry. No public utility may furnish support of

any kind, direct or indirect, to any subsidiary, group, association, or individual for advertising and

include the expense as part of its base rate. Nothing contained in this section shall be deemed as

prohibiting the inclusion in the base rate of expenses incurred for advertising, informational or

educational in nature, that is designed to promote public safety conservation of the public utility’s

product or service. The public utilities commission shall promulgate such rules and regulations as

are necessary to require public disclosure of all advertising expenses of any kind, direct or indirect,

and to otherwise effectuate the provisions of this section.

     (b) Effective as of January 1, 2008, and for a period of twenty (20) years thereafter, each

electric distribution company shall include a charge per kilowatt-hour delivered to fund demand-

side management programs. The 0.3 mills per kilowatt-hour delivered to fund renewable energy

programs shall remain in effect until December 31, 2028. The electric distribution company shall

establish and, after July 1, 2007, maintain, two (2) separate accounts, one for demand-side

management programs (the “demand-side account”), which shall be funded by the electric demand-

side charge and administered and implemented by the distribution company, subject to the

regulatory reviewing authority of the commission, and one for renewable energy programs, which

shall be administered by the Rhode Island commerce corporation pursuant to § 42-64-13.2 and shall

be held and disbursed by the distribution company as directed by the Rhode Island commerce

corporation for the purposes of developing, promoting, and supporting renewable energy programs.

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     During the time periods established in this subsection, the commission may, in its

discretion, after notice and public hearing, increase the sums for demand-side management and

renewable resources. In addition, the commission shall, after notice and public hearing, determine

the appropriate charge for these programs. The office of energy resources, and/or the administrator

of the renewable energy programs, may seek to secure for the state an equitable and reasonable

portion of renewable energy credits or certificates created by private projects funded through those

programs. As used in this section, “renewable energy resources” shall mean: (1) Power generation

technologies, as defined in § 39-26-5, “eligible renewable energy resources,” including off-grid

and on-grid generating technologies located in Rhode Island, as a priority; (2) Research and

development activities in Rhode Island pertaining to eligible renewable energy resources and to

other renewable energy technologies for electrical generation; or (3) Projects and activities directly

related to implementing eligible renewable energy resources projects in Rhode Island.

Technologies for converting solar energy for space heating or generating domestic hot water may

also be funded through the renewable energy programs. Fuel cells may be considered an energy

efficiency technology to be included in demand-side management programs. Special rates for low-

income customers in effect as of August 7, 1996, shall be continued, and the costs of all of these

discounts shall be included in the distribution rates charged to all other customers. Nothing in this

section shall be construed as prohibiting an electric distribution company from offering any special

rates or programs for low-income customers which are not in effect as of August 7, 1996, subject

to the approval by the commission.

     (1) The renewable energy investment programs shall be administered pursuant to rules

established by the Rhode Island commerce corporation. Said rules shall provide transparent criteria

to rank qualified renewable energy projects, giving consideration to:

     (i) The feasibility of project completion;

     (ii) The anticipated amount of renewable energy the project will produce;

     (iii) The potential of the project to mitigate energy costs over the life of the project; and

     (iv) The estimated cost per kilowatt-hour (KWh) of the energy produced from the project.

     (c) [Deleted by P.L. 2012, ch. 241, art. 4, § 14.]

     (d) The chief executive officer of the commerce corporation is authorized and may enter

into a contract with a contractor for the cost-effective administration of the renewable energy

programs funded by this section. A competitive bid and contract award for administration of the

renewable energy programs may occur every three (3) years and shall include, as a condition, that

after July 1, 2008, the account for the renewable energy programs shall be maintained and

administered by the commerce corporation as provided for in subsection (b) of this section.

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     (e) Effective January 1, 2007, and for a period of twenty-one (21) years thereafter, each

gas distribution company shall include, with the approval of the commission, a charge per deca

therm delivered to fund demand-side management programs (the “gas demand-side charge”),

including, but not limited to, programs for cost-effective energy efficiency, energy conservation,

combined heat and power systems, and weatherization services for low-income households.

     (f) Each gas company shall establish a separate account for demand-side management

programs (the “gas demand-side account”) that shall be funded by the gas demand-side charge and

administered and implemented by the distribution company, subject to the regulatory reviewing

authority of the commission. The commission may establish administrative mechanisms and

procedures that are similar to those for electric demand-side management programs administered

under the jurisdiction of the commission and that are designed to achieve cost-effectiveness and

high, life-time savings of efficiency measures supported by the program.

     (g) The commission may, if reasonable and feasible, except from this demand-side

management charge:

     (1) Gas used for distribution generation; and

     (2) Gas used for the manufacturing processes, where the customer has established a self-

directed program to invest in and achieve best-effective energy efficiency in accordance with a plan

approved by the commission and subject to periodic review and approval by the commission, which

plan shall require annual reporting of the amount invested and the return on investments in terms

of gas savings.

     (h) The commission may provide for the coordinated and/or integrated administration of

electric and gas demand-side management programs in order to enhance the effectiveness of the

programs. Such coordinated and/or integrated administration may after March 1, 2009, upon the

recommendation of the office of energy resources, be through one or more third-party entities

designated by the commission pursuant to a competitive selection process.

     (i) Effective January 1, 2007, the commission shall allocate, from demand-side

management gas and electric funds authorized pursuant to this section, an amount not to exceed

three percent (3%) of such funds on an annual basis for the retention of expert consultants, and

reasonable administration costs of the energy efficiency and resource management council

associated with planning, management, and evaluation of energy-efficiency programs, renewable

energy programs, system reliability, least-cost procurement, and with regulatory proceedings,

contested cases, and other actions pertaining to the purposes, powers, and duties of the council,

which allocation may by mutual agreement, be used in coordination with the office of energy

resources to support such activities.

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     (j) Effective January 1, 2016, the commission shall annually allocate from the

administrative funding amount allocated in subsection (i) from the demand-side management

program as described in subsection (i) as follows: (1) for the energy efficiency and resource

management council, no more than forty percent (40%) for the purposes identified in subsection (i)

and (2) sixty percent (60%) of three percent (3%) from the demand-side management gas and

electric funds annually to the office of energy resources for activities associated with planning,

management, and evaluation of energy-efficiency programs, renewable energy programs, system

reliability, least-cost procurement, and with regulatory proceedings, contested cases, and other

actions pertaining to the purposes, powers, and duties of the office of energy resources and shall

have exclusive authority to direct the use of the office administrative and programmatic funds.

     (k) On April 15, of each year, the office and the council shall submit to the governor, the

president of the senate, and the speaker of the house of representatives, separate financial and

performance reports regarding the demand-side management programs, including the specific level

of funds that were contributed by the residential, municipal, and commercial and industrial sectors

to the overall programs; the businesses, vendors, and institutions that received funding from

demand-side management gas and electric funds used for the purposes in this section; and the

businesses, vendors, and institutions that received the administrative funds for the purposes in

subsections (i) and (j). These reports shall be posted electronically on the websites of the office of

energy resources and the energy efficiency and resources management council.

     (l) On or after August 1, 2015, at the request of the Rhode Island infrastructure bank, each

electric distribution company, except for the Pascoag Utility District and Block Island Power

Company, shall remit two percent (2%) of the amount of the 2014 electric demand-side charge

collections to the Rhode Island infrastructure bank.

     (m) On or after August 1, 2015, at the request of the Rhode Island infrastructure bank, each

gas distribution company shall remit two percent (2%) of the amount of the 2014 gas demand-side

charge collections to the Rhode Island infrastructure bank.

     (n) Effective January 1, 2022, the commission shall allocate, from demand-side

management gas and electric funds authorized pursuant to this section, five million dollars

($5,000,000) of such funds on an annual basis to the Rhode Island infrastructure bank. Gas and

electric demand-side funds transferred to the Rhode Island infrastructure bank pursuant to this

section shall be eligible to be used in any energy efficiency, renewable energy, clean transportation,

clean heating, energy storage, or demand-side management project financing program administered

by the Rhode Island infrastructure bank notwithstanding any other restrictions on the use of such

collections set forth in this chapter. The infrastructure bank shall report annually to the commission

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within ninety (90) days of the end of each calendar year how collections transferred under this

section were utilized.

     (o) The Rhode Island office of energy resources, in coordination with the energy efficiency

and resource management council, and following consultation with the public utilities commission

and division of public utilities and carriers, shall issue a request for proposals for the cost-effective

administration and implementation of statewide energy efficiency programs funded by this section

no later than September 30, 2023. The draft request for proposals shall be reviewed through at least

one technical session at the public utilities commission prior to issuance. Public utilities

commission approval shall not be required. The Rhode Island office of energy resources, in

coordination with the energy efficiency and resource management council, shall evaluate proposals

and determine whether energy efficiency administration and implementation by the electric and gas

distribution company or a third party is likely to achieve the most net benefits for electric and gas

customers in Rhode Island. After January 1, 2025, the office of energy resources may, periodically,

and at its discretion, issue additional requests for proposals for the administration and

implementation of statewide energy efficiency programs funded through this chapter of an electric

distribution company as defined in § 39-1-2(a)(12) or gas distribution company included as a

public utility in § 39-1-2(a)(20) that has greater than one hundred thousand (100,000) customers.

     (1) Nothing in this chapter shall prohibit the electric and/or gas distribution company from

submitting a proposal to administer and implement the state energy efficiency programs.

     (2) If the office of energy resources, in coordination with the energy efficiency and resource

management council, determines that the use of a third-party administrator is likely to achieve the

most net benefits for electric and gas customers in Rhode Island, it shall file its recommendation

with the public utilities commission, which shall docket and rule on the matter pursuant to its

general statutory authorization.

     (3) If the commission determines that the recommended third-party administrator is in the

interest of Rhode Island utility customers, it shall provide for the full cost recovery for the third-

party administrator consistent with the terms of the approved contract, and which shall reflect the

overall annual budget approved by the commission. The third-party administrator shall be subject

to all the requirements set forth for the electric and gas distribution company per § 39-1-27.7.

     (4) If the commission determines that a third-party administrator will administer the state

energy efficiency programs on or after June 1, 2024, the commission shall direct the gas and electric

distribution company to collect and transfer the gas and electric energy efficiency funds to the third-

party administrator for the annual state energy efficiency program beginning with the program year

and thereafter for the remaining program years. The gas and electric distribution company shall

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transfer the annual administrative funds to the office of energy resources and energy efficiency and

resource management council.

     (5) If a third-party administrator implements the annual energy efficiency programs then

they shall be required to develop and design the annual state energy efficiency program with the

office of energy resources and energy efficiency and resource management council, including a

vote by the energy efficiency and resource management council prior to the third-party

administrator filing the annual program plan to the public utilities commission for review and a

decision.

     (6) The third-party administrator shall file the annual state energy efficiency program plan

to the public utilities commission for review and approval no later than September 30, 2024, and

annually thereafter on such date.

     (7) The third-party administrator shall provide all information requested by the office of

energy resources, energy efficiency and resource management council, division of public utilities

and carriers, and the public utilities commission, including responses to data requests, which are

necessary for the agencies to carry out their respective oversight roles, and shall be accountable to

the same standards as the utility with administering and implementing energy efficiency, system

reliability, and least-cost procurement standards and goals in accordance with § 39-1-27.7 and this

section.

     (8) If the office does not recommend advancement of a third-party administrator, the

electric and gas distribution company shall continue to administer statewide energy efficiency

programs.

     SECTION 3. Chapter 39-2 of the General Laws entitled "Duties of Utilities and Carriers"

is hereby amended by adding thereto the following section:

     39-2-1.5. Utility base rate -- Prohibitions on advertising, political, charitable, and

investor-related expenses.

     (a) In addition to costs prohibited in § 39-1-27.4(b), no public utility serving greater than

one hundred thousand (100,000) customers distributing or providing heat, electricity, or water to

or for the public shall recover through rates any direct or indirect cost associated with:

     (1) Advertising, marketing, communications, or public education that seek to influence

public opinion, including any costs associated with activities such as research, analysis, preparation

or planning undertaken in support of advertising, marketing, communications, or public education,

or any other related costs identified by the commission, unless such marketing, advertising,

communications or related costs are specifically approved or ordered by the commission;

     (2) Membership, dues, sponsorships or contributions to a business or industry trade

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association, group or related entity incorporated under Section 501 of the Internal Revenue Code

of 1986, as amended;

     (3) Charitable giving expenses, including contributions to organizations qualified under

section 501(c)(3) or 501(c)(4) of the Internal Revenue Code of 1986, as amended;

     (4) Lobbying as defined in § 42-139.1-3 including, but not limited to, any costs for

activities undertaken in support of lobbying such as policy research, analysis, preparation, and

planning undertaken in support of lobbying;

     (5) Contributions to political candidates, campaign committees, issue committees, or

independent expenditure committees or similar political expenses;

     (6) Litigation to influence, modify, or repeal existing federal, state or local regulations,

legislation or ordinances;

     (7) Marketing and administration or customer service for unregulated products or services

provided or sold by the utility or the utility’s affiliates;

     (8) Tax penalties or fines issued against the utility;

     (9)(i) Travel, lodging or food and beverage expenses for such company’s board of directors

and officers or the board of directors and officers of such company’s parent company;

     (ii) Entertainment or gifts;

     (iii) Any owned, leased or chartered aircraft for such company’s board of directors and

officers or the board of directors and officers of such company’s parent company; or

     (iv) Investor relations; and

     (10) Annual compensation for any employees or members of the board of directors of the

company exceeding the current annual salary of the governor.

     (b) On or before September 1, 2025, and annually thereafter, each utility serving greater

than one hundred thousand (100,000) customers shall report to the public utilities commission a

list of expenses to ensure the utility’s compliance with this chapter. Such report shall include, but

need not be limited to:

     (1) A list of all outside services or vendors paid by the utility;

     (2) An itemized list of all expenses associated with activities described in § 39-1-27.7.1,

including expenses made to:

     (i) Third-party vendors;

     (ii) Utility affiliates, subsidiaries or parent companies; and

     (iii) Utility employees in the form of compensation.

     (3) For each itemized expense associated with activities described in § 39-1-27.7.1, the

billing amount, date, identity of payee, and an explanation of the expense sufficient to describe its

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purpose.

     (4) In the case of an expense associated with activities described in § 39-1-27.7.1 made to

a third-party vendor by a centralized service company, parent company, or other corporate affiliate

of utility, the identity of that third-party vendor;

     (5) Any other itemized information deemed relevant by the commission.

     No public service company shall recover through rates any costs associated with the

preparation of such report.

     (c) No investor-owned utility with more than one hundred thousand (100,000) customers

shall recover through rates its direct or indirect costs associated with its attendance in, participation

in, preparation for, or appeal of any contested proceeding conducted before the commission. Such

costs shall include, but need not be limited to, attorneys’ fees, fees to engage expert witnesses or

consultants, the portion of employee salaries associated with such attendance, participation,

preparation or appeal of a contested proceeding and related costs identified by the commission.

     (d) By November 1, 2024, the public utilities commission shall initiate rulemaking to

amend its rules under title 39 to implement the requirements of this chapter, including requiring the

public disclosure of all expenses prohibited from rate recovery. Rulemaking shall conclude no later

than June 1, 2025.

     SECTION 4. Title 39 of the General Laws entitled "PUBLIC UTILITIES AND

CARRIERS" is hereby amended by adding thereto the following chapter:

CHAPTER 33

ENERGY SYSTEM PLANNING FOR EQUITY AND CLIMATE

     39-33-1. Definitions.

     As used in this section, unless the context otherwise indicates, the following terms have

the following meanings.

     (1) "Covered utility" means an electric distribution company as defined in § 39-1-2 that

serves more than one hundred thousand (100,000) customers.

     (2) "Environmental justice", as defined by the department of environmental management,

means the fair treatment and meaningful involvement of all people regardless of race, color,

national origin, English language proficiency, or income with respect to access to the state’s natural

resources and the development, implementation, and enforcement of environmental laws,

regulations, and policies. This definition may be updated in alignment with subsequent statute.

     (3) "Hosting capacity" means a threshold at a circuit at which new distributed energy

resources will trigger upgrades or changes to the electrical distribution system and cost

considerations of related upgrades and changes.

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     (4) "Resiliency" means the ability to prepare for and adapt to changing conditions and

withstand and recover rapidly from deliberate attacks, accidents or naturally occurring threats or

incidents, including, but not limited to, threats or incidents associated with the impacts of climate

change.

     39-33-2. Integrated distribution system planning.

     (a) Integrated distributions system plans. Beginning June 30, 2025, then every two (2) years

thereafter, a covered utility shall be required to submit a ten (10) year integrated distribution system

plan to the commission. The integrated distribution system plan shall identify solutions to enable

the cost-effective achievement of the Rhode Island’s greenhouse gas reduction obligations and

climate policies; to improve grid reliability and resiliency; to support distributed energy resource

integration and utilization for grid services; to accelerate the deployment of new technologies and

services to optimize grid performance and minimize electricity system costs; to increase customer

choice and engagement in energy services; to maximize use of federal funding sources; and to

support equity and environmental justice goals. The integrated distribution system plan shall

include a three (3) year action plan to optimize near-term grid investments and operations.

     (b) Documentation; priorities identified; integrated distribution system planning process;

stakeholder input. The commission shall initiate a proceeding to document existing utility systems

and processes that support integrated grid planning; to identify the priorities to be addressed in a

filing by a covered utility regarding an integrated distribution system plan; and to establish a public

and transparent integrated distribution system planning process and reporting standards. The

commission shall hold technical conferences and/or stakeholder workshops to identify priorities,

assumptions, goals, methods, and tools that will assist the covered utility in developing an

integrated distribution system plan. As part of the integrated distribution system planning process:

     (1) The commission may require the creation of a stakeholder council to provide input

during the integrated distribution system planning process; a technical advisory group to review

and provide input on forecasting, assumptions, modeling tools, and other issues the commission

identifies; and working groups as appropriate. A stakeholder council may include participants

including, but not limited to, municipal representatives; consumer advocates; representatives for

demand response, electric vehicles, energy storage, and energy efficiency industries; solar

developers; industrial customers; state planning agencies; and environmental organizations.

     (2) A covered utility shall provide notice to all municipalities that are included in its service

area to inform them of the process and request copies of all comprehensive land use plans, which

shall be considered when preparing the integrated distribution system plan.

     (3) A covered utility shall develop a community engagement plan that describes how it will

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collaborate with community-based organizations and environmental justice communities to ensure

that community needs, especially with respect to energy burden, customer choice, and resiliency,

inform utility forecasting and methods to identify distribution system investments, including

customer-sited non-wires solutions.

     (4) A covered utility shall host at least three (3) public workshops prior to filing its

integrated distribution system plan filing and must document how the public input received

informed the distribution system planning process.

     (c) Commission order. At the conclusion of the technical conferences and stakeholder

workshops held under § 39-33-2(b), the commission shall issue an order directing a covered utility

to submit a filing to the commission that addresses the priorities identified in the proceeding

initiated pursuant to § 39-33-2(a) and includes the additional components identified in § 39-33-

2(b).

     (d) Additional components; submission. A covered utility shall submit a filing to the

commission within twelve (12) months of the issuance of an order by the commission pursuant to

§ 39-33-2(b). In addition to addressing the priorities specified in the commission order, the filing

must:

     (1) Assess the electric system of the covered utility and its relationship to the regional grid;

     (2) Include multiple planning scenarios, with, at a minimum, a baseline scenario and a

scenario of high-penetration distributed energy resources and end-use building and transportation

electrification. The planning scenarios must incorporate mechanisms for achieving the priorities

established pursuant to § 39-33-2(b), including, but not limited to, cost-effective policies, programs,

rates, use of software or technology, and infrastructure planning, including non-wires alternatives.

The baseline scenario shall incorporate existing state climate and clean energy requirements, local

laws and planning efforts, as well as existing federal laws, including, but not limited to, the Inflation

Reduction Act and the Infrastructure Investment and Jobs Act. Each scenario may have multiple

sensitivities based on inputs including, but not limited to, fuel and technology costs, load flexibility,

and rate design.

     (3) Include, at a minimum, the following:

     (i) Forecasts of projected load, including forecasts of end-use electrification, energy

efficiency and distributed energy resources;

     (ii) Baseline energy supply data and assessments, including, but not limited to, planned

generation retirements; new generation that is planned or needed, including generation of electricity

from renewable sources; and energy storage installations;

     (iii) Analysis of hosting capacity, including locational benefits of distributed energy

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resources and areas of existing or potential system congestion;

     (iv) Analysis of available and emerging technologies necessary to enable load management

and flexibility;

     (v) An assessment of the environmental, equity, and environmental justice impacts of the

distribution system plans and identified solutions; and

     (vi) An identification of cost-effective near-term grid investments and operations needed

to achieve the priorities identified in § 39-33-2(b); and

     (vii) An assessment of consumer cost impacts and protections for low-income

communities.

     (4) Include a plan for moving to system planning based on time-series analysis and

probabilistic planning criteria. Forecasting methodologies in the distribution system plans must be

transparent, and temporally and geographically granular. Forecasts should include feeder-level data

at hourly or sub-hourly intervals. Feeder level forecasts should be disaggregated by distributed

energy resource type and indicate, of those distributed energy resources, which are flexible and the

associated flexible load. The distribution system plans should include a plan for forecasting with

time series data at the circuit level. A utility shall provide a forecasting roadmap of how its

forecasting methodology will evolve over time and when this will happen, including utilizing time

series planning.

     (5) Reference and incorporate, as appropriate, all relevant elements, analysis, and findings

conducted as part of the state's most recent climate action plan or strategy and all relevant elements,

analysis, and findings related to proceedings including, but not limited to, the system reliability

procurement process; the commission’s future of gas proceeding; the infrastructure, safety and

reliability plan; and the power sector transformation process.

     (e) Public comment and review. The commission shall make the filing for each covered

utility available for public comment for a period of no less than ninety (90) days. The commission

shall, if it determines it is necessary, order a covered utility to revise the plan to address any

deficiencies in the plan or to incorporate any reasonable actions to align its business, programs,

operations, and investments with greenhouse gas reduction obligations and climate policies. The

commission may use the filing and the input received from interested parties in rate cases or other

proceedings involving the covered utility.

     (f) Access to information. A covered utility shall ensure to the greatest extent practicable

that any information related to the filing is provided in a forum accessible to interested parties and

all relevant data and distribution planning modeling tools are available to interested parties.

Nothing in this section prohibits the commission from holding additional proceedings if the

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commission determines it is necessary to meet the purposes of this section.

     (g) Administrative expense. The commission is authorized to hire one or more consultants

to assist with each task set forth in this section and, should the general assembly not appropriate

funds from the general fund specifically for implementation of this section, may assess its actual

costs to the covered utility in a manner to be determined by the commission.

     39-33-3. Performance-based regulation.

     (a) Not later than October 1, 2024, the public utilities commission shall initiate a

proceeding to investigate, develop and adopt a framework for implementing performance-based

regulation of electric distribution companies serving greater than one hundred thousand (100,000)

customers. Such framework adopted by the commission shall:

     (1) Establish standards and metrics for measuring such electric distribution company's

performance of objectives that are in the interest of ratepayers or benefit the public, which may

include, but not be limited to, safety, reliability, emergency response, cost efficiency, affordability,

equity, customer satisfaction, municipal engagement, resiliency, and advancing the state's

environmental and policy goals, including, but not limited to, those goals established in § 42-6.2-

2;

     (2) Identify the manner, including the timeframe and extent, in which such standards and

metrics shall be used to apply the principles and guidelines set forth in § 39-1-1 and to determine

the relative adequacy of the company's service and the reasonableness and adequacy of rates

proposed and considered pursuant to title 39; and

     (3) Identify specific mechanisms to be implemented to align utility performance with the

standards and metrics adopted pursuant to this section and title 39. The commission may also

initiate a proceeding to investigate, develop and adopt a framework for implementation of

performance-based regulation for gas and water companies, as defined in § 39-1-2, consistent with

the requirements and provisions of this section.

     (b) In any proceeding required under subsection (a) of this section, or in any rate hearing

pursuant to title 39, the commission may approve performance-based incentives to encourage a gas

or electric distribution company to operate efficiently and provide high quality service at fair and

reasonable rates and shall consider the implementation of financial performance-based incentives

and penalties and performance-based metrics. If the commission approves such performance-based

incentives and penalties for a particular company, the commission shall include in such approval a

framework for periodic monitoring and review of the company's performance in regard to criteria

specified by the commission, which shall include, but not be limited to, the company's return on

equity, reliability and quality of service. If the commission determines in the periodic monitoring

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and review that a more extensive review of company performance is necessary, the commission

may institute a further proceeding in accordance with the purposes of this chapter, including a

complete review and investigation described in subsection (a) of this section pursuant to metrics

developed by the commission.

     (c) Notwithstanding any provision of general laws or public laws to the contrary, in

exercising its discretion regarding whether to allow the recovery through rates of any portion of the

compensation package for executives or officers or of any portion of any incentive compensation

for employees of any electric distribution company, gas company or water company, as defined in

title 39, the public utilities commission shall consider whether to require that any such

compensation that is recoverable through rates be dependent upon the achievement of performance

targets established pursuant to subsection (a) of this section.

     SECTION 5. This act shall take effect upon passage.

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EXPLANATION

BY THE LEGISLATIVE COUNCIL

OF

A N   A C T

RELATING TO PUBLIC UTILITIES AND CARRIERS -- PUBLIC UTILITIES COMMISSION

***

     This act would amend several provisions relative the powers and duties of the PUC and

would require the submission by utilities of integrated distribution system plans identifying

solutions to reduce greenhouse gases.

     This act would take effect upon passage.

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