# RMI Electricity Affordability Toolkit — Full Content > A curated set of actionable, state-level policies to help legislators, staff, and advocates identify and advance effective electricity affordability solutions. Source: https://affordability-toolkit.rmi.org --- ## Percentage Of Income Payment Plans URL: https://affordability-toolkit.rmi.org/policies/percentage-of-income-payment-plans PDF: https://affordability-toolkit.rmi.org/pdfs/percentage-of-income-payment-plans.pdf Percentage of income payment plans reduce energy burden by capping bills as a fixed percentage of household income. - **Themes:** cost distribution, customer agency - **Safeguard:** Yes - **Impact time horizon:** short — Once approved and funded, PIPPs can generally launch within a year or two. - **Potential cost savings:** high — PIPPs can deliver significant cost savings, but impacts will depend on policy design. Using RMI's [Energy Poverty Policy Simulator](https://utilitytransitionhub.rmi.org/energy-poverty-policy-simulator/), a Virginia-style PIPP applied to North Carolina is projected to reduce energy burdens by over 50% for customers at or below 100% of the federal poverty level. - **Target cost drivers:** Aging grid infrastructure, Fuel price volatility, Extreme weather/wildfires, Load growth, Misaligned utility incentives ### Context and Background Percentage of income payment plans (PIPPs) are utility affordability programs that reduce energy burden, the share of income spent on energy bills, by capping bills as a fixed percentage of household income. PIPP design varies, but they generally cap energy bills at 3%–10% of household income, with costs typically funded by other ratepayers. PIPPs protect against rising bills and provide predictability by ensuring bills remain even month to month. PIPPs are increasingly seen as a cornerstone of energy affordability policy. While legislation may establish the overall framework, the specific design of the PIPP — including eligibility considerations, enrollment process, or payment formulas — is typically managed by utilities or regulators. ### Real-World Examples PIPPs exist in at least ten states, including New Jersey, Illinois, Colorado, Maine, North Dakota, and Nevada. **California — California Implementation** California's utility commission [developed a Percentage of Income Payment Plan Pilot](https://www.appriseinc.org/wp-content/uploads/2023/06/NEUAC-PIPP-Pilot-5-25-23-2.pdf?utm_source=chatgpt.com) following the passage of [Senate Bill 598](https://legiscan.com/CA/text/SB598/id/1639280), which directed the commission to [address utility disconnections](https://www.cpuc.ca.gov/-/media/cpuc-website/files/uploadedfiles/cpucwebsite/content/about_us/organization/commissioners/martha_guzman_aceves/order-instituting-rulemaking-disconnection-com-guzman-aceves.pdf). The program caps energy bills at 4% of household income. In order to qualify, customers must (1) be part of the state's California Alternate Rates for Energy (CARE) program, a low-income utility bill discount program, and (2) be located either in one of the zip codes with the highest rates of disconnections or have experienced at least two disconnections during the year prior to the moratorium. A bill surcharge applied to all customers pays for the program. **New York — New York Implementation** New York's Public Service Commission approved the [Energy Affordability Guarantee Pilot](https://www.governor.ny.gov/news/governor-hochul-announces-energy-affordability-guarantee-pilot-program-low-income-utility), which functions like a PIPP, in 2024. The concept was first outlined by the governor in 2023, and the pilot builds on a number of existing state and utility affordability policies and programs. The pilot program caps monthly energy bills at 6% of household income for low-income households that fully electrify their space and water heating through the EmPower+ program, which provides subsidized and no-cost home energy retrofits. Funding for the pilot comes from a $50 million state budget appropriation. **Ohio — Ohio Implementation** Ohio's PIPP [began in 1983 as a result of a Public Utilities Commission of Ohio (PUCO) order](https://liheapch.acf.gov/dereg/states/ohio.htm) and is [the oldest and largest PIPP in the United States](https://liheapch.acf.gov/docs/PIPPupdate.pdf). Multiple policy and regulatory changes have revised elements of the program in the years since, including a major update in 2010 that also resulted in the program's renaming to “[PIPP Plus](https://puco.ohio.gov/utilities/gas/resources/pipp-plus)”. [Eligible households](https://development.ohio.gov/individual/energy-assistance/2-percentage-of-income-payment-plan-plus) that heat with gas pay 5% of their gross household income on their gas bill and 5% on their electric bill. Households that heat with electricity pay 10% of their gross monthly income. For customers in arrears, each monthly on-time payment results in a credit of 1/24 of their historic balance. Ohioans that receive electric or gas service from a utility regulated by PUCO and have a household income less than 175% of the federal poverty level are eligible for the program. ### Legislative Design Considerations Legislative approaches will differ state-to-state but can consider the following actions and parameters in establishing PIPPs: **Eligibility criteria:** Setting an income threshold for program eligibility (e.g., household income ≤150% or ≤200% of the federal poverty line) or defining specific target populations (e.g., low-income households, elderly, or medically vulnerable) leads to programs that reach the most in need. Legislation can also require that program administrators establish eligibility criteria that maximize affordability benefits overall or give specific consideration to these target populations. Legislators can consider including moderate-income customers to reach more households in need. **Affordability standards:** Set the target energy burden (e.g., energy bills are not to exceed 6%–10% of household income). Specifying different tiers of benefits based on income level or household size matches assistance to household needs. **Source of funding:** Establish whether the program is funded via utility bill surcharges, state budgets, federal grants, cap-and-invest programs, or utility revenues; programs are nearly always ratepayer-funded. These stipulations may include cost caps or cost allocation provisions for utilities. Paying for program costs via cuts to other beneficial programs may undermine progress toward affordability goals. **Reporting requirements:** Requiring program implementers to periodically report on program participation and cost-effectiveness leads to greater transparency and accountability. This may involve third-party evaluations or audits to provide more robust oversight. **Establishment of related policies:** Undertaking a portfolio approach that pairs PIPPs with other complementary policies can lead to a more comprehensive strategy that addresses multiple facets of electricity affordability at once. ### Case Study **Virginia** [Virginia’s Percentage of Income Payment Program](https://www.dss.virginia.gov/benefit/PIPP/index.cgi) provides long-term utility bill assistance to low-income customers of two of the state’s major utilities (Appalachian Power Company and Dominion Energy). The program was [established as part of the Virginia Clean Economy Act](https://energy.virginia.gov/renewable-energy/documents/VCEASummary.pdf), which directed the Department of Social Services and State Corporation Commission to develop and implement a PIPP. **Eligibility criteria:** Enrollment is open to households at or below 150% of the Federal Poverty Level and are customers of Dominion Energy or Appalachian Power. **Affordability standards:** The PIPP caps energy bills at 6% of household income for those with non-electric heating and 10% of household income for those with electric heating. **Source of funding:** A universal service fee on non-participating customers’ bills (about $0.79 monthly surcharge) funds the program. **Establishment of related policies:** Virginia's PIPP also involves arrearage forgiveness and energy efficiency support. If a customer has an outstanding balance with the utility, full and on-time monthly payments result in monthly arrearage forgiveness, up to one-twelfth of their outstanding utility debt each month. After 12 months of consecutive on-time payments, the prior balance is eliminated. Qualifying customers can also receive a free home energy audit and additional energy efficiency services. **Key Takeaways:** The establishment of Virginia's PIPP marked a significant shift toward improving long-term energy affordability for customers in two of the state’s major utilities, setting a model for potential expansion. By being paired with arrearage forgiveness and free energy audits, the program takes a more holistic approach that addresses multiple facets of the energy affordability challenge. ### Further Reading - [We Can End Energy Poverty in the Electric Sector: Here's How](https://rmi.org/we-can-end-energy-poverty-in-the-electric-sector-heres-how/) — RMI (2025) - [Utilities' Low-Income Discount Programs Help Address Energy Insecurity, But Some US States Lag Behind](https://www.energypolicy.columbia.edu/utilities-low-income-discount-programs-help-address-energy-insecurity-but-some-us-states-lag-behind/) — Columbia University Center on Global Energy Policy (2024) - [The Energy Poverty Policy Simulator](https://utilitytransitionhub.rmi.org/energy-poverty-policy-simulator/) — RMI (2024) --- ## Securitization URL: https://affordability-toolkit.rmi.org/policies/securitization PDF: https://affordability-toolkit.rmi.org/pdfs/securitization.pdf Securitization is a financing mechanism that allows utilities to replace high-cost debt with low-interest bonds, lowering customer bills while freeing up capital to make investments that modernize the electricity system. - **Themes:** cost control - **Safeguard:** No - **Impact time horizon:** medium — The timing of securitization impacts can range widely, but plant retirement dates are often in the range of a few years or more from the date of enactment. For example, North Carolina's securitization bill required retirement between 2 and 6 years after passage. - **Potential cost savings:** medium — Using securitization to close Public Service of New Mexico's San Juan Generating Station and investing in renewable replacement resources saved that utility's customers nearly $80 million in 2023 alone, with the average residential customer saving $6.87 per month. Actual cost savings will vary based on policy design and implementation. - **Target cost drivers:** Extreme weather/wildfires, Misaligned utility incentives ### Context and Background Securitization is a financing mechanism that allows utilities to recover certain costs at a lower expense to customers. Utilities often use securitization to retire uneconomic generation assets by paying back the remaining plant balance with low-interest, ratepayer-backed bonds, rather than the utility's higher-cost rate of return. Once legislation is in place that enables securitization, utilities may apply for regulatory approval of bonds to refinance outstanding investments or stranded costs, typically resulting in lower net present value costs and lower monthly charges to customers than traditional cost recovery through rates. In situations where securitization leads to the retirement of a generation asset, utilities can use [capital recycling](https://rmi.org/securitization-in-action/), an approach that involves taking existing plants off a utility's balance sheet and replacing that rate base with new, least-cost generation resources. This strategy improves utility earnings by helping recover some of the costs associated with the old assets and allowing them to make money from the new energy investments. States authorize the use of securitization for a variety of purposes, including the [retirement of generation facilities](https://leg.colorado.gov/sites/default/files/documents/2019A/bills/sl/2019a_sl_359.pdf), [wildfire-related costs](https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill_id=201920200AB913), and investing in energy efficiency, clean energy, [resilience](https://www.nysenate.gov/legislation/bills/2021/S6455), or [customer affordability programs](https://olis.oregonlegislature.gov/liz/2023R1/Downloads/MeasureDocument/HB3143/Introduced). Most recently, a major wave of securitization legislation followed Winter Storm Uri, enabling utilities to recover billions of dollars in extraordinary fuel costs through securitization. While this helped shield customers from abrupt, extreme rate increases, it also underscored the risks of overreliance on fuels with volatile costs. Securitization has gained traction as a tool to modernize the electricity system and free up capital for lower-cost generation resources. It has been applied in more than a dozen states and is gaining momentum as a strategic electricity affordability policy. ### Real-World Examples 13 states have securitization enacted, most of which require plant retirement for securitization.[^1] ^[1]: Source: Christian Fong, pers. com **New Mexico — New Mexico Implementation** New Mexico's Energy Transition Act ([Senate Bill 489](https://energyinnovation.org/wp-content/uploads/2020/09/Securitization-Brief_September-2020.pdf)) enabled securitization of 100% of undepreciated investment in retiring coal plants, plus related costs like decommissioning and remediation. The policy requires facility abandonment and that a portion of the proceeds from the process be used for just transition, economic development, and worker assistance in communities. Securitization must also result in utility customer savings according to the law. The legislation's use of the word "abandonment" initially raised questions, with some stakeholders debating whether this could allow a utility to sell a coal plant to another owner who could continue operating it, rather than retiring it. Subsequent developments clarified that the intent of the statute was to require retirement, not transfer of ownership, but the initial ambiguity underscores the importance of precise statutory language. **North Carolina — North Carolina Implementation** North Carolina's [House Bill 951](https://www.ncleg.gov/Sessions/2021/Bills/House/PDF/H951v5.pdf) (HB 951) requires the securitization of 50% of the remaining value of specific coal-fired generating facilities, with retirement dates established in the legislation—an innovative approach since in most other states, securitization is something optional that utilities may pursue. The policy assumes proceeds will cover costs associated with retirement and does not require funding be used for purposes like pollution abatement or worker transition. The bill also does not include formal affordability requirements and instead relies on the assumption that securitized bonds carry lower interest rates than traditional utility cost recovery. HB 951 pairs securitization with cost-saving mechanisms like performance-based ratemaking. ### Legislative Design Considerations Securitization legislation can include the following elements, which may vary from state to state: **Eligible costs:** Clearly defining what types of costs can be securitized, including undepreciated power plant value, decommissioning costs, and remediation, ensures only appropriate expenses are included.[^2] ^[2]: Legislation may authorize the securitization of both capital expenditures (capex) and operating expenditures (opex). For capex—such as the unrecovered balance of a retired power plant—securitization directly lowers costs by replacing the utility’s higher-cost return on equity and debt with lower-cost, AAA-rated, ratepayer-backed bonds. For opex—such as storm recovery or wildfire mitigation—overall cost savings are less certain as these expenses are typically passed directly through to customers without earning a return. In these cases, the primary benefit may be avoiding large, immediate rate increases by spreading cost recovery over time, even if this slightly increases total costs due to interest. **Affordability requirements:** Requiring that securitization results in net ratepayer savings compared to traditional cost recovery methods ensures customers benefit directly, and requiring fair allocation of costs across customer classes mitigates disproportionate impacts on vulnerable groups.[^3] ^[3]:Recent legislation in a number of states has specifically exempted new large loads from paying securitization charges under the rationale that these loads did not benefit from the retiring assets so should not have to pay for them. While that is true in principle, new large loads can also impose other costs that other customers become responsible for without well-designed tariffs or ringfencing. **Approval and oversight:** Empowering the commission to approve or deny financing orders, set bond terms, structure surcharges, and hire independent, expert counsel helps ensure that the financing is structured in the lowest cost way possible. Allowing for intervenor participation and public hearings during the financing order approval process builds transparency and provides additional safeguards. **Use of proceeds:** Setting requirements on using a portion of securitized funds to invest in transition assistance for affected communities and workers, electricity affordability mechanisms like bill rebates, or other state priorities can broaden the benefits of securitization. **Retirement:** Tying securitization to the permanent retirement of older generation assets can guarantee that financial savings are coupled with progress toward electricity system modernization. **Bond design:** Requiring bonds to be low-interest, high credit quality, and structured to minimize risk delivers savings and protects customers. ### Case Study **Montana** Montana’s [House Bill 467 (HB 467)](https://archive.legmt.gov/bills/2019/BillPdf/HB0467.pdf), the Montana Energy Impact Assistance Bond Act, authorizes utilities to issue ratepayer-backed bonds to finance the retirement or replacement of electricity infrastructure and facilities. The legislation aims to reduce costs to customers, modernize the grid, and support least-cost generating resources while also mitigating rate impacts from major capital expenditures. Utilities are not required to retire any specific facilities but may seek approval from the commission to securitize eligible costs when in the public interest. **Eligible costs:** Allows utilities to securitize unrecovered capital costs of retired or replaced electric infrastructure or facilities, decommissioning and site restoration costs, and other related costs approved by the commission. **Affordability requirements:** In approving securitization, utilities must demonstrate that the approach will either lower overall costs to customers or substantially mitigate rate impacts relative to traditional financing. They must also show that securitization will result in net present value savings compared to other financing options. **Approval and oversight:** The Montana Public Service Commission (PSC) reviews utility applications and issues financing orders aligned with the law. The PSC has broad authority to attach conditions to maximize savings, minimize financial risks, and protect directly impacted workers and communities. **Use of proceeds:** Proceeds may offset stranded costs from plant retirements or replacements or be invested in modernized infrastructure, least-cost generation and storage resources, and transmission or electric delivery upgrades. **Retirement:** Utilities must retire a plant for securitization to be applicable. **Bond design:** Legislation requires that securitized bonds be issued through a financing order approved by the commission with charges passed to customers. Bonds have thirty-year maturities and are secured by dedicated customer charges. **Key Takeaways:** HB 467 provides Montana utilities with a flexible securitization tool to finance the retirement or replacement of electric infrastructure while minimizing customer cost impacts. It also allows the proceeds to be funneled toward least-cost resources and grid modernization. Its effectiveness will depend on how utilities employ the tool and how rigorously the PSC uses its oversight powers to protect customers and align with long-term energy policy goals. ### Further Reading - [Securitization in Action](https://rmi.org/securitization-in-action/) — RMI (2022) - [Comparing 2019 Securitization Legislation in Colorado, Montana, and New Mexico](https://energyinnovation.org/wp-content/uploads/2020/09/Securitization-Brief_September-2020.pdf) — Energy Innovation (2020) - [The Rationale Behind U.S. Utility Securitization And Reasons For Recent Growth](https://csgwest.org/wp-content/uploads/2024/08/RatingsDirect_CreditFAQTheRationaleBehindUSUtilitySecuritizationAndReasonsForRecentGrowth_57532202_Jun-05-2024.PDF.pdf) — S&P Global Ratings (2024) - [Securitization: A Valuable Tool For Cost Recovery Opportunities Outside a Normal Rate Case](https://www.mcr-group.com/wp-content/uploads/2023/10/Securitization-White-Paper_v2.pdf) — MCR (2023) --- ## Fuel-Cost Sharing URL: https://affordability-toolkit.rmi.org/policies/fuel-cost-sharing PDF: https://affordability-toolkit.rmi.org/pdfs/fuel-cost-sharing.pdf Fuel-cost sharing is a policy that provides a financial incentive for a utility to carefully manage its fuel costs by exposing the utility to a portion of fuel-cost volatility risk, allowing a utility to earn more if it reduces fuel costs and bear a share of the burden if those costs rise. - **Themes:** cost control, cost distribution - **Safeguard:** No - **Impact time horizon:** medium — For example, Nevada passed [legislation](https://www.leg.state.nv.us/App/NELIS/REL/83rd2025/Bill/12684/Text) (A.B. 452), effective July 1, 2025, requiring the PUC to open an investigatory docket on fuel cost sharing. The legislation requires the PUC to submit a report to the legislature on the outcomes of the docket by July 1, 2026, and authorizes the PUC to implement fuel-cost sharing if it is in the public interest. Following implementation of fuel-cost sharing mechanisms, regulators often perform true-ups [annually](https://rmi.org/insight/strategies-for-encouraging-good-fuel-cost-management/). - **Potential cost savings:** medium — While savings will vary with policy design and implementation, fuel-cost sharing promotes affordability by creating an incentive to reduce fuel costs and reducing bill volatility. Fuel costs represent a major portion of customer electric bills, roughly 25% over the course of the year, and reducing those costs directly translates into customer savings. Volatile bills have a destabilizing effect on customers and can lead to customers falling behind on their bills, racking up late fees, and eventually losing service. - **Target cost drivers:** Fuel price volatility, Misaligned utility incentives ### Context and Background Fuel-cost sharing is a policy that provides a financial incentive for a utility to carefully manage its fuel costs by exposing the utility to a portion of fuel-cost volatility risk, allowing a utility to earn more if it reduces fuel costs and bear a share of the burden if those costs rise. In most vertically integrated states, all fuel costs are passed through to customers with what is often called a fuel adjustment clause (FAC). A FAC allows utilities to recover the exact fuel costs they incurred from customers, facing no risk if they spend more than expected on fuel and not benefiting from any savings if they spend less than expected. Alternatively, [fuel-cost sharing](https://rmi.org/insight/strategies-for-encouraging-good-fuel-cost-management/) mechanisms work by building an expected amount of utility spending on fuel costs into customer rates and then exposing a utility to a certain percentage of its fuel costs if it deviates from the expected value. If a utility spends more than expected on fuel costs, it pays a portion of the difference between expected vs. actual costs rather than passing it completely through to customers, and vice versa if a utility spends less than expected on fuel costs. For example, suppose a utility's expected fuel costs are $100 million, and they have a 10% fuel-cost sharing mechanism. If the utility spends $110 million on fuel, they are on the hook for $1 million (10 million x 10%) and recover the remaining $9 million from customers. If the utility can manage its fuel costs and only spends $90 million, they get to keep $1 million of the underspend, while the remaining $9 million difference between actual and expected fuel costs is returned to customers. In [2024 alone](https://www.eia.gov/electricity/data/browser/#/topic/12?agg=2,0,1&fuel=vtvv&geo=g&sec=g&freq=A&start=2023&end=2024&ctype=linechart<ype=pin&rtype=s&maptype=0&rse=0&pin=), utilities spent $71 billion on fuel costs for electricity generation, so any incentive for utilities to spend less on fuel can provide substantial savings to utilities and customers alike. With [volatile natural gas prices](https://www.eia.gov/todayinenergy/detail.php?id=62203) in recent years and some states relying on natural gas for as much as [83% of their electricity generation](https://ember-energy.org/data/us-electricity-data/), fuel-cost sharing mechanisms can be an important tool to protect customers from some of this risk and encourage better fuel-cost management by utilities. In practice, fuel-cost sharing mechanisms can be customized for different utilities along many dimensions, such as the level of sharing, how the expected amount is set, and more to incentivize utilities to manage their fuel costs in a manner that is aligned with the best interests of customers. As of 2025, nine states utilize some type of fuel-cost sharing mechanism for electric utilities, and state legislatures can play an important role in directing or requiring public utility commissions (PUCs) to implement fuel-cost sharing mechanisms in their states. These nine states are Hawaii, Idaho, Missouri, Montana, Oregon, Vermont, Washington, Wisconsin, and Wyoming. In 2025, [Nevada](https://www.leg.state.nv.us/App/NELIS/REL/83rd2025/Bill/12684/Text) legislators directed the PUC to study the potential of implementing a fuel-cost sharing mechanism. ### Real-World Examples As of August 2025, nine states (based on RMI’s [PIMs database](https://pims.rmi.org/)) have electric utilities subject to fuel cost sharing: Hawaii, Idaho, Missouri, Montana, Oregon, Vermont, Washington, Wisconsin, and Wyoming. Nevada has recently passed authorizing legislation. **Montana — Montana Implementation** The Montana legislature modified state code (Mont. Code Ann. § 69-3-331) in 2019 to require a [10% sharing mechanism](https://pims.rmi.org/details/185) for NorthWestern Energy’s purchased power and fuel costs outside of a forecasted amount. **Wisconsin — Wisconsin Implementation** Wisconsin state code (Wis. Admin. Code § PSC 116) requires all investor-owned utilities to operate under a [fuel cost tolerance mechanism](https://pims.rmi.org/details/203) where purchased power and fuel costs inside a +/- 2% forecasted range are absorbed by utilities and costs/savings outside the range are allocated to customers. The fuel cost tolerance has been in effect since 2011. **Wyoming — Wyoming Implementation** Wyoming implemented a 20% [purchased power and fuel-cost sharing mechanism](https://pims.rmi.org/details/209) in 2011 for Rocky Mountain Power. The new mechanism replaces Rocky Mountain Power's Power Cost Adjustment Mechanism which included a deadband of no sharing and three bands of different sharing percentages. ### Legislative Design Considerations Legislation on fuel-cost sharing mechanisms can include the following elements: **PUC directive:** Legislation can direct regulators to study the use of fuel-cost sharing mechanisms in their state, allow regulators to approve fuel-cost sharing mechanisms proposed by utilities, or require the use of fuel-cost sharing mechanisms by certain utilities. **Policy structure:** Fuel-cost sharing mechanisms can include a [variety of design components](https://rmi.org/insight/strategies-for-encouraging-good-fuel-cost-management/) like deadbands, sharing symmetry, the method for setting the expected value, the frequency and method of conducting true-ups, and the actual sharing percentage, among many other potential components. Legislation can specify key components for regulators to consider when designing the fuel-cost sharing mechanism to provide more guidance for regulators as they develop and implement the mechanism. **Reporting and transparency:** In addition to enabling the use of fuel-cost sharing mechanisms, legislation can include provisions like regular prudence reviews or audits of utility fuel management practices to enhance transparency and oversight. **Customer protections:** Including provisions like maximum rate increase caps, protections for low-income customers, or the expansion of energy assistance programs can safeguard customers. ### Case Study **Missouri** All of Missouri’s [investor-owned utilities](https://pims.rmi.org/?_gl=1*1rp6v1m*_gcl_au*MTcyMTA4OTA1OS4xNzQ0MjE2NDQ3) — Ameren Missouri, Liberty, Evergy West, and Evergy Metro — operate under fuel-cost sharing mechanisms called fuel adjustment clauses with 5% utility sharing. While FACs in most states pass through 100% of costs to customers, Missouri’s FACs function as fuel-cost sharing mechanisms. [Prior to 2005](https://efis.psc.mo.gov/Document/Display/92123), FACs were deemed unlawful by the Missouri Supreme Court because they would allow rates to go into effect without a general rate case which could consider all relevant factors. However, in 2005, the legislature enacted [SB 179](https://www.senate.mo.gov/05info/pdf-bill/tat/SB179.pdf), which allowed the Missouri Public Service Commission (PSC) to implement FACs and include incentives designed to improve the efficiency and cost-effectiveness of utility fuel and power purchases. Ultimately, the PSC determined that passing 100% of fuel costs through to customers would not incentivize utilities to prudently manage their fuel costs and settled on a 5% utility sharing level for each utility. In addition to the legislative details highlighted above, [SB 179](https://www.senate.mo.gov/05info/pdf-bill/tat/SB179.pdf) includes the following specific provisions regarding the use of FACs in the state: **Policy structure:** Prudently incurred fuel and purchased power costs can be tracked and recovered in a FAC. In practice, fuel and purchased power costs are included in the FACs for each of Missouri’s investor-owned utilities. **PSC directive:** SB 179 gave the PSC broad authority to establish incentives to encourage more efficient fuel and purchased power cost management, including establishing a FAC. The PSC can approve, modify, or reject FACs only after a full hearing in a general rate case. After the PSC approved a 5% sharing mechanism for [Evergy West](https://www.efis.psc.mo.gov/Document/Display/102672) in 2007, they subsequently approved 5% sharing mechanisms for [Liberty](https://www.efis.psc.mo.gov/Document/Display/107617), [Ameren Missouri](https://www.efis.psc.mo.gov/Document/Display/116411), and [Evergy Metro](https://www.efis.psc.mo.gov/Document/Display/83558) in 2008, 2009, and 2015, respectively. **Reporting and transparency:** The PSC must conduct prudence reviews of the costs included in the FAC at least once every eighteen months, conduct true-ups of the FAC at least once per year, and require FACs to appear as a separate line item on customer bills. In practice, true-ups occur at the end of each recovery period (either 8 or 12 months depending on the utility) where the PSC evaluates the actual incurred costs relative to the costs included in permanent rates and adjusts the FAC to credit or charge customers depending on if costs were lower or higher than expected, respectively. **Key Takeaways:** Between 1979 and 2006, electric utilities in Missouri covered 100% of their fuel and purchased power costs. In response to volatile natural gas prices adversely impacting smaller utilities, the Missouri legislature passed SB 179 in 2005, which granted the PUC authority to implement a FAC and establish incentive mechanisms to encourage more prudent management of fuel and purchased power costs. As a result of this second key provision, the PSC adopted 5% fuel-cost sharing mechanisms for each of Missouri’s investor-owned utilities, which helps protect customers from volatile fuel power supply costs while incentivizing utilities to efficiently manage these costs. ### Further Reading - [Strategies for Encouraging Good Fuel-Cost Management](https://rmi.org/insight/strategies-for-encouraging-good-fuel-cost-management/) — RMI (2023) - [Learning to Share: A Primer On Fuel-Cost Pass-Through Reform](https://www.ourfinancelab.com/post/can-we-share-the-cost-of-fuel) — Albert Lin, Jeremy Kalin, and Kaja Rebane (2023) - [How Fuel Cost-Sharing Can Deliver Savings for Utility Customers](https://rmi.org/resources/how-fuel-cost-sharing-can-deliver-savings-for-utility-customers/) — RMI (2026) - [Fuel Cost Sharing Analysis](https://utilitytransitionhub.rmi.org/fuel-cost-sharing-analysis-overview/) — RMI (2026) - [Fuel Cost-Sharing and Utility Returns](https://www.veredaadvisory.com/fuel-cost-sharing) — Vereda Advisory (2026) --- ## Virtual Power Plants URL: https://affordability-toolkit.rmi.org/policies/virtual-power-plants PDF: https://affordability-toolkit.rmi.org/pdfs/virtual-power-plants.pdf Virtual power plants (VPPs) are aggregations of distributed energy resources (DERs) like electric vehicles, solar and/or battery storage, heat pumps, smart thermostats, and more. VPPs promote affordability by cost-effectively providing a variety of grid services and compensating participating customers. - **Themes:** cost control, customer agency - **Safeguard:** No - **Impact time horizon:** short — VPPs can be implemented within [6-12 months](https://rmi.org/wp-content/uploads/dlm_uploads/2024/06/VPP_reliability_brief.pdf). - **Potential cost savings:** high — While cost savings will vary with policy design and implementation, [VP3's PowerShift](https://rmi.org/insight/power-shift/) report found VPP-enabled resource portfolios can reduce net power generation costs by 20% relative to the status quo - about $400 million per year or $140 per household per year for an illustrative state electricity system. In another study, [Brattle](https://www.brattle.com/wp-content/uploads/2023/04/Real-Reliability-The-Value-of-Virtual-Power_5.3.2023.pdf) found that 60 GW of VPPs in the United States could reduce resource adequacy costs by $15 billion-$35 billion over ten years ($1.5 billion-$3.5 billion per year). - **Target cost drivers:** Load growth, Aging grid infrastructure, Misaligned utility incentives, Extreme weather/wildfires, Fuel price volatility ### Context and Background [Virtual power plants (VPPs)](https://rmi.org/insight/virtual-power-plant-flipbook/) are aggregations of distributed energy resources (DERs) like electric vehicles, solar and/or battery storage, heat pumps, smart thermostats, and other demand response (DR) technologies. By coordinating the dispatch of DERs, VPPs can provide a variety of grid services including energy, capacity, resilience, and ancillary services such as frequency and voltage regulation. VPPs can help meet peak demand at lower cost than conventional resources and defer the need for costly transmission and distribution system investments, saving customers and utilities money. While all customers can benefit from the reduction in system costs which VPPs provide, customers who participate in VPPs can gain more control over their electricity bills and save money by earning participation incentives and reducing their electricity usage. VPPs can be deployed in as little as [6-12 months](https://rmi.org/wp-content/uploads/dlm_uploads/2024/06/VPP_reliability_brief.pdf), are highly adaptable, and directly address major cost drivers like load growth and transmission and distribution investment. Because of these factors, VPPs can empower customers and provide sustainable cost savings for the long term. State legislatures can enable VPP deployment by supporting DER adoption for all customers (e.g., through tax credits or rebates), directing public utility commissions (PUCs) to study the potential impact of VPPs in their state, requiring the development of utility incentives to grow VPPs, removing rules that prevent demand response from participating in wholesale markets, requiring utilities to create VPP offerings, and establishing statewide VPP capacity goals. ### Real-World Examples As of 2025, at least [five states](https://static1.squarespace.com/static/5ac5143f9d5abb8923a86849/t/67a68454ac578d0b39251fc1/1738966103047/2024-VPP-Report-Final.pdf) have passed VPP-related legislation. In 2024, an additional six states introduced VPP-related legislation. **California — California Implementation** California enacted [legislation](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=202120220AB205) (A.B. 205) in 2022 authorizing the California Energy Commission (CEC) to implement and administer the Demand Side Grid Support (DSGS) Program, a VPP which provides peak load reduction during summer extreme weather events. To date, the [program has enrolled](https://www.canarymedia.com/articles/virtual-power-plants/california-budget-demand-side-grid-support) over 800 MW of capacity across hundreds of thousands of controllable customer-owned devices. However, the program's [funding was cut](https://www.utilitydive.com/news/california-zeroes-out-funding-for-largest-virtual-power-plant/760274/) as part of California's 2025 budget negotiations. The [CEC](https://content.govdelivery.com/accounts/CNRA/bulletins/3f5436e) intends to propose potential changes to the program for the 2026 season to align with its new projected funding level. **Maryland — Maryland Implementation** Maryland passed the [Distributed Renewable Integration and Vehicle Electrification (DRIVE) Act](https://mgaleg.maryland.gov/mgawebsite/Legislation/Details/hb1256?ys=2024RS) (H.B. 1256) in 2024, requiring investor-owned utilities to file VPP pilot programs with the Maryland Public Service Commission (PSC) by July 1, 2025. The legislation also directs the PSC to consider establishing a process for transitioning to a permanent VPP program if they determine it is in the public interest. In October 2025, the [PSC issued an order](https://www.psc.state.md.us/wp-content/uploads/MD-PSC-Orders-Utilities-to-Scale-Up-DRIVE-Act-Proposals_10212025.pdf) directing utilities to submit revisions to their pilot proposals, including expanding the scale of their pilot programs by targeting broader customer participation. **Virginia — Virginia Implementation** Virginia passed [legislation](https://lis.virginia.gov/bill-details/20251/HB2346/text/CHAP0709) (H.B. 2346) in 2025, which requires Dominion Energy to propose a 450 MW VPP pilot program by the end of 2025. Following the pilot's conclusion in 2028, the State Corporation Commission must initiate a proceeding to establish a permanent program. ### Legislative Design Considerations Legislation can include the following components: **Eligible technologies:** Allowing a variety of DR/DER technologies to participate in VPPs can maximize customer eligibility and the benefits of VPPs. **Customer adoption:** Directing regulators to enhance program opportunities and compensation for vulnerable communities can increase adoption of DERs and participation in VPPs across all customers. **Enabling policies:** A range of legislative approaches can promote VPP deployment based on how advanced VPP development is in a given state. Bolstering incentives for DER adoption, directing PUCs to conduct proceedings on VPP development, ensuring that grid services from aggregated DERs are sufficiently considered in utility planning processes, removing rules that prevent demand response from participating in wholesale markets, or creating VPP programs and tariffs can all support VPP deployment. **Program harmonization:** Sometimes past regulation and legislation has led to management of DERs and VPPs through a number of uncoordinated programs and regulatory dockets. Legislation can seek to integrate existing approaches into a more rational, harmonized, and consistent approach. **Program scale:** Directing regulators to establish scalable programs and create utility capacity procurement targets for VPP programs can create a pathway for programs to progress beyond the pilot stage. **Grid services:** Allowing VPPs to be compensated for multiple grid services (capacity, frequency regulation, etc.) can maximize their value for utilities and customers while ensuring fair compensation to participants. **Utility incentives:** Directing/requiring regulators to establish revenue opportunities like performance incentive mechanisms (PIMs) tied to VPP deployment, adoption, and utilization can encourage utility support for VPP programs. ### Case Study **Colorado** Colorado passed the [Modernize Energy Distribution Systems Act in 2024](https://leg.colorado.gov/sites/default/files/2024a_218_signed.pdf) to pave the way for VPP development in the state. The legislation requires Xcel Energy, the largest electric utility in the state, to submit a plan for a VPP program and a tariff for performance-based compensation to the Colorado PUC by February 1, 2025. Critically, the legislation requires Xcel Energy to develop a fully-fledged VPP program rather than a pilot program with the potential for expansion down the road. As of August 2025, the Colorado PUC is reviewing Xcel Energy's [application](https://www.dora.state.co.us/pls/efi/EFI.Show_Docket?p_session_id=&p_docket_id=25A-0061E) for a VPP, which would be deployed in 2026 and grow to 125 MW by 2030. **Grid services:** The legislation specifies several grid services for which the VPP should be compensated, including local and system peak reduction, transmission and distribution investment avoidance or deferral, and voltage support, among others. This allows the grid to more fully benefit from the services VPPs can provide. **Eligible technologies:** The law is technology neutral as it does not explicitly state which DR/DER technologies should be included or excluded from the VPP program. **Customer adoption:** The legislation does not contain any provisions designed to facilitate low-income household participation in the VPP program. **Key Takeaways:** Through this legislation, Colorado has paved the way for its residents to experience the cost savings that VPPs can provide. Overall, the legislation establishes clear criteria that the VPP must fulfill, like grid services, while allowing Xcel Energy and the Colorado PUC to determine other key components of the VPP. ### Further Reading - [How Virtual Power Plants Can Help the United States Win the AI Race](https://rmi.org/how-virtual-power-plants-can-help-the-united-states-win-the-ai-race/) — RMI (2025) - [Power Shift](https://rmi.org/insight/power-shift/) — RMI (2024) - [VPP Policy Principles](https://rmi.org/insight/vpp-policy-principles/) — RMI (2024) - [Virtual Power Plant Flipbook](https://rmi.org/insight/virtual-power-plant-flipbook/) — RMI (2025) - [Virtual Power Plants: Insights, Profiles, and Inventory](https://emp.lbl.gov/publications/virtual-power-plants-insights) — Lawrence Berkeley National Laboratory (2025) - [VP3 Progress Report: From Awareness to Action](https://rmi.org/insight/vp3-progress-report-from-awareness-to-action/) — RMI (2025) - [Pathways to Commercial Liftoff: Virtual Power Plants 2025 Update](https://static1.squarespace.com/static/67f555826ee1df58205ff806/t/6827b036c404a667b1385264/1747431490309/Liftoff_DOE_Virtual+Power+Plants+%28UPDATE%29_Jan+2025.pdf) — U.S. Department of Energy (2025) --- ## Bill Rebates URL: https://affordability-toolkit.rmi.org/policies/bill-rebates PDF: https://affordability-toolkit.rmi.org/pdfs/bill-rebates.pdf Electric bill rebates can be issued on a one-time or recurring basis to provide immediate, targeted relief to customers. - **Themes:** cost distribution - **Safeguard:** No - **Impact time horizon:** short — Bill rebates can be distributed quickly and provide immediate relief to households. - **Potential cost savings:** low — While cost savings will vary with policy design and implementation, bill rebates are infrequently distributed and are often less than a single monthly electric bill. For example, [Massachusetts](https://www.mass.gov/news/healey-driscoll-administration-announces-energy-affordability-agenda-to-deliver-220-million-in-immediate-relief-save-58-billion-over-5-years) issued a $50 bill rebate (~2% of [average annual electricity costs](https://www.eia.gov/electricity/sales_revenue_price/pdf/table_5A.pdf)) while the [California Climate Credit](https://www.cpuc.ca.gov/industries-and-topics/natural-gas/greenhouse-gas-cap-and-trade-program/california-climate-credit/california-climate-credit---faq) is often less than $100 per year (~6% of average annual electricity costs). - **Target cost drivers:** Aging grid infrastructure, Fuel price volatility, Extreme weather/wildfires, Load growth, Misaligned utility incentives ### Context and Background Distributing bill rebates is one way that states can provide immediate relief for households facing high electricity bills. States like [New York](https://www.governor.ny.gov/news/governor-hochul-announces-200-million-utility-bill-relief-8-million-new-yorkers) and [Massachusetts](https://www.mass.gov/info-details/governor-healeys-energy-affordability-agenda) have provided one-time bill credits to customers while [California](https://www.cpuc.ca.gov/industries-and-topics/natural-gas/greenhouse-gas-cap-and-trade-program/california-climate-credit/california-climate-credit---faq) provides the bi-annual California Climate Credit to residential and small business customers each year using funds from the state's cap and trade program. [Pennsylvania](https://www.pa.gov/governor/newsroom/2025-press-releases/governor-shapiro-launches-legislative-push-for--lightning-plan--.html) is also considering a cap-and-trade program as part of its Lightning Plan where 70 percent of the revenue generated would be returned to electricity customers in the form of credits. As bill rebates do not directly reduce electricity system costs, the frequency, funding source, and target populations are factors which play a key role in determining the overall effectiveness of bill rebates as an electricity affordability policy. One-time bill rebates can provide valuable relief for households but do not provide sustainable relief over the long term. Funding bill rebates with excess funds or from ratepayer-funded programs that have already achieved their goals could provide a more positive overall impact on affordability compared to cutting other programs to pay for bill rebates. However, funding rebates from efforts that support systemwide and individual customer affordability, like energy efficiency, may have unintended consequences over the medium or long term. Lastly, states can provide bill rebates to all customers or target specific populations like low- to moderate-income (LMI) customers to tailor the impact of their bill rebates. ### Real-World Examples At least six states have utilized bill rebates to promote electricity affordability: California, Delaware, Massachusetts, New Jersey, New York, and Pennsylvania (proposed legislation). **Pennsylvania — Pennsylvania Climate Emissions Reduction Act (PACER, S.B. 503)** As part of Governor Shapiro’s Lightning Plan, legislators in Pennsylvania introduced the [Pennsylvania Climate Emissions Reduction Act (PACER, S.B. 503)](https://www.palegis.us/legislation/bills/2025/sb503) in 2025. [PACER](https://www.palegis.us/legislation/bills/text/PDF/2025/0/SB0503/PN0770) would establish a cap-and-invest program where 70% of the auction proceeds would be returned directly to electric customers in the form of a bill rebate. **New York — 2024 One-Time Utility Bill Credit** In 2024, the [New York Public Service Commission (PSC)](https://www.governor.ny.gov/news/governor-hochul-announces-200-million-utility-bill-relief-8-million-new-yorkers) approved a $200 million one-time bill credit that was distributed to over 8 million electric and gas customers. Funds for the credit came from a state appropriation and the credit was designed by the Energy Affordability Policy working group in conjunction with the Department of Public Service. The working group considered several policy proposals and presented their plan to the PSC who ultimately approved it. ### Legislative Design Considerations Electric bill rebate legislation can include the following parameters: **Source of funding:** The source of funding for bill rebates is a critical decision for states, which influences the overall impact on electricity affordability. Paying for bill rebates by cutting other ratepayer-funded programs could have an adverse impact on affordability in the long term, especially if they are cost-effective approaches that contribute to systemwide and individual customer affordability. Utilizing excess funds or tying bill rebates to revenue-generating programs like cap-and-trade can provide short-term relief without impacting long-term affordability. An additional consideration is whether to fund bill rebates through taxpayer, ratepayer, or utility shareholder funds. It is critical to understand the affordability impacts on different households if funding bill rebates through taxpayer funds vs. ratepayer funds (e.g., tax burden vs. energy burden). **Design details:** Consider providing bill rebates to all customers or specific customer groups, depending on state policy objectives and unique affordability contexts. In legislation, states can explicitly specify how the rebates should be distributed among customers or require the agency administering the rebates to study the optimal distribution of rebates to maximize their impact on electricity affordability. **Rebate cadence:** Considering factors like available funding and the energy burden of different customer groups can help determine whether one-time or recurring bill rebates make the most sense. Recurring rebates provide more sustainable relief for households but may not be financially prudent for some states. ### Case Study **California** California distributes bi-annual electric bill rebates to all residential and small business customers of non-public electric utilities in the form of the [California Climate Credit](https://www.cpuc.ca.gov/industries-and-topics/natural-gas/greenhouse-gas-cap-and-trade-program/california-climate-credit/california-climate-credit---faq). The California Public Utilities Commission (CPUC) directs utilities to distribute the credits using funds generated by California’s cap-and-trade program, which was established to achieve the emissions reductions goals created in the Global Warming Solutions Act of 2006. Since the credits were first issued in 2014, [over $16 billion](https://www.cpuc.ca.gov/industries-and-topics/natural-gas/greenhouse-gas-cap-and-trade-program/california-climate-credit/california-climate-credit---faq) in credits have been distributed to households.[^1] ^[1]: Residential customers also receive a natural gas California Climate Credit. Small business customers only receive the electric California Climate Credit. The California cap-and-trade program was first authorized by the [Global Warming Solutions Act of 2006](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=200520060AB32) (A.B. 32) and subsequently extended to 2030 by [A.B. 398](https://calmatters.digitaldemocracy.org/bills/ca_201720180ab398) in 2017. The CPUC was given broad authority by the legislature to distribute the greenhouse gas allowance revenues by electric utilities to customers, and they developed a method where each residential and small business customer of a utility receives an equal bill rebate. **Source of funding:** The California cap-and-trade program was first authorized by the [Global Warming Solutions Act of 2006](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=200520060AB32) (A.B. 32) and subsequently extended to 2030 by [A.B. 398](https://calmatters.digitaldemocracy.org/bills/ca_201720180ab398) in 2017. In [2012](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M040/K631/40631611.PDF), the California legislature ([S.B. 1018](https://legiscan.com/CA/text/SB1018/id/658114)) granted broad authority to the CPUC to develop a methodology for distributing the greenhouse gas allowance revenues generated by electric utilities directly to residential and small business electricity customers. **Design details:** The credits vary by utility depending on their forecasted greenhouse gas allowance auction proceeds, but each residential and small business customer of the same utility receives the same amount. [In response](https://www.cpuc.ca.gov/-/media/cpuc-website/industries-and-topics/reports/cpuc-response-to-executive-order-n-5-24.pdf) to a 2024 executive order issued by Governor Newsom, the CPUC recently identified alternative distribution methodologies of the California Climate Credit, which could maximize its benefit for households disproportionately impacted by higher electricity rates, specifically low-income households and households without rooftop solar, rather than distributing the credit to all customers evenly. **Rebate cadence:** In addition to developing a distribution methodology, the [CPUC approved](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M040/K631/40631611.PDF) a semi-annual rebate cadence in 2012. Today, most customers receive the credits on their April and October electric bills. In the same response to a 2024 executive order mentioned above, the CPUC provided considerations for distributing the credit on a volumetric basis, which could promote electrification and help smooth volatility in monthly bills for customers. **Key Takeaways:** California established the California Climate Credit to help ease the burden of rising electricity rates due to the state's cap-and-trade program. The rebates provide a recurring source of relief for households and small businesses and are directly tied to California's emissions reductions goals through the cap-and-trade program. ### Further Reading - [California Climate Credit: Frequently Asked Questions](https://www.cpuc.ca.gov/industries-and-topics/natural-gas/greenhouse-gas-cap-and-trade-program/california-climate-credit/california-climate-credit---faq) — California Public Utilities Commission (2025) --- ## Cost-Effective Wildfire Management URL: https://affordability-toolkit.rmi.org/policies/cost-effective-wildfire-management PDF: https://affordability-toolkit.rmi.org/pdfs/cost-effective-wildfire-management.pdf Cost-effective wildfire management involves a variety of strategic approaches that reduce the risk and impact of wildfires on the electricity system while aiming to preserve electricity affordability. - **Themes:** cost control, cost distribution - **Safeguard:** No - **Impact time horizon:** variable — This section assesses the timelines over which policy may impact utility investments and processes, rather than the timeline over which wildfire impacts themselves may change. - **Planning: short.** Planning efforts can have an immediate impact on actions, but the full benefits depend on how quickly plans are implemented. - **Mitigation: medium.** Actions like vegetation management may occur in the short term, but large infrastructure upgrades like undergrounding typically take at least 3-5 years. - **Cost Distribution: variable.** Cost recovery for wildfire-related expenses can begin immediately if they are included in a cost tracker, but utilities often recover costs from larger capital investments over much longer time horizons through the rate base. The structural impacts of cost distribution, such as how financial stability affects a utility's ability and willingness to invest, may also emerge over a longer time horizon. The duration of litigation can introduce another source of variability to cost distribution. - **Potential cost savings:** variable — The effects of mitigation techniques on wildfire damages and liabilities vary, and accurately estimating avoided losses is inherently difficult. Cost impacts for low-income households depend on affordability protections and cost distribution approaches if applicable. - **Target cost drivers:** Extreme weather/wildfires ### Context and Background Cost-effective wildfire management includes a variety of strategic approaches to electricity system operations, technologies, and planning that reduce the risk and impact of wildfires on the system while aiming to preserve electricity affordability. As more intense wildfires occur in places like the Western United States, costs to the electricity system are increasing substantially. These costs come from a number of interconnected factors: the increased need to mitigate wildfire risk (e.g., by undergrounding power lines), wildfire lawsuit claims when infrastructure causes costly fires, high premiums for utility liability insurance, increased capital spending to repair equipment that fails during fires, and utility credit rating downgrades associated with elevated risk. In California, for example, [16 percent](https://energyinnovation.org/wp-content/uploads/Clean-Energy-Isnt-Driving-Power-Price-Spikes.pdf) of the total cost to customers in the state's three largest investor-owned utilities now comes from wildfire-related costs. In some states, the legal and financial landscape compounds the challenges associated with wildfire risk. Under California's doctrine of inverse condemnation, utilities can be held liable for wildfire damages caused by their equipment even without negligence and regardless of other contributing factors. This liability framework, combined with the growing risk of intense fires, leads to steep and unpredictable costs for utilities and their customers. To mitigate the costs utilities may face, some states have adopted liability caps, which limit how much they must pay and shift a portion of the risk to property owners or the state. Utilities may manage wildfire risk independently, but establishing regulatory processes helps ensure that utilities are in fact managing risk and doing so in a way that is transparent and cost-effective. Legislation can establish these processes and support strategies to identify and assess wildfire risks, mitigate risks, and ensure risks are distributed fairly among taxpayers, ratepayers, shareholders, and individual. For example, legislation can authorize the creation and terms of use of wildfire self-insurance funds, which are essential to keeping utilities out of bankruptcy when a particularly bad fire comes around and serve as a key mechanism of affordability. Integrated resource plans (IRPs), distribution system plans (DSPs), and risk-specific plans like wildfire mitigation plans provide direct opportunities for risk management.[^1] Dockets and rate cases may address elements of wildfire risk but tend to be less well-suited for comprehensive risk management. Legislation can require addressing wildfire risks through established planning processes or other venues. ^[1]: [Oregon's Distribution System Plan](https://portlandgeneral.com/about/who-we-are/resource-planning/distribution-system-planning) serves as an illustrative example. ### Real-World Examples Utilities in at least [19 states](https://www.pnnl.gov/publications/pnnl-releases-database-tracking-wildfire-mitigation-plans-nationwide) have wildfire mitigation plans, and at least 12 states have state-level requirements, often legislated, that directly address wildfire-related planning, mitigation, or cost distribution within the electricity sector. **California — California Implementation** California requires utilities to file annual wildfire mitigation plans. Oversight and enforcement are shared, with the Office of Energy Infrastructure and Safety (an independent agency) reviewing and approving plans, the utility commission enforcing compliance and determining cost recovery, and CalFire providing technical input. Liability follows inverse condemnation, but utilities may access a wildfire liability fund to cover the cost of wildfire-related damages if the commission finds they acted reasonably and complied with safety requirements. Both utility customers and shareholders contribute to the wildfire fund with fixed annual shareholder charges and capped ratepayer surcharges. California's wildfire management requirements for utilities result from a number of statutes, including [Senate Bill 901](https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill_id=201720180SB901) and the 2019 Wildfire Legislation — [Assembly Bill 1054](https://legiscan.com/CA/text/AB1054/id/2046243) and [Assembly Bill 111](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=201920200AB111). **Utah — Utah Implementation** Utah requires wildfire mitigation plans from utilities, and utilities are shielded from claims if they follow an approved plan. Plans do not include ratepayer protections like cost-effectiveness or affordability tests. The commission reviews utility plans but has limited enforcement mechanisms. Customer bill surcharges (capped to protect ratepayers) support a fund that pays for wildfire-related damages, which are capped at $450,000 per person unless there is a case of wrongful death. Utah established these requirements for utilities through 2024's [Senate Bill 224](https://le.utah.gov/~2024/bills/static/SB0224.html). ### Legislative Design Considerations Legislative approaches to cost-effective wildfire management will differ state-to-state but can consider the following actions and parameters: **Policy structure:** Designing policy to address a combination of the processes relevant for wildfire risk management ensures comprehensiveness. Comprehensive policy addresses at least these three components: risk identification and assessment (i.e., planning), risk mitigation (i.e., action), and the distribution of costs related to mitigation, damages, or liability. **Affordability requirements:** Ensuring ratepayer protections are baked into bill surcharges or other payment mechanisms — e.g., by requiring transparency and independent review of utility expenditures, setting spending guardrails, or providing targeted rate assistance for low-income communities — helps protect households from disproportionate financial burdens and builds public trust. **Source of funding:** Establish to what extent funding comes from shareholders, ratepayers, taxpayers, or others with an eye toward fair cost distribution. **Regulatory enforcement:** Direct utilities to conduct proactive wildfire planning integrated with other planning efforts (e.g., DSPs or IRPs), and require utilities to follow approved mitigation measures, report on implementation progress, and justify costs. Provide state agencies the authority to audit, revise, or reject wildfire plans and impose penalties for non-compliance. Consider mandating that utilities revise plans if they exceed authorized budgets or fall short of established requirements. **Liability framework:** Clarify under what conditions utilities are shielded from or subject to legal liability for fire-related damages to balance utility protection with public accountability. **Reporting and transparency:** Require utilities to make plans public and submit regular public reports on mitigation goals, expenditures, and outcomes to ensure oversight and transparency. ### Case Study **Washington** Washington’s [House Bill (HB) 1539](https://app.leg.wa.gov/billsummary?BillNumber=1539&Initiative=False&Year=2025) established a Wildfire Mitigation and Resiliency Standards Work Group tasked with developing recommendations for utility wildfire mitigation planning and implementation. The bill itself does not mandate specific actions by utilities but provides a foundation for coordinated statewide policy to address wildfire risk in a cost-effective way. As of 2025, the Work Group is actively meeting and must submit recommendations to the legislature and key agencies within a set timeline. **Policy structure:** [HB 1539](https://app.leg.wa.gov/billsummary?BillNumber=1539&Initiative=False&Year=2025) addresses wildfire planning, mitigation, and cost allocation by creating a structure for strong coordination between parties, including utilities, fire authorities, local governments, insurers, and others. **Source of funding:** The legislation does not establish a funding mechanism but directs the Work Group to evaluate cost-effectiveness and fair cost allocation among utilities, ratepayers, and others. **Regulatory enforcement:** The bill positions the Work Group to recommend future regulation. **Reporting and transparency:** The Work Group must hold public meetings, solicit stakeholder input, and submit a final public report with policy recommendations to the legislature and governor. **Timeline:** The bill includes a near-term deadline for the Work Group to deliver recommendations, but it does not establish a permanent planning framework or mandate any resulting legislative or regulatory action. **Key Takeaways:** HB 1539 does not impose binding requirements on utilities but instead establishes structure and process for developing comprehensive recommendations that inform future regulatory and legislative work to address wildfire risks. ### Further Reading - [Reimagining Utility Climate Risk Planning](https://rmi.org/reimagining-utility-climate-risk-planning/) — RMI (2024) - [Climate change and utility wildfire risk: A proposal for a federal backstop](https://www.hamiltonproject.org/wp-content/uploads/2025/05/20240522_THP_Climate_Wildfire_Proposal.pdf) — The Hamilton Project (2024) - [Dynamic Grid Management Technologies Reduce Wildfire Adaptation Costs in the Electric Power Sector](https://haas.berkeley.edu/wp-content/uploads/WP347.pdf) — University of California Berkeley Energy Institute at Haas (2025) - [Current Practices in Distribution Utility Resilience Planning for Wildfires](https://www.energy.gov/sites/default/files/2024-10/UtilityResiliencePlanningPracticesforHazards-Wildfire.pdf) — National Renewable Energy Laboratory (2024) - [Clean Energy Isn't Driving Power Price Spikes](https://energyinnovation.org/wp-content/uploads/Clean-Energy-Isnt-Driving-Power-Price-Spikes.pdf) — Energy Innovation (2024) --- ## Disconnection Protections URL: https://affordability-toolkit.rmi.org/policies/disconnection-protections PDF: https://affordability-toolkit.rmi.org/pdfs/disconnection-protections.pdf Disconnection protections ensure that everyone has access to electricity by preventing shutoffs when customers do not pay their bills. - **Themes:** customer agency - **Safeguard:** Yes - **Impact time horizon:** short — Laws may specify that protections take effect immediately (common for emergency measures). If the law follows a standard effective date plus regulatory implementation, it may take a few months to a year before customers are protected. - **Potential cost savings:** n/a — Disconnection protections alone do not directly result in cost savings. See the [Arrearage Management policy page](https://affordability-toolkit.rmi.org/policies/arrearage-management-plans) for more information. - **Target cost drivers:** Aging grid infrastructure, Fuel price volatility, Extreme weather/wildfires, Load growth, Misaligned utility incentives ### Context and Background [Utility disconnection protections](https://eta-publications.lbl.gov/sites/default/files/feur_12_-_advancing_equity_in_utility_regulation.pdf) are policies that prevent electricity (or gas) shutoffs when customers do not pay their bills. These policies aim to protect public health and safety by ensuring that everyone has access to electricity for critical energy services like heating, cooling, cooking, and running medical equipment. Protections can also prevent housing displacement and foster trust between utilities and their customers. Protections generally apply to the most vulnerable customers and/or during periods of vulnerability (e.g., extreme heat or cold); disconnection protections [expanded in many places](https://pubs.naruc.org/pub/2B1596E2-1866-DAAC-99FB-37A81B4AFEF7) as a response to the financial hardship created by the COVID pandemic. The expansion of temporary disconnection protections during the COVID pandemic prompted increased interest in permanent protections, particularly for the most vulnerable households. ### Real-World Examples Most states offer some level of disconnection protections for nonpayment, typically applied on a temporary basis or under specific circumstances as described below. **Arkansas — Arkansas Implementation** Arkansas [protects vulnerable customers from shutoffs](https://apsc.arkansas.gov/consumer-services/suspension-of-service/#:~:text=Gas%20or%20electric%20service%20to,years%20or%20Older%20or%20Handicapped.) during periods of extreme heat or cold. For example, utilities cannot shut off power to customers aged 65 or older or customers with a disability if the National Weather Service forecasts a temperature of 95 degrees during the next 24 hours. The commission developed these rules under broad legislative authority and direction to protect vulnerable customers rather than as the result of a specific legislative directive. **Illinois — Illinois Implementation** Illinois [requires](https://www.law.cornell.edu/regulations/illinois/Ill-Admin-Code-tit-83-SS-280.130) utilities to provide adequate notice and reason for disconnection, requires they allow customers to remedy the problem to avoid disconnection, and sets limits on disconnection under certain circumstances. Limits apply to certain medically vulnerable customers, veterans, military personnel on active duty, periods of cold weather, and hot weather. Illinois established heat-based protections via [House Bill 1541](https://illinoisattorneygeneral.gov/news/story/attorney-general-raoul-announces-passing-of-utilities-bill?utm_source=chatgpt.com) and cold-based protections via a [2024 amendment to the Public Utilities Act](https://www.ilga.gov/legislation/ilcs/fulltext?DocName=022000050K8-205). The state also has performance incentive mechanisms that incentivize reduced disconnections. **Texas — Texas Implementation** Texas [provides restrictions](https://ftp.puc.texas.gov/public/puct-info/agency/rulesnlaws/subrules/electric/25.29/25.29.pdf) regarding the timing of disconnection (e.g., not during or on the day immediately preceding a holiday or weekend), disabled or medically vulnerable customers, and extreme weather. Many of Texas's protections are established by agency rules, but its cold-weather protections for gas shutoffs are codified [in statute](https://statutes.capitol.texas.gov/Docs/UT/htm/UT.104.HTM). **Virginia — Virginia Implementation** Virginia, via [House Bill 906](https://legacylis.virginia.gov/cgi-bin/legp604.exe?241+sum+HB906), provides disconnection protections to customers during periods of extreme heat or cold; on Fridays, weekends, holidays, or immediately before holidays; and during future outbreaks of communicable disease. The legislation also establishes guidelines for notices of nonpayment. ### Legislative Design Considerations Legislative approaches will differ state-to-state but can consider the following actions and parameters when establishing disconnection protections: **Eligibility criteria:** Defining which households qualify for protections based on income (e.g., percent of federal poverty level), participation in federal programs (e.g., Supplemental Nutrition Assistance Program (SNAP) or Low-Income Home Energy Assistance Program (LIHEAP)), or membership in a designated priority group (e.g., individuals with medical conditions, older adults, or households with young children) leads to programs that effectively support vulnerable populations. **Cause for disconnection:** Establish the reasons utility service may be disconnected, including specific types of nonpayment such as nonpayment of bills or a failure to meet the terms of deferred payment agreements. Setting standards on when disconnection is prohibited (e.g., a failure to pay disputed charges before the dispute has been resolved) leads to stronger consumer protections. **Notice and communication standards:** Establish a framework for advanced notice of disconnection. This could involve prohibiting disconnection on holidays or weekends, for example, to reduce risk of hardship. Legislation could require notices be published in advance and in multiple languages while including information on customer assistance and appeal rights. **Disconnection windows:** Setting restrictions on disconnections during discrete severe weather phenomena, crises like the COVID pandemic, cold or hot weather (e.g., days with high temperatures above 95 degrees Fahrenheit or below 32), or specific seasonal periods (e.g., November 1 through March 31) enhances customer safety. Legislation can also establish how long disconnection protection lasts, for example, by protecting a medically vulnerable customer from disconnection for 60 days after a nonpayment, and it can set a framework for extending the length of these protections. **Minimum delinquency period:** At least 42 states require a utility to give customers a critical window to resolve missed payments before facing disconnection, generally falling between 15 and 45 minimum days. **Minimum arrearage thresholds:** At least seven states protect customers from disconnection over small debts by specifying a minimum amount of customer debt before a utility can disconnect service, ranging from about $50 to $500. **Establishment of related policies:** Pairing disconnection protections with arrearage management programs or other similar policies, such as bill assistance, leads to more comprehensive solutions for addressing deferred payments and sustaining affordability. **Reporting requirements:** Require regular reporting of disconnections, restoration rates, arrearage size, and payment plan utilization by ZIP code and income bracket to track policy outcomes. **Establishment of regulatory authority:** Grant regulators specific authority to revise protections based on program performance and needs. ### Case Study **Colorado** Colorado provides some of the strongest [disconnection protections](https://www.sos.state.co.us/CCR/GenerateRulePdf.do?ruleVersionId=244&fileName=4%20CCR%20723-3) in the Mountain West, focused on low-income households and individuals with medical conditions. In 2020, [Senate Bill 20-030](https://leg.colorado.gov/bills/sb20-030) required the Colorado Public Utilities Commission to establish disconnection protections, and [House Bill 22-1018](https://leg.colorado.gov/bills/hb22-1018) expanded those protections two years later. The Commission now oversees a winter disconnection moratorium, medical exemption process, and coordination with energy assistance programs like LEAP (the Low-Income Energy Assistance Program). The protections are multifaceted but focus most strongly on energy security during the winter months. **Eligibility criteria:** The law provides restrictions on disconnection to protect health and safety, including for medically vulnerable customers. **Cause for disconnection:** The law stipulates reasons for which disconnection may or may not be implemented. **Notice and communication standards:** Colorado law requires written notice at least ten days in advance of disconnection in Spanish and English, including information about available state, federal, and local agencies with energy assistance programs, and informs the customer of their rights, including their rights to a dispute. **Disconnection windows:** The law provides temperature-based protections (32°F and below, 95°F and above). **Minimum delinquency period:** The disconnection date is 30 days after the disconnection notice. **Minimum arrearage thresholds:** Colorado law does not set a statewide minimum arrearage threshold. **Establishment of related policies:** The state establishes a structure and process for installment payment plans to manage arrearage. **Reporting requirements:** Utilities must track and report monthly statistics, including on the number of disconnections, reconnections, customers entering and defaulting on payment arrangements, and total dollar amount of arrears. **Key Takeaways:** Colorado’s policy combines protections with robust process and coordination with bill assistance and arrearage management programs to deliver a strong safety net for customers. ### Further Reading - [State Energy Justice Roundtable Series: Customer Affordability and Arrearages](https://pubs.naruc.org/pub/2B1596E2-1866-DAAC-99FB-37A81B4AFEF7) — National Association of Regulatory Utility Commissioners (2023) - [Advancing Equity in Utility Regulation](https://eta-publications.lbl.gov/sites/default/files/feur_12_-_advancing_equity_in_utility_regulation.pdf) — United States Department of Energy (2021) - [Protecting Access to Essential Utility Service During Extreme Heat and Climate Change](https://www.nclc.org/resources/protecting-access-to-essential-utility-service/) — National Consumer Law Center (2023) --- ## Green Municipal Bonds URL: https://affordability-toolkit.rmi.org/policies/green-municipal-bonds PDF: https://affordability-toolkit.rmi.org/pdfs/green-municipal-bonds.pdf Green municipal bonds are a financing tool that can be used by states to promote electricity affordability through financing energy upgrades or funding statewide programs for energy efficiency, customer assistance, and more. - **Themes:** cost control, cost distribution - **Safeguard:** No - **Impact time horizon:** short — Green municipal bonds can be issued and start financing projects within [1-2 years](https://www.energy.gov/sites/default/files/2020/11/f80/Leveraging-Bond-Financing_resource-summary_0.pdf) . - **Potential cost savings:** variable — While cost savings will vary from state to state, green municipal bonds can provide cost savings in two ways: lowering financing costs for energy upgrades and funding statewide programs currently paid for by ratepayers at a lower cost than the status quo. Savings are dependent on the type of green bond issued (General Obligation (GO) vs. revenue) and the projects funded by green bond issuances (energy efficiency upgrades, clean energy installations, etc.). - **Target cost drivers:** Load growth, Misaligned utility incentives ### Context and Background [Green municipal bonds](https://www.epa.gov/statelocalenergy/municipal-bonds-and-green-bonds) are a financing tool that can be used by states in two primary ways to improve electricity affordability.[^1] First, they can be used to provide low-cost financing for specific energy efficiency upgrades or renewable energy installations for residential and commercial customers. In this case, the government entity issuing the bonds leverages its high credit rating to offer low interest rate loans (often through an intermediary lending partner) to individual customers. These customers can receive longer-term, lower interest rate loans than they could receive from a private lender while the government entity uses the loan payments to cover repayment to bondholders (plus operating costs). Because of this relationship, customers can benefit from lower financing costs for energy upgrades and lower electricity costs due to the upgrade itself. Second, green bonds can be used to fund statewide energy efficiency, clean energy, customer assistance, and other programs currently funded by electricity ratepayers and subject to the utility's allowed return on equity. With this approach, the costs for operating these programs are shifted from the rate base to the tax base. All households benefit from [financing costs](https://rmi.org/rebalancing-return-on-equity-to-accelerate-an-affordable-clean-energy-future/) that are lower than the allowed return on equity for most utilities and funding these programs through taxes could be [more progressive](https://www.nber.org/system/files/working_papers/w26385/w26385.pdf) than through charges on electric bills. Due to their adaptability as a low-cost financing mechanism, green bonds have already been issued by many states in a variety of different contexts. [As of 2021](https://publicfinance.org/index.php/pfj/article/view/34/46), 39 states have issued at least one green bond series, but most issuances have gone towards non-energy-related projects like water and sewer upgrades or mass transit projects. Legislatures can direct a state agency to issue one or more series of green bonds for a specific purpose, grant broader authority to a state agency to issue green bonds for various programs, or create a green bank that can act independently to issue green bonds and finance energy projects. Ultimately, there is an opportunity to improve electricity affordability by using green bonds to fund valuable customer programs at the lowest cost possible and potentially fund programs using taxpayer dollars rather than ratepayer dollars. A variety of other financial tools, like securitization and bulk procurement, and reverse auctions, may also be deployed to lower costs for customers. Green bonds are highlighted here for their targeted potential and history of use. ^[1]: We refer to green municipal bonds as "green bonds" in this toolkit. Green municipal bonds must meet certain criteria to be formally labeled as "green bonds" in the market to mitigate the risk of greenwashing, however, a state can issue municipal bonds to be used for a "green" purpose like clean energy or energy efficiency upgrades without receiving the "green" designation. Such bonds should not be marketed as "green bonds" to avoid greenwashing. ### Real-World Examples As of 2021, green municipal bonds have been used in [39 states](https://publicfinance.org/index.php/pfj/article/view/34/46). **Vermont — Vermont Implementation** Vermont's [Municipal Bond Bank](https://www.vtbondbank.org/sites/default/files/2025-04/VBB_AnnualReport_2024%20_FINAL_small.pdf) has issued $2.8 billion in GO green bonds since 1970 to fund its [Pooled Loan Program,](https://www.vtbondbank.org/pooled-loan-program) which provides low-cost financing for infrastructure projects in municipalities and school districts, like energy efficiency upgrades and facilities renovations. The program is not limited to energy-related infrastructure. **Connecticut — Connecticut Implementation** Connecticut enacted [legislation](https://www.cga.ct.gov/2025/BA/PDF/2025SB-00004-R01-BA.PDF) (S.B. 4) in 2025 that allows the [Office of Policy and Management](https://www.cga.ct.gov/2025/amd/S/pdf/2025SB-00004-R00SA-AMD.pdf) to issue up to $300 million in GO bonds to pay for the state's hardship protection measures currently funded by charges on customer electric bills and the state's electric vehicle charging program. **Hawaii — Hawaii Implementation** Hawaii created the [Hawaii Green Infrastructure Authority (HGIA)](https://gems.hawaii.gov/about-us/) through [legislation in 2013](https://www.capitol.hawaii.gov/sessions/session2013/bills/SB1087_CD1_.htm) (S.B. 1087) to provide low-interest rate loans for residents seeking to install rooftop solar. The HGIA issued $150 million in [green revenue bonds](https://naseo.org/data/sites/1/naseo-gems-update-2015-08-04.pdf) to fund the loans, and the bonds are backed by loan repayments and a green infrastructure fee applied to all electric ratepayer bills. ### Legislative Design Considerations Legislation enabling the use of green municipal bonds to promote electricity affordability can include the following components: **Eligibility criteria:** Legislation can define the types of programs/projects which can be funded through green bond proceeds. [Some uses](https://www.energy.gov/sites/prod/files/2014/06/f16/Clean-Energy-Group-Reduce-Risk-Increase-Clean-Energy.pdf) include energy efficiency upgrades, renewable energy installations, or funding customer protection programs like arrearage forgiveness. **Bond and program design:** [Issuing](https://www.energy.gov/sites/default/files/2020/11/f80/Leveraging-Bond-Financing_resource-summary_0.pdf) general obligation (GO) bonds often requires voter approval because the bonds are backed by the state’s authority to issue taxes and are repaid through tax revenues or other state funds. Alternatively, states can issue revenue bonds, which are repaid through specific revenues like individual loan payments or energy savings performance contracts. The use of bond proceeds, a state’s tax code, and a state’s debt limit are key factors in determining which type of green bond to issue. **Establishment or empowerment of bonding authorities:** Empowering an existing state-chartered bond authority or establishing a new clean energy finance authority or green bank are two methods to issue green bonds. If a state is using revenue bonds to support loans for residential and commercial energy upgrades, the issuing authority needs to manage other financial transactions, like making loans or providing credit enhancement for loans offered by other financial institutions. **Debt limits:** Many states have [debt limits](https://www.urban.org/sites/default/files/publication/94906/debt-limits_7.pdf) that restrict the total amount of GO debt they can have, however, [revenue bonds](https://taxpolicycenter.org/briefing-book/what-are-municipal-bonds-and-how-are-they-used) are typically excluded from these limits. Issuing new GO debt could impede a state’s ability to fund other valuable projects and programs, so it is a key decision for policymakers. **Taxpayer implications (GO bonds):** Paying for programs through taxes can be more progressive than through charges on electric bills, however, states may have [regressive tax systems](https://itep.org/whopays-map-7th-edition/). Evaluating the net financial impact on households of shifting these costs from the rate base to the tax base can help states determine if issuing GO bonds will lead to an affordability improvement or if issuing revenue bonds may be a better approach. ### Case Study **New York** New York passed the [Green Jobs Green New York Act](https://www.nyserda.ny.gov/All-Programs/Green-Jobs-Green-New-York) in 2009 to provide residents with greater access to low-cost financing for energy efficiency upgrades and clean energy installations, and more pathways to green job opportunities. Green Jobs Green New York (GJGNY) is administered by the New York State Energy Research and Development Authority (NYSERDA). The largest [GJGNY program](https://www.nyserda.ny.gov/-/media/Project/Nyserda/Files/EDPPP/GJGNY/Annual-Report-GJGNY/2024-GJGNY-annual-report.pdf) is the Residential Revolving Loan Fund where NYSERDA provides loans for one- to four-family residential energy improvements like energy efficiency upgrades and solar installations. The fund was initially capitalized with a portion of New York’s Regional Greenhouse Gas Initiative (RGGI) proceeds and has since been replenished by ten issuances of green revenue bonds totaling over $280 million. To date, NYSERDA has issued over 43,000 residential loans amounting to $559 million for households to install energy efficiency upgrades, rooftop solar systems, heat pumps, and more. **Establishment or empowerment of bonding authorities:** The [GJGNY Act](https://www.nyserda.ny.gov/-/media/Project/Nyserda/Files/EDPPP/GJGNY/GJGNY-Legislation/GJGNY-Act-2009.pdf) directed NYSERDA to create a revolving loan fund consisting of two accounts to finance the cost of approved energy efficiency services: a residential and multifamily account and a non-residential account. **Bond and program design:** While the residential revolving loan fund was initially capitalized with RGGI funds, NYSERDA has since used its bonding authority granted in state statute to [issue ten series of green revenue bonds](https://www.nyserda.ny.gov/-/media/Project/Nyserda/Files/EDPPP/GJGNY/Annual-Report-GJGNY/2024-GJGNY-annual-report.pdf) to maintain the fund. However, NYSERDA often requires additional RGGI funds to pledge excess revenues to cover expected loan losses. The GJGNY Act directed NYSERDA to establish an on-bill recovery mechanism for repayment of residential loans (in addition to a traditional loan repayment method) as well as develop other underwriting criteria to expand access to loans for households that may not qualify using traditional lending criteria. **Eligibility criteria:** NYSERDA has developed several criteria for eligible projects and customers funded by the loans. Energy services eligible for loans must meet cost-effectiveness standards developed by NYSERDA, residential loans must be capped at $13,000 ([$25,000](https://assembly.state.ny.us/leg/?default_fld=&bn=A08510&term=2011&Summary=Y&Actions=Y&Text=Y&Votes=Y) for loans where the project payback period is less than 15 years), and loan interest rates should be no higher than necessary to make providing the energy upgrade feasible (the [average interest rate](https://www.nyserda.ny.gov/All-Programs/Green-Jobs-Green-New-York/Data-and-Trends) on residential loans is 3.82%). **Key Takeaways:** The GJGNY Act provided clear parameters to NYSERDA to develop a residential revolving loan fund, which NYSERDA has since funded through 10 series of green revenue bonds over 14 years and supplemental RGGI funding. Over this time period, NYSERDA has provided $559 million in low-cost loans to households to install energy upgrades and reduce electricity costs. NYSERDA’s green revenue bonds do not need voter approval, do not burden taxpayers, and do not count against New York’s debt limit. ### Further Reading - [Leveraging Bond Financing to Support Energy Efficiency and Renewable Energy Goals: A Resource Summary for State and Local Governments](https://www.energy.gov/sites/default/files/2020/11/f80/Leveraging-Bond-Financing_resource-summary_0.pdf) — U.S. Department of Energy (2020) - [Municipal Bonds and Green Bonds](https://www.epa.gov/statelocalenergy/municipal-bonds-and-green-bonds) — U.S. Environmental Protection Agency - [Reduce Risk, Increase Clean Energy: How States and Cities are Using Old Finance Tools to Scale Up a New Industry](https://www.energy.gov/sites/prod/files/2014/06/f16/Clean-Energy-Group-Reduce-Risk-Increase-Clean-Energy.pdf) — Clean Energy Group (2013) --- ## Low-Income Energy Efficiency URL: https://affordability-toolkit.rmi.org/policies/low-income-energy-efficiency PDF: https://affordability-toolkit.rmi.org/pdfs/low-income-energy-efficiency.pdf Low-income energy efficiency programs help households reduce energy consumption and utility costs by supporting measures like air sealing, insulation, and equipment upgrades. - **Themes:** cost control, customer agency - **Safeguard:** Yes - **Impact time horizon:** short — Designing, approving, and launching a low-income energy efficiency program often takes a year or two. - **Potential cost savings:** medium — Program impacts vary greatly depending on design. For example, programs providing deep retrofits can achieve high cost savings while those offering lighter efficiency measures may deliver lower savings. Comprehensive energy efficiency measures can [reduce household energy bills by 50%](https://homes.lbl.gov/home-retrofits) or more, but finite program funding can limit the reach of deep energy efficiency upgrades to a relatively small percentage of eligible households. - **Target cost drivers:** Aging grid infrastructure, Fuel price volatility, Extreme weather/wildfires, Load growth, Misaligned utility incentives ### Context and Background Energy efficiency programs for low-income households reduce energy consumption and utility costs by supporting measures like air sealing, insulation, and equipment upgrades to increase energy affordability and provide additional benefits, such as improved health and home comfort. [Many low-income households](https://www.aceee.org/press-release/2024/09/study-one-four-low-income-households-spend-over-15-income-energy-bills?utm) live in older, less energy-efficient homes, disproportionately experiencing issues like drafts, inefficient heating and cooling systems, and poor insulation — making these targeted support programs especially important. Energy efficiency programs typically take two forms: deep energy retrofits that deliver large bill savings to a small number of customers or lighter improvements that provide more modest benefits to a broader population. Funding and financing can also take many forms, including upfront rebates, on-bill financing, grants, and low-interest loans; it is important to design incentives to ensure that low-income households can access them, ideally by reducing or eliminating out-of-pocket costs. ### Real-World Examples Most states offer some form of low-income energy efficiency support, such as weatherization, incentives for more efficient appliances, and/or improved controls. **California — California Implementation** California's Low-Income Weatherization Program provides no-cost energy efficiency retrofits, solar photovoltaic systems, and health and safety upgrades to [low-income households](https://www.csd.ca.gov/Shared%20Documents/LIWP-2022-Multi-Family-2.0-Final-Program-Guidelines.pdf) with specific focuses on disadvantaged communities, farmworker housing, transitional housing, and homeless shelters. Funding is appropriated through the state's cap-and-trade program with an average of approximately [$35 million](https://www.csd.ca.gov/Shared%20Documents/LIWP-Fact-Sheet.pdf) annually from fiscal years 2014/25 through 2022/23. Multiple pieces of legislation provide the foundation for this program, including, for example, [Senate Bill 535](https://legiscan.com/CA/text/SB535/id/179871), which links cap-and-trade funds to disadvantaged communities. **Colorado — Colorado Implementation** Colorado enacted [Article 8.7](https://law.justia.com/codes/colorado/2021/title-40/article-8-7/section-40-8-7-103/) in its utility statutes in 2005, which formally established the Colorado Affordable Residential Energy (CARE) Program. CARE provides no-cost energy efficiency upgrades and energy audits to customers of participating utilities, living in a participating county, with household income that meets program limits, or with a household member who participates in aid programs (e.g., Supplemental Nutrition Assistance Program (SNAP), Section 8). It is funded by [Energy Outreach Colorado](https://garfieldcleanenergy.org/income-qualified/care-colorado-affordable-residential-energy-program/), a nonprofit. **Massachusetts — Massachusetts Implementation** Massachusetts's [Mass Save](https://www.masssave.com/residential/programs-and-services/income-based-offers/income-eligible-programs) program delivers a suite of energy efficiency services, including no-cost weatherization, equipment upgrades, and health and safety improvements for low-income households. The program is administered by a group of the state's utilities and energy efficiency service providers with oversight from the state's Department of Public Utilities and advisory input from the Energy Efficiency Advisory Council. Funding comes from a dedicated energy efficiency surcharge on both gas and electric bills. The [Green Communities Act of 2008](https://malegislature.gov/Laws/SessionLaws/Acts/2008/Chapter169) [spurred the creation of Mass Save](https://www.aceee.org/files/proceedings/2012/data/papers/0193-000169.pdf). ### Legislative Design Considerations Legislative approaches to low-income energy efficiency will differ state-to-state but can consider the following actions and parameters: **Incentive structure:** Establish the form of the program. Comprehensive low-income programs are often grant-funded, but low-income energy efficiency programs may take a variety of forms. - **Direct installation programs** fund the installation of measures directly in homes, such as smart thermostats, lighting upgrades, and high-efficiency appliances. - **Upfront rebates** provide discounts on appliances or equipment at point-of-sale. - **On-bill financing or repayment** spread upgrade costs over time through utility bills, ideally in such a way that monthly cost savings are greater than monthly charges. - **Grants and loans** fund efficiency improvements without high-interest debt. **Eligibility criteria:** Define which households will qualify for protections based on income, participation in federal programs, or other characteristics to reach the intended populations. This may also depend on administration and implementation (e.g., eligibility may depend on being a customer of a participating utility if utilities administer the program). **Source of funding:** Provide clear, dedicated funding through a mix of federal, state, utility, nonprofit, and/or other sources. Funding stability could be ensured by, for example, requiring utilities to spend a certain percentage of their budgets on the program. **Administration:** Clarify the role of regulators, utilities, nonprofits, or others in program planning, administration, and implementation. **Scope of services:** Establish a framework for which services will be funded or provided. Consider enabling or directing program administrators to include health and safety upgrades, in addition to energy-related retrofits, or coordinate with entities that provide those related services to ensure the program does not turn away families in homes with health and safety issues. This approach builds more inclusive, fair, and comprehensive home upgrade programs. **Reporting requirements:** Require regular reporting of program impacts (e.g., households served by income bracket) to build transparency and enable ongoing assessments of program effectiveness. **Establishment of related policies:** Specify a minimum low-income sector spending or savings target or requirement to help ensure that low-income customers are benefiting from energy efficiency programs in general. Pennsylvania, for example, has adopted a requirement that utilities achieve savings of at least [5.8% of their portfolio](https://neep.org/sites/default/files/media-files/2024_regionalroundup_pa_final.pdf) from programs directed at low-income customers. ### Case Study **Nevada** [Nevada’s Home Energy Retrofit Opportunities for Seniors (HEROS) program](https://www.energy.nv.gov/siteassets/content/programs/HEROS_Fact_Sheet_February_2020_DRAFT.pdf) improves energy affordability and home comfort for seniors via no-cost home retrofits and technical assistance for eligible, low-income households with residents aged 60 and older. [Assembly Bill 466](https://www.leg.state.nv.us/App/NELIS/REL/78th2015/Bill/2192/Text) in the state’s 2015 legislative session provided the legal framework for the state to allocate funding to programs like HEROS. **Eligibility criteria:** To qualify, households must have at least one resident aged 60 and older, have an income at or below 200% of federal poverty guidelines, and be owner-occupied. **Source of funding:** Funding comes from the [Renewable Energy Account](https://www.leg.state.nv.us/nrs/nrs-701a.html#NRS701ASec450) in the State General Fund. **Administration:** The Governor’s Office of Energy created the program and provides funding to the Nevada Housing Division, which works with nonprofit service providers that implement the upgrades. **Scope of services:** Upgrades are no-cost and include insulation, air sealing and ductwork repair, appliance and lighting upgrades, and heating, ventilation, and air conditioning (HVAC) system repair or replacement. **Reporting requirements:** Reporting requirements were not legislatively mandated but were established administratively. **Key Takeaways:** Energy upgrades from HEROS reduce household energy use by an average of 64% and can create healthier and more comfortable living environments, reducing issues like asthma and carbon monoxide risks. By delivering tangible energy efficiency benefits to vulnerable households, the program addresses an issue at the intersection of energy affordability, aging in place, and housing quality. ### Further Reading - [We Can End Energy Poverty in the Electric Sector: Here's How](https://rmi.org/we-can-end-energy-poverty-in-the-electric-sector-heres-how/) — RMI (2025) - [Funding Our Future: Creating a One-Stop Shop for Whole-Home Retrofits](https://rmi.org/creating-a-one-stop-shop-for-whole-home-retrofits/) — RMI (2022) - [Supporting Low-Income Energy Efficiency: A Guide for Utility Regulators](https://www.aceee.org/toolkit/2021/04/supporting-low-income-energy-efficiency-guide-utility-regulators) — American Council for an Energy-Efficient Economy (2021) - [The Energy Poverty Policy Simulator](https://utilitytransitionhub.rmi.org/energy-poverty-policy-simulator/) — RMI (2024) --- ## All-Source Procurement URL: https://affordability-toolkit.rmi.org/policies/all-source-procurement PDF: https://affordability-toolkit.rmi.org/pdfs/all-source-procurement.pdf All-source procurement is a framework that requires utilities to solicit and evaluate bids from a full range of supply and demand-side resources in a competitive, technology-neutral process to prioritize cost-effectiveness and reliability. - **Themes:** cost control - **Safeguard:** No - **Impact time horizon:** medium — Impacts are realized as utilities update resource plans and conduct new procurement cycles. - **Potential cost savings:** medium — While cost savings will vary based on policy design and implementation, competitive procurement can lead to billions of dollars in savings and lower overall system costs by avoiding overbuilt infrastructure and leveraging lower-cost energy resources. For example, [Northern Indiana Public Service Company used an all-source solicitation for its 2018 IRP](https://energyinnovation.org/wp-content/uploads/2020/04/All-Source-Utility-Electricity-Generation-Procurement-Best-Practices.pdf) and was able to reduce forecast costs by $1.1 billion (approximately 10%) relative to its 2016 IRP scenario by retiring additional coal-fired generation and leveraging clean energy. - **Target cost drivers:** Load growth, Fuel price volatility, Aging grid infrastructure, Misaligned utility incentives ### Context and Background All-source procurement is a [framework](https://energyinnovation.org/wp-content/uploads/2020/04/All-Source-Utility-Electricity-Generation-Procurement-Best-Practices.pdf) that requires utilities to consider a full range of supply, and ideally, demand-side resources — energy efficiency, demand response, energy storage, and all types of generation — when planning new investments or meeting future energy needs. Rather than defaulting to a specific technology or ownership structure, all-source procurement can be a competitive, technology-neutral process that maximizes cost-effectiveness and reliability. This approach [helps reduce costs and improve grid flexibility](https://rmi.org/grading-your-utilitys-shopping-habits/). While utilities have implemented all-source procurement without a requirement in some cases, as of 2025, several states, including Colorado, Michigan, and Oregon, have implemented requirements for utilities to use all-source procurement through legislation or regulation. Utility planning, such as integrated resource plans (IRPs), typically identifies a specific portfolio of technologies that can cost-effectively meet demand. Procurement actions work to implement these plans. All-source solicitation, where utilities define their system needs and invite competitive bids, can work synergistically with IRPs: procurement processes provide real-time validation of key planning assumptions such as resource costs, and updated IRPs can better tailor all-source procurements to meet system needs. This approach promotes affordability by maximizing competition, ensuring up-to-date pricing, and exposing risks like fuel price volatility through actual bid responses rather than relying solely on historical or projected data. ### Real-World Examples As of 2025, [at least eight states](https://www.rstreet.org/research/state-by-state-scorecard-on-electricity-competition/) have some degree of competitive electricity procurement. **Colorado — Colorado Implementation** Colorado's Public Utility Commission (PUC) [requires investor-owned utilities to conduct all-source solicitations](https://www.sos.state.co.us/CCR/GenerateRulePdf.do?ruleVersionId=11998&fileName=4%20CCR%20723-3) as part of their electric resource planning process. In 2017, Xcel Energy's Colorado subsidiary, the Public Service Company of Colorado, [completed an all-source supply-side procurement](http://www.dora.state.co.us/pls/efi/EFI.Show_Filing?p_fil=G_728992&p_session_id=) as part of this requirement, which it [claimed would save customers over $200 million](https://rmi.org/saving-colorado-customers-money-with-clean-energy/) when compared to Xcel's original planning phase portfolio, in part through retiring coal plants. Colorado's [state code of regulations](https://www.law.cornell.edu/regulations/colorado/department-700/division-723/4-CCR-723-3/electric-resource-planning) requires electric utilities subject to PUC authority to submit comprehensive resource plans. **Washington — Washington Implementation** Washington's Utilities and Transportation Commission (UTC) [issued a rule](https://lawfilesext.leg.wa.gov/law/wsr/2021/03/21-02-023.htm) in December 2020 to establish an [all-source procurement requirement](https://app.leg.wa.gov/WAC/default.aspx?cite=480-107-009&pdf=true). The move was [part of an effort by the UTC](https://app.leg.wa.gov/wac/registerfiling.aspx?cite=480-107-001) to act on new statutory requirements established by state bills, including the 2019 Clean Energy Transformation Act. **Georgia — Georgia Implementation** Georgia's [state rules and regulations](https://rules.sos.state.ga.us/gac/515-3-4) require all electricity supplies whose rates are fixed by the state's Public Service Commission (PSC) to develop IRPs for PSC review and approval. Building on that requirement, the PSC required Georgia Power Company to conduct an all-source solicitation as part of its [2022 Integrated Resource Plan (IRP) Final Order](https://psc.ga.gov/search/facts-document/?documentId=191010). ### Legislative Design Considerations To enable and unlock the full benefits of all-source procurement, legislation can include the following: **Mechanism components:** Require utilities to use competitive, all-source solicitations that are directly informed by integrated resource planning outcomes. This ensures that procurement decisions reflect long-term system needs and stakeholder priorities. Requirements that utilities issue solicitations based on grid services (e.g., capacity, flexibility, resilience), rather than specific technologies, will also allow diverse solutions, including distributed energy resources, to compete. **Reporting and transparency:** Requiring independent evaluators or regulatory oversight to assess bids will help ensure that utility-owned proposals are evaluated on an equal footing with third-party offers. **Coordination with other programs:** Directing regulators to consider broader public interest goals, such as resilience, when approving procurement plans and evaluating bids will help align those plans with state targets. **Policy structure:** Require utilities to account for the long-term risks of fuel price volatility when comparing resource options, helping to level the playing field across different types of generation resources. **Regulatory enforcement:** In addition to ensuring the state has rules encouraging all-source procurement, ensuring the state has a commission that can support those rules is important for effective monitoring of procurement processes. ### Further Reading - [How to Build Clean Energy Portfolios,](https://connectedcommunities.lbl.gov/sites/default/files/2021-09/RMI%20How%20to%20Build%20Clean%20Energy%20Portfolios.pdf) — RMI (2021) - [All-Source Competitive Solicitations: State and Electric Utility Practices,](https://emp.lbl.gov/publications/all-source-competitive-solicitations) — Berkeley Lab (2021) - [Making The Most Of The Power Plant Market: Best Practices For All-Source Procurement Of Electric Generation,](https://energyinnovation.org/report/making-the-most-of-the-power-plant-market-best-practices-for-all-source-procurement-of-electric-generation/) — Energy Innovation (2020) - [Experience with Competitive Procurements and Centralized Resource Planning to Advance Clean Electricity,](https://www.rff.org/publications/working-papers/experience-with-competitive-procurements-and-centralized-resource-planning-to-advance-clean-electricity/) — Resources for the Future (2021) - [The Benefits of an All-Source RFP in Duke Energy Indiana\'s 2021 Integrated Resource Planning Process,](https://www.synapse-energy.com/benefits-all-source-rfp-duke-energy-indianas-2021-integrated-resource-planning-process) — Synapse Energy Economics (2020) --- ## Arrearage Management Plans URL: https://affordability-toolkit.rmi.org/policies/arrearage-management-plans PDF: https://affordability-toolkit.rmi.org/pdfs/arrearage-management-plans.pdf Arrearage management plans help low-income utility customers systematically reduce and ultimately eliminate utility debt. - **Themes:** customer agency - **Safeguard:** Yes - **Impact time horizon:** short — Once arrearage management plans come into place, customers can typically begin accessing them right away. - **Potential cost savings:** n/a — AMPs result in debt forgiveness rather than a reduction in bills. The level of cost savings depends on the customer's outstanding balance and AMP design, but arrearage management programs can save a customer hundreds to thousands of dollars in debt over the course of a year. - **Target cost drivers:** Aging grid infrastructure, Fuel price volatility, Extreme weather/wildfires, Load growth, Misaligned utility incentives ### Context and Background Arrearage management plans (AMPs) support long-term energy affordability by helping low-income utility customers systematically reduce and ultimately eliminate utility debt. AMPs generally forgive a portion of a customer's outstanding debt for each on-time payment of a new bill. Often, this works by eliminating one-twelfth of the initial debt each month until the full debt is gone after one year. Such programs enable participants to chip away at arrears over time and stay current on their utility payments, often leading to improved payment habits once the program ends. AMPs are especially important for households facing high energy burdens who may accumulate large arrears over time. They are often seen as a win-win-win for customers in arrears, the broader customer base, and the utility because lowering arrearages also lowers uncollectible costs that would otherwise fall on all customers. ### Real-World Examples At least ten states have arrearage management plans in place, not all of which have been established through legislation. **Maine — Maine Implementation** Maine requires utilities to create and implement their own AMPs via [An Act To Assist Electric Utility Ratepayers](https://www.mainelegislature.org/legis/bills/display_ps.asp?paper=SP0731&PID=undefined&snum=126), enacted in 2014. Each time an AMP participant pays their current amount due on time, [one twelfth of their initial arrearage amount is forgiven](https://www.maine.gov/sos/sites/maine.gov.sos/files/inline-files/407c317-2024-008%20%28AMD%29.docx), up to $500 per month. Utilities recover costs through rates. Eligible customers include those who meet eligibility criteria for state assistance programs HEAP and LIAP (Home Energy Assistance Program and Low-Income Assistance Program) and have arrearage of at least $500 with a portion at least 90 days in arrears, and the program has some restrictions on participation for those who have previously participated in an AMP. **Massachusetts — Massachusetts Implementation** Massachusetts enacted [statutory requirements](https://malegislature.gov/Laws/SessionLaws/Acts/2005/Chapter140) in 2005 for utilities to develop and implement AMPs. A portion of the customer's past-due balance is forgiven each month, with the specifics varying by utility (e.g., up to $1,000 per month for National Grid). Utilities recover costs through rates, subject to approval by the utility commission. Eligibility extends to customers with an arrearage of at least $300 that is at least 60 days overdue and who are enrolled in the utility's low-income discount rate, which typically requires eligibility for federal assistance programs. ### Legislative Design Considerations Legislation can establish the following program parameters, which may differ state-to-state: **Program timeline:** Specify how long it takes for the entire arrearage to be forgiven. Many programs forgive one twelfth of the arrearage each month when the customer makes an on-time payment of their current month’s bill; under this system, the entire arrearage is forgiven after a year. **Eligibility criteria:** Define which households will qualify for an AMP based on extent of arrears, income level, or participation in assistance programs to support the customers most at risk of disconnection. **Notice and communication standards:** Establish standards for providing notice to eligible customers to support awareness and program participation. **Enrollment process:** Provide the basic framework for AMP enrollment. **Administration:** Clarify the role of utilities and regulators in program design and administration. **Source of funding:** Specify cost recovery mechanisms to help ensure predictable program financing. **Reporting requirements:** Require regular reporting of program impacts (e.g., households participating, defaults, amount of arrearage forgiven) to build transparency and enable evaluation of program effectiveness. **Establishment of related policies:** Establish or coordinate AMPs with other initiatives to lead to stronger consumer protections and longer-term improvements in affordability. These initiatives can include disconnection protections to ensure customers making regular payments in AMPs cannot be disconnected, mechanisms to ensure bill affordability (discount rates or percentage-of-income payment plans), or energy efficiency programs or requirements that AMP participants accept no-cost energy efficiency audits or tools. ### Further Reading - [Helping Low-Income Utility Customers Manage Overdue Bills through Arrearage Management Programs (AMP)](https://www.nclc.org/wp-content/uploads/2022/09/amp_report_final_sept13.pdf) — National Consumer Law Center (2013) - [We Can End Energy Poverty in the Electric Sector: Here's How](https://rmi.org/we-can-end-energy-poverty-in-the-electric-sector-heres-how/) — RMI (2025) - [The Energy Poverty Policy Simulator](https://utilitytransitionhub.rmi.org/energy-poverty-policy-simulator/) — RMI (2024) --- ## Capex-Opex Equalization URL: https://affordability-toolkit.rmi.org/policies/capex-opex-equalization PDF: https://affordability-toolkit.rmi.org/pdfs/capex-opex-equalization.pdf Capex-opex equalization strategies aim to balance the financial incentives between capital expenditures (capex) and operating expenditures (opex) to incentivize cost-effective solutions. - **Themes:** cost control - **Safeguard:** No - **Impact time horizon:** medium — Capex-opex equalization mechanisms are not expected to deliver results immediately but rather require regulatory reform or rule changes and often take time to integrate into utility planning and operations. This policy can be expected to show real impacts within a 2–5-year window after implementation starts. - **Potential cost savings:** medium — Consolidated Edison's [Brooklyn-Queens Demand Management](https://www.aceee.org/sites/default/files/publications/researchreports/u1809.pdf) program, approved in 2014 by the state's commission, demonstrated how incentives can enable utilities to use demand management, efficiency, and distributed generation in place of $1.2 billion of traditional grid upgrades to meet increasing peak demand. With only $75 million in spending, Consolidated Edison achieved most of the targeted peak reduction and deferred major infrastructure investments. Overall, cost savings will depend on the specific equalization mechanisms in place and the way they are designed. - **Target cost drivers:** Load growth, Misaligned utility incentives, Extreme weather/wildfires ### Context and Background Capex-opex equalization refers to a set of strategies that aim to balance the financial incentives between capital expenditures (capex) and operating expenditures (opex). Since utilities traditionally earn a return on capex but not opex, they typically favor capex solutions, like constructing new power generation, even when opex solutions may cost less or provide more benefits to customers and the grid (e.g., grid-enhancing technologies, non-wires alternatives, energy efficiency, or demand flexibility). There is a range of equalization strategies that aim to correct this imbalance; on the narrow end of the spectrum, they can allow utilities to treat certain opex categories like capex with an allowed return, and on the broad end of the spectrum, they remove the distinction between capex and opex completely. The ideal end result is to neutralize the utility preferences for capex solutions where more cost-effective opex solutions exist. ### Real-World Examples Many states currently have explicit capex-opex equalization mechanisms in place. **California — California Implementation** California incorporates capex-opex equalization through rules and mechanisms approved by its utility commission and authorized via laws like [Assembly Bill 32 (the Global Warming Solutions Act)](https://ww2.arb.ca.gov/resources/fact-sheets/ab-32-global-warming-solutions-act-2006) and [Senate Bill 350 (The Clean Energy and Pollution Reduction Act)](https://www.energy.ca.gov/rules-and-regulations/energy-suppliers-reporting/clean-energy-and-pollution-reduction-act-sb-350) that broadly support these types of utility innovation strategies. Utilities are allowed to capitalize certain operational costs, such as those that enable distributed energy generation or grid modernization. **Minnesota — Minnesota Implementation** Minnesota has implemented capex-opex equalization through programs that allow cost recovery for certain investments related to distributed generation. Broad authority is available via a number of statutes related to energy efficiency and cost recovery. **Massachusetts — Massachusetts Implementation** Massachusetts established the [Green Communities Act](https://malegislature.gov/Laws/SessionLaws/Acts/2008/Chapter169), which mandates strong energy efficiency targets and allows utilities to amortize and earn a rate of return on energy efficiency expenditures. **New York — New York Implementation** New York enabled capex-opex equalization through the state's [Reforming the Energy Vision (REV)](https://www.ny.gov/sites/default/files/atoms/files/WhitePaperREVMarch2016.pdf) framework, which came about via a regulatory proceeding aimed at realigning utility incentives. The framework allows utilities to amortize and earn a return on specific types of operating expenses, such as energy efficiency and demand-side management programs. **Oregon — Oregon Implementation** Oregon has approved non-wires alternatives programs in which utilities can recover costs associated with investments in demand-side and distributed energy solutions, and regulators have approved financing mechanisms in select dockets that place these expenses on more equal footing with capital expenses. No single statute explicitly encourages equalization mechanisms, broad authority is available via laws like [House Bill 2021](https://olis.oregonlegislature.gov/liz/2021R1/Measures/Overview/HB2021), which mandates decarbonization and encourages non-wires alternatives. ### Legislative Design Considerations Legislation for capex-opex equalization can do the following. Approaches may differ state by state: **Equalization methods:** Authorize or encourage the regulator to explore or implement one or more methods for placing capex and opex on equal footing. Methods can be narrow or broad in scope and tailored to the utility's context and policy goals. Methods could include, for example: - **Opex capitalization** allows utilities to earn a rate of return on specific types of operating expenses, most commonly energy efficiency or demand-side management programs. - **Efficiency carryover mechanisms** enable utilities to retain cost savings from reduced expenditures during any year of a multi-year rate plan, incentivizing them to undertake opex solutions by providing future revenue opportunities. - **Performance incentive mechanisms** (PIMs) are tools that offer utilities financial incentives relative to specific outcomes. They generally include a performance metric tied to the outcome and one or more targets or benchmarks that trigger rewards if met or penalties if unmet. For example, a PIM to increase utilization of distributed energy resources can be considered a form of capex-opex equalization. - **Shared savings mechanisms** (SSMs) are a form of PIM designed to align utility behavior with policy objectives by offering a proportion of savings or net benefits created by certain utility actions to the utility as earnings. SSMs have been applied across a range of utility investments, including demand response, non-wires alternatives, and energy efficiency programs. - **Modified clawback mechanisms** are a type of PIM that adjust or reclaim utility earnings when actual outcomes differ significantly from projections used to justify an investment. These mechanisms are designed to protect customers from overpayment and maintain utility accountability. - **Totex ratemaking** merges capex and opex into a single "total expenditures" pool and applies a consistent capitalization rate so utilities earn on both capex and opex equally. **Establishment of related policies:** Implement capex-opex equalization alongside policies that create a cost-efficiency incentive. Capex-opex equalization is most effective when part of a broader policy framework that aligns utility incentives with cost-efficiency. While capex-opex equalization strategies can place opex solutions on an equal footing with capex solutions, on their own, they do not incentivize cost-efficiency. It is therefore important to implement capex-opex equalization alongside mechanisms that create an incentive for cost-efficiency.[^1] ^[1]: As an illustrative example: a utility can earn 7% on either an opex solution or a capex solution, and the opex solution is $10 (yielding $0.70 in earnings) while the capex solution is $100 (yielding $7). Even though both offer the same rate of return, the utility would still prefer the capital solution. To actually drive reduced spending, additional incentives are needed to make the opex option attractive. **Coordination with other programs:** Encouraging alignment between equalization mechanisms and broader goals, such as clean electricity standards or building energy efficiency initiatives, creates a more coherent and effective policy approach. **Eligible costs:** Empower the commission to define the categories of opex that can be treated like capital, such as demand-response programs, energy efficiency investments, a distributed energy resource management system, grid-enhancing technologies, non-wires alternatives, or battery storage deployment. Rather than selecting specific technologies, legislation may allow for flexibility in program design and instead set criteria for eligible operating costs based on, for example, customer benefits. **Regulatory enforcement:** Granting regulators explicit authority to oversee implementation and assess performance outcomes enables accountability and ensures utilities adhere to the requirements established. **Reporting and transparency:** Requiring utilities to submit filings that, for example, track outcomes and describe how equalized costs are calculated and allocated to customers increases transparency and oversight of program impacts. ### Further Reading - [A Strategic Framework for Utility Cost Control](https://rmi.org/wp-content/uploads/dlm_uploads/2025/02/Strategic_Framework_Cost_Controls_report.pdf) — RMI (2025) - [Making the Clean Energy Transition Affordable: How Totex Ratemaking Could Address Utility Capex Bias in the United States](https://rmi.org/insight/making-the-clean-energy-transition-affordable/) — RMI (2022) - [Improving the PBR Framework in Hawaii: Addressing the Risk of Capex Bias](https://www.brattle.com/insights-events/publications/improving-the-pbr-framework-in-hawaii-addressing-the-risk-of-capex-bias/) — Brattle Group (2019) --- ## Careful Management Of Cost Trackers URL: https://affordability-toolkit.rmi.org/policies/careful-management-of-cost-trackers PDF: https://affordability-toolkit.rmi.org/pdfs/careful-management-of-cost-trackers.pdf Careful management of the use of cost trackers can promote affordability by increasing scrutiny on utility costs and strengthening incentives for utilities to control costs. - **Themes:** cost control - **Safeguard:** No - **Impact time horizon:** medium — Cost trackers are [usually adopted](https://rmi.org/insight/a-strategic-framework-for-utility-cost-control/) in rate cases or other proceedings. Rate cases generally take [12-18 months to complete](https://www.utilitydive.com/news/accelerating-utility-rate-case-filings-generative-ai-artificial-intelligence-genai/730551/). Once adopted, costs covered by cost trackers are "trued-up" at regular intervals and can remain in place for an undetermined period of time. The savings that might result from carefully considering the use of cost trackers occur in the medium- to long-term. - **Potential cost savings:** variable — The potential cost savings from careful management of cost trackers is variable and depends on the existing use of cost trackers by public utility commissions in different states. For example, [Dominion Energy](https://www.scc.virginia.gov/media/sccvirginiagov-home/regulated-industries/utility-regulation/energy-regulation/2024-veur.pdf) in Virginia estimates that $39.3 billion (62%) of its $63.4 billion net rate base will be recovered by cost trackers by 2029. While it's possible that some costs could be rejected by replacing cost trackers with a more thorough review process, it's not clear how much costs could be saved by avoiding cost trackers. - **Target cost drivers:** Aging grid infrastructure, Fuel price volatility, Misaligned utility incentives ### Context and Background A [cost tracker](https://rmi.org/wp-content/uploads/dlm_uploads/2024/07/PBR_Deck_final.pdf) is a regulatory mechanism to provide cost recovery for specific costs outside of general rate case proceedings. Cost trackers are [intended](https://pubs.naruc.org/pub/FA86C519-AF31-D926-BE12-2AC7AE0CD8D6) for costs deemed to be volatile, outside of the utility's control, and present a substantial financial risk to the utility if not recovered. While cost trackers can provide timely cost recovery for utilities, they can weaken the incentive for utilities to control costs because tracked costs typically receive less scrutiny by regulators compared to general rate cases. Furthermore, in some instances, cost trackers are structured to provide guaranteed cost recovery. The use of cost trackers has expanded in recent years, but legislatures and regulators may wish to carefully consider their use to ensure these mechanisms are not serving as vehicles for unfettered utility spending. ### Real-World Examples As of 2022, all 50 states had cost trackers in place. The most common cost tracker is a fuel-adjustment clause (81% of the largest electric and gas utilities have fuel-adjustment clauses). **Virginia** The Virginia legislature passed a [joint resolution](https://legacylis.virginia.gov/cgi-bin/legp604.exe?241+sum+HJ30) in 2024 (H.J. 30) requiring the State Corporation Commission (SCC) and Virginia Department of Energy to conduct a stakeholder-informed study on the use of performance-based regulation (PBR). [Stakeholders](https://energy.virginia.gov/public/documents/Stakeholders/FINAL_Report_PBR%20Stakeholder_Split.pdf) ultimately recommended a comparative analysis of the costs and benefits of recovering costs through rate-adjustment clauses (cost trackers), which are heavily used in Virginia, relative to base rates, performance-based tools, or hybrid mechanisms. **Kentucky** The Kentucky Legislative Research Commission completed a [study](https://legislature.ky.gov/LRC/Publications/Research%20Memoranda/RM531.PDF) to analyze the costs and benefits of implementing alternative rate mechanisms, including cost trackers, for public utilities regulated by the Kentucky Public Service Commission. While the report did not make any explicit recommendations, it did include an assessment of the benefits and limitations of cost trackers. Notably, the report highlighted that cost trackers weaken utility cost control incentives and are often not offset by reductions in a utility’s ROE, despite less financial risk facing a utility due to the certainty of cost recovery. ### Legislative Design Considerations Legislation about the prudent use of cost trackers could include the following principles: **Criteria for cost tracker eligibility:** Directing regulators to [adopt a set of criteria](https://rmi.org/insight/a-strategic-framework-for-utility-cost-control/) that must be met in order to use cost trackers can guard against excessive use. [Criteria could include](https://pubs.naruc.org/pub/FA86C519-AF31-D926-BE12-2AC7AE0CD8D6) requiring utilities to prove that costs are outside the utility's control, unpredictable, and volatile, and would materially impact the utility's financial health if not recovered via a tracker. Additionally, legislation can include provisions that clarify the authority of the public utility commission (PUC) to deny the approval of a cost tracker, deny recovery of certain tracked costs, and eliminate cost trackers that it deems no longer necessary. **Complementary cost control incentives:** Because cost trackers weaken a utility's incentive to control costs, legislation can provide a requirement and/or clear authority for regulators to [create complementary incentives](https://rmi.org/insight/a-strategic-framework-for-utility-cost-control/) for utilities to control any costs recovered via a cost tracker. One example of such an incentive is a shared savings mechanism, which rewards the utility with a share of the cost savings resulting from a particular action. **Reduction of utility return on equity (ROE):** Cost trackers provide more certainty of cost recovery for utilities, so it may be appropriate to reduce a utility's allowed ROE in accordance with this reduction in financial risk. Directing regulators to consider the impact of cost trackers on a utility's financial risk and allowing for [reductions in utility ROEs](https://rmi.org/insight/a-strategic-framework-for-utility-cost-control/) where reliance on cost trackers significantly reduces utility business risk can guard against unnecessary costs for customers. ### Further Reading - [A Smarter Approach to Cost Trackers to Support Affordability](https://rmi.org/insight/cost-trackers-to-support-affordability/) — RMI (2026) - [A Strategic Framework for Utility Cost Control](https://rmi.org/insight/a-strategic-framework-for-utility-cost-control/) — RMI (2025) - [Alternative Rate Mechanisms and Their Compatibility with State Utility Commission Objectives](https://pubs.naruc.org/pub/FA86C519-AF31-D926-BE12-2AC7AE0CD8D6) — National Regulatory Research Institute (2014) --- ## Community Solar Programs URL: https://affordability-toolkit.rmi.org/policies/community-solar-programs PDF: https://affordability-toolkit.rmi.org/pdfs/community-solar-programs.pdf Community solar programs allow customers to benefit from the cost savings of solar energy without needing to install solar systems on their homes, giving customers more control over their electricity bills. - **Themes:** customer agency - **Safeguard:** No - **Impact time horizon:** medium — It can take [2-5 years](https://joinsolar.org/what-is-the-process-for-setting-up-a-community-solar-project/) to build a community solar project. - **Potential cost savings:** medium — While cost savings will vary with program design and implementation, community solar subscribers generally save between [5%-20% on annual electricity costs](https://www.energysage.com/community-solar/community-solar-savings/). - **Target cost drivers:** Load growth, Aging grid infrastructure, Misaligned utility incentives, Extreme weather/wildfires, Fuel price volatility ### Context and Background [Community solar programs](https://www.energy.gov/eere/solar/community-solar-basics) provide the cost savings of solar energy to households without needing to install solar systems on their homes, giving customers more control over their electricity bills. Here's [how it works](https://www.energy.gov/sites/default/files/2023-03/Community%20Solar%20Overview%20-%20Local%20Focus_0.pdf): a utility, third-party developer, or community entity constructs a mid-size solar array ([typically 1 MW-20 MW](https://docs.nrel.gov/docs/fy25osti/91361.pdf)) whose electricity is distributed to the grid. Typically, households pay a monthly fee to the project owner for a share of the electricity generated by the solar array and then receive a credit on their electric bill for that amount of electricity. Since the fee paid to the community solar project should be less than the retail electricity rate, customers generally [save 5%-20% on their electricity costs](https://www.energysage.com/community-solar/community-solar-savings/) compared to purchasing all of their electricity from their utility. For example, a customer might pay $0.14/kWh to the community solar developer each month but receive a credit of $0.16/kWh from the utility for their share of electricity generated from the community solar project. [In addition](https://rmi.org/insight/community-solar-plus/) to cost savings for individual customers, community solar paired with battery storage and equipment to "island" the facility from the grid can also provide valuable resilience during power outages and enable electrification by meeting local demand and reducing stress on the grid. ### Real-World Examples As of [2025](https://data.nrel.gov/submissions/249), 44 states have community solar programs, and 24 states have legislation enabling community solar. Many of these programs vary in size and scope, and this list includes one-off programs that are now closed. **Minnesota** [Minnesota](https://ilsr.org/articles/minnesotas-community-solar-program/) has installed over [900 MW](https://www.energy.gov/communitysolar/community-solar-market-trends) of community solar capacity since it was first enabled by [legislation](https://www.revisor.mn.gov/bills/bill.php?b=house&f=hf729&ssn=0&y=2013) (H.F. 729) in 2013. In 2023, the state passed new [legislation](https://www.revisor.mn.gov/bills/bill.php?b=house&f=hf2310&ssn=0&y=2023) (H.F. 2310), which established annual program growth caps and carve-outs for LMI subscribers. A [2024 study](https://www.lrl.mn.gov/docs/2024/mandated/241703.pdf) commissioned by the Minnesota Department of Commerce found that the program could deliver $2.9 billion in benefits to the state over the next 40 years and 3%-8% bill reductions to subscribing customers. **Georgia** [Georgia](https://www.energy.gov/communitysolar/community-solar-market-trends) currently has 135 MW of installed community solar capacity, but does not have a statewide program in place. In 2024 and 2025, legislators introduced the [Homegrown Solar Act](https://www.legis.ga.gov/legislation/70437) (H.B. 507), which would require the Georgia PSC to develop a community solar program for customers in Georgia Power’s service area, but the legislation did not pass in either year. **Massachusetts** [Massachusetts](https://docs.nrel.gov/docs/fy25osti/91361.pdf) has over 1,000 MW of community solar capacity. About 600 MW of this capacity is attributed to the Solar Massachusetts Renewable Target (SMART) program, a statewide solar incentive program developed by the Massachusetts Department of Energy Resources as a result of [2016 legislation](https://malegislature.gov/Laws/SessionLaws/Acts/2016/Chapter75#:~:text=AN%20ACT%20PROVIDING%20FOR%20A,DURING%20THE%20COVID%2D19%20EMERGENCY.&text=AN%20ACT%20AUTHORIZING%20THE%20DIVISION,TO%20THE%20CITY%20OF%20SALEM) (S.B. 1979). ### Legislative Design Considerations Legislation enabling community solar could include the following principles: **Program caps:** [At least half](https://docs.nrel.gov/docs/fy25osti/91361.pdf) of states with community solar programs have some type of overall program size cap (usually based on overall capacity). [These caps](https://docs.nrel.gov/docs/fy18osti/70663.pdf) can be a standalone target, based on a state's existing net energy metering rules, or even based on a [percentage of total electric retail sales](https://communitysolaraccess.org/wp-content/uploads/Policy-Guidebook_2024.pdf). Program caps can provide more ability for policymakers and regulators to monitor deployment and address challenges, but they may limit scaling relative to uncapped programs which allow market forces to dictate deployment. Carefully designed programs can support long-term, stable market environments for developers without the need for program caps which may require future legislative action to modify. **Project size requirements:** Similar to overall program caps, about [half of states](https://docs.nrel.gov/docs/fy25osti/91361.pdf) have caps on the size of individual community solar projects. These caps are usually in the range of 5-20 MW. [Larger projects](https://docs.nrel.gov/docs/fy18osti/70663.pdf) may benefit from economies of scale relative to smaller projects, however, smaller projects may be easier to site, disperse throughout the state, and connect to the distribution grid. These factors will vary from state to state, so policymakers can consider if individual project size caps are necessary for their state policy objectives. **Eligibility criteria:** Subscriber location and eligibility requirements are key elements of a community solar program. In every state, subscribers must be located in the [same electric utility service territory](https://docs.nrel.gov/docs/fy18osti/70663.pdf) as the solar project which helps avoid billing and other administrative issues. [Additionally](https://communitysolaraccess.org/wp-content/uploads/Policy-Guidebook_2024.pdf), while having a large "anchor offtaker" can be helpful in securing project financing, establishing a minimum number of subscribers per project and/or a maximum percentage of the project that a single subscriber can hold (usually 40%-60%) can help ensure that large subscribers are not crowding out other potential subscribers. **Incentives for development:** Providing direct monetary incentives or exemptions from other restrictions to projects located on brownfields, landfills, parking facilities, or other underutilized land can facilitate project development by helping developers overcome the higher costs associated with building in these more complex locations. **Subscriber compensation:** States have an important role in determining how community solar subscribers are [compensated](https://docs.nrel.gov/docs/fy18osti/70663.pdf), which has critical implications for potential cost savings. Key decisions include determining the rate at which subscribers are compensated for the generated electricity and the associated renewable energy certificates. **Low-income customer participation:** Including provisions for low-income customer participation can expand community solar access for low-to-moderate income (LMI) households. Many [states](https://docs.nrel.gov/docs/fy25osti/91361.pdf) include carve-outs, a specific percentage of program capacity dedicated to LMI subscribers, or financial incentives like extra funding or rate adders to expand access to LMI households. Additional funding for customer outreach and education, coupling with other low-income customer programs (e.g., weatherization, energy efficiency), and guaranteed savings requirements are [additional policy features](https://communitysolaraccess.org/wp-content/uploads/Policy-Guidebook_2024.pdf) that can promote low-income customer participation and savings from community solar. ### Further Reading - [State Policies and Programs for Community Solar](https://data.nrel.gov/submissions/249) — National Renewable Energy Laboratory (2025) - [Policy Guidebook: Expanding Solar Access through Informed Policy Decisions](https://communitysolaraccess.org/wp-content/uploads/Policy-Guidebook_2024.pdf) — Coalition for Community Solar Access (2024) - [Focusing the Sun: State Considerations for Designing Community Solar Policy](https://www.nrel.gov/docs/fy18osti/70663.pdf) — National Renewable Energy Laboratory (2018) - [Community Solar+](https://rmi.org/insight/community-solar-plus/) — RMI (2022) --- ## Low-Income Discount Rates URL: https://affordability-toolkit.rmi.org/policies/low-income-discount-rates PDF: https://affordability-toolkit.rmi.org/pdfs/low-income-discount-rates.pdf Low-income discount rates provide electricity at a discounted price, either as a flat discount or a tiered rate that varies by income group. - **Themes:** cost distribution, customer agency - **Safeguard:** Yes - **Impact time horizon:** short — Once approved and funded, low-income discount rate programs can generally launch within a year or two. - **Potential cost savings:** high — While cost savings will vary substantially with policy design and implementation, low-income discount rates can offer substantial savings for individual consumers. RMI's [Energy Poverty Policy Simulator](https://utilitytransitionhub.rmi.org/energy-poverty-policy-simulator/) shows how even modest discount rates can reduce low-income customer bills by hundreds of dollars annually. - **Target cost drivers:** Aging grid infrastructure, Fuel price volatility, Extreme weather/wildfires, Load growth, Misaligned utility incentives ### Context and Background Low-income discount rates are a tool used by states to improve energy affordability for economically vulnerable households. These programs provide energy at a discounted price, which can be structured as a flat discount (e.g., 30% off the utility's per-kWh rate for all eligible income groups) or a tiered discount (i.e., the discount varies by income group, with the lowest-income customers receiving the largest discount). Discount rate programs are often linked to federal policy guidelines or eligibility for other assistance programs. The implementation of low-income discount rates varies significantly across jurisdictions in terms of structure and benefit level. Some states mandate utilities provide these rates, while other programs have emerged voluntarily or through utility-initiated rate proposals. Low-income discount rates can serve as an alternative to percentage of income payment plans (PIPPs) or a complement to other affordability programs that protect energy access, reduce energy demand, and address customer debt. Like PIPPs, low-income discount rates help lower total bills for participating households. However, the support they provide is typically less tailored to individual household needs and can be less administratively complex. These policies can provide relief to energy-burdened customers, though tiered, rather than flat, discount rates may be necessary in order to significantly improve energy burden for the most severely burdened customers. ### Real-World Examples As of 2025, at least 12 states have low-income discount rates in place. **Connecticut — Connecticut Implementation** Connecticut's Low-Income Discount Rate lowers customer bills via a five-tiered structure with discounts ranging from 5% to 50%. The program is funded through a systems benefits charge on monthly customer bills, and households less than 200% of the federal poverty level and meeting some additional criteria are eligible. Connecticut updated its program after data sharing with the Department of Social Services triggered automatic enrollment and resulted in a large increase in costs. Relevant statutes include 2020's [Take Back Our Grid legislation (House Bill 7006)](https://legiscan.com/CT/text/HB07006/2020) which, spurred by the grid impacts of Tropical Storm Isaias, drove a number of electricity system reforms. **New Hampshire — New Hampshire Implementation** New Hampshire's Electric Assistance Program provides discounted rates on a sliding scale between 5% and 86% depending on household income. A system benefits charge on customer bills funds the program. Households earning less than 60% of the state median income are eligible, and the program provides discounts for monthly electricity usage up to 750 kWh. The statewide program distributes cost recovery across customers of all utility service territories. New Hampshire's [Revised Statutes Annotated (RSA) Chapter 374-F](https://gc.nh.gov/rsa/html/NHTOC/NHTOC-XXXIV-374-F.htm) which deals with electric utility restructuring, [authorized the program](https://liheapch.acf.gov/dereg/states/nhsnapshot.htm) . ### Legislative Design Considerations Legislation will vary state-by-state but can include the following parameters: **Policy structure:** Targeted discounts may address energy burdens for the lowest income households more fairly and adequately than flat discounts. Depending on income, households may receive discounts of anywhere from 5% to over 80%. **Eligibility criteria:** Determine whether eligibility is based on federal guidelines, participation in assistance programs, or other criteria to ensure benefits reach intended households. **Source of funding:** Specify whether the program is funded by a system benefits charge, general rates, state appropriations, or a separate public purpose fund. If paid through rates, clarify how costs are recovered and from whom. For example, some states will have all ratepayers pay a system benefits charge, some only residential ratepayers, and some only residential ratepayers with the exception of income-eligible customers. **Reporting requirements:** Requiring utilities report regularly (e.g., annually) on the program's performance, including the number of customers enrolled, program costs, outcomes, discount levels, and geographic/demographic reach, supports accountability. Providing this information transparently (e.g., on a public-facing dashboard) enables public monitoring. **Voluntary or mandatory:** Determine whether participation by utilities is mandatory or voluntary. Mandatory policies typically lead to broader coverage, more customers benefiting, and greater fairness across service territories. **Enrollment process:** Specify whether program enrollment will happen automatically or via customer-initiated applications. Automatic enrollment is considered a best practice because it improves uptake and reduces administrative burden for low-income customers. **Design details:** Consider establishing other elements, like usage caps or outreach elements, to optimize program impacts. ### Further Reading - [We Can End Energy Poverty in the Electric Sector: Here's How](https://rmi.org/we-can-end-energy-poverty-in-the-electric-sector-heres-how/) — RMI (2025) - [Utilities' Low-Income Discount Programs Help Address Energy Insecurity, But Some US States Lag Behind](https://www.energypolicy.columbia.edu/utilities-low-income-discount-programs-help-address-energy-insecurity-but-some-us-states-lag-behind/) — Columbia University Center on Global Energy Policy (2024) - [The Energy Poverty Policy Simulator](https://utilitytransitionhub.rmi.org/energy-poverty-policy-simulator/) — RMI (2024) --- ## Multi-Year Rate Plans URL: https://affordability-toolkit.rmi.org/policies/multi-year-rate-plans PDF: https://affordability-toolkit.rmi.org/pdfs/multi-year-rate-plans.pdf Multi-year rate plans, when designed effectively, can provide a powerful incentive for utilities to control costs by extending the time between utility rate cases beyond the typical one to two years. - **Themes:** cost control - **Safeguard:** No - **Impact time horizon:** long — Most regulators have adopted plan terms of [3-5 years](https://rmi.org/insight/a-strategic-framework-for-utility-cost-control/) and it can take several years for utilities to adjust their operational and planning approaches in response to an MRP. Ultimately, the primary cost savings impact from a well-designed MRP are likely to manifest when the revenue requirement for future rate cases is determined. - **Potential cost savings:** variable — MRP design and implementation has a significant impact on potential cost savings, so it is challenging to estimate potential savings across the United States. In one study, [Pacific Economics Group](https://eta-publications.lbl.gov/sites/default/files/multiyear_rate_plan_gmlc_1.4.29_final_report071217.pdf) estimated that a utility under a five-year multi-year rate plan could achieve 5% lower costs after 10 years than a utility under a traditional three-year rate case model. However, savings could range from 2%-9% depending on policy design and other factors. - **Target cost drivers:** Aging grid infrastructure, Misaligned utility incentives ### Context and Background A [multi-year rate plan](https://rmi.org/insight/a-strategic-framework-for-utility-cost-control/) (MRP) is a performance-based regulation tool that extends the time between utility rate cases beyond the typical one to two years. MRPs are intended to establish base rates that are not reset to reflect the utility's actual costs for several years. This creates an incentive for the utility to reduce spending as it can benefit from cost savings achieved relative to its allowed rates for a longer period of time compared to a traditional rate case procedure. Ultimately, efficiency gains achieved by the utility can create savings that flow down to customers via lower rates in the next cycle or through excess utility earnings returned to customers. Additionally, MRPs can provide cost savings by reducing the administrative costs associated with undertaking more frequent rate cases. However, there are several key components of MRPs that need to be carefully designed in order to provide a strong incentive for utilities to reduce spending and deliver the greatest savings to customers. ### Real-World Examples As of 2024, [14 states](https://www.naruc.org/core-sectors/energy-resources-and-the-environment/valuation-and-ratemaking/performance-based-regulation-state-tracking-map/) currently have multi-year rate plans. An additional five states have historical experience with multi-year rate plans. **Hawaii — Hawaii Implementation** Hawaii had utilized a triennial rate case cycle since 2010, and legislation in [2011](https://data.capitol.hawaii.gov/sessions/session2024/bills/HB2390_SD1_.HTM) (H.B. 2390) and [2018](https://www.capitol.hawaii.gov/sessions/session2018/bills/SB2939_SD1_.HTM) (S.B. 2939) gave the Hawaii PUC broad authority to implement regulatory reforms in support of ratepayers and the state’s energy policy goals. This led to the PUC initiating a three-year investigation focused on PBR, culminating in a [PBR framework](https://puc.hawaii.gov/energy/pbr/) launched in 2021, which features a five-year MRP. **Illinois — Illinois Implementation** Illinois [enacted legislation](https://www.ilga.gov/documents/legislation/publicacts/102/102-0662.htm) (Public Act 102-0662), which allows [Commonwealth Edison](https://www.icc.illinois.gov/docket/P2024-0181/documents/359318/files/629460.pdf) and [Ameren Illinois](https://www.icc.illinois.gov/docket/P2022-0487/documents/359319/files/629463.pdf) to submit multi-year rate plans with four-year terms to the Illinois Commerce Commission (ICC). Prior to submitting their multi-year rate plans, the legislation requires the ICC to complete an audit of each utility to evaluate the current condition of the distribution grid, understand the benefits of utility investments for ratepayers, and establish a baseline for future distribution grid spending. **Nevada — Nevada Implementation** Nevada passed [legislation](https://puc.nv.gov/uploadedFiles/pucnvgov/Content/Utilities/Electric/SB300_EN%20(1).pdf) (S.B. 300) in 2019 requiring the Public Utility Commission of Nevada to determine if alternative ratemaking mechanisms, including multi-year rate plans, are suitable for electric utilities in the state based on nine criteria, including alignment with state public policy goals, among others. **Oregon — Oregon Implementation** Oregon passed [legislation](https://olis.oregonlegislature.gov/liz/2025R1/Measures/Overview/HB3179) (H.B. 3179) in 2025 requiring the PUC to establish rules for electric and gas utilities to submit three- to seven-year multi-year rate plans and limit the quantity of utilities allowed to submit rate increases in a given year. The law gives the PUC authority to consider the cumulative economic impact of proposed rate increases on residential ratepayers, taking into consideration a variety of metrics related to affordability. ### Legislative Design Considerations Legislation on multi-year rate plans can include these principles: **PUC directive:** Successfully implementing a multi-year rate plan to reduce costs for customers is a complex undertaking that requires careful consideration of [design components](https://rmi.org/insight/how-to-restructure-utility-incentives-four-pillars-of-comprehensive-performance-based-regulation/) like attrition relief mechanisms, earnings sharing mechanisms, and off-ramps, among others, and their implications on a utility’s incentive to contain costs. Legislation can list multi-year rate plan components for public utility commissions (PUCs) to consider and provide them with the flexibility to design plans that achieve the greatest cost reductions. Additionally, legislation should make affordability and utility cost containment a central pillar of the PUC’s mandate in designing an MRP. **Regulatory framework:** Combining multi-year rate plans with other performance-based regulation (PBR) and [innovative regulatory tools](https://rmi.org/insight/how-to-restructure-utility-incentives-four-pillars-of-comprehensive-performance-based-regulation/) like revenue decoupling mechanisms, fuel-cost sharing mechanisms, and performance incentive mechanisms can strengthen the cost containment incentive of multi-year rate plans and ensure service quality remains high. Legislation that allows regulators to consider a broader suite of regulatory tools in conjunction with multi-year rate plans can deliver the greatest impact on affordability. **PUC support:** Because of the complexity in successfully implementing multi-year rate plans, it’s critical to ensure that PUCs have adequate financial and staff resources to properly study and design them. Additionally, it may be beneficial to allow PUCs to commission independent analyses or to hire consultants to support them in designing PBR frameworks that limit the potential for unintended consequences. **Policy structure:** Effective MRP design is best left to the PUC and stakeholders through a collaborative process. However, it can be helpful for legislation to provide some guardrails. For example, reconciliation of spending should be avoided (as this functions as a formula rate plan), leave the determination to allow incremental capital funding up to the regulator, but ensure that if such a mechanism is authorized, it is accompanied by a complementary incentive for the utility to spend cost-efficiently. If an earnings sharing mechanism is included, ensure there is a wide deadband before the sharing would be triggered to preserve the cost-containment incentive of the MRP. ### Further Reading - [Fixing Multiyear Rate Plans: Building a firm foundation for utility cost control](https://rmi.org/insight/fixing-multiyear-rate-plans/) — RMI (2025) - [A Strategic Framework for Utility Cost Control](https://rmi.org/insight/a-strategic-framework-for-utility-cost-control/) — RMI (2025) - [Multi-Year Rate Plans: Core Elements and Case Studies](https://www.synapse-energy.com/sites/default/files/Synapse-Whitepaper-on-MRPs-and-FRPs.pdf) — Synapse Energy Economics (2019) --- ## Permitting Reform URL: https://affordability-toolkit.rmi.org/policies/permitting-reform PDF: https://affordability-toolkit.rmi.org/pdfs/permitting-reform.pdf Modernizing permitting for large electricity generation projects can lower the cost of supplying electricity by making it faster and easier to build the lowest-cost resources to meet growing demand. - **Themes:** cost control - **Safeguard:** No - **Impact time horizon:** long — The time required to pass and enact permitting reform policy varies depending on the nature of the reform but typically takes less than five years; realization of bill savings is likely to take longer. - **Potential cost savings:** low — State-level permitting reform on its own is unlikely to deliver significant cost savings. Permitting most often affects customer bills indirectly, and state processes represent just one of several constraints on electricity deployment. State-level reforms can serve as a powerful tool when launched as part of a more comprehensive strategy to address bottlenecks across the project deployment process that includes additional levers (e.g., interconnection reform). - **Target cost drivers:** Aging grid infrastructure, Load growth ### Context and Background As electricity demand rises and affordability pressures increase, getting more generation online has become increasingly critical to maintaining affordable and reliable electricity. Permitting is a critical step for all energy infrastructure projects in the United States, and the efficiency of the permitting process directly shapes project costs and timelines. Energy developers must navigate [fragmented and overlapping authority and regulatory requirements](https://eta-publications.lbl.gov/sites/default/files/rap-enterline-valainis-laws-order-inventory-state-renewable-energy-siting-policies-2024-june.pdf) across federal, state, and local levels, leading to compounding delays, uncertainty, and costs. Although permitting reforms can occur across all these levels of government, state-level actions have an important role to play. On their own, state-level reforms may not deliver large or immediate bill savings, but they can be a powerful tool to support electricity affordability when paired with other complementary reforms. Building things faster can also improve grid reliability, resilience, economic growth, and energy security. Widespread delays and cancellations of new electricity projects can have both direct and indirect impacts on electricity prices that vary depending on market structure and other factors. Direct permitting costs (e.g., application fees and legal fees) cost about [$5–$14 billion per year in the United States](https://www.mckinsey.com/industries/public-sector/our-insights/unlocking-us-federal-permitting-a-sustainable-growth-imperative), and permitting [delays of 6–18 months can add $200,000 in expenses per megawatt](https://eta-publications.lbl.gov/sites/default/files/w3s_developer_survey_summary_-_011724.pdf) for certain energy projects. While these costs are material at the project level, their impact on customer bills can be indirect and depends on market structure. Permitting costs are passed onto ratepayers in regulated markets but not in restructured markets; in constrained electricity markets, permitting challenges can contribute to tighter supply and upward pressure on electricity prices. The table below illustrates how the direct bill impacts from project cancellations and delays — some of which permitting reform may address — vary by market type. [[permitting-reform-market-table]] Permitting reform can improve affordability by streamlining processes, clarifying requirements, and strengthening coordination across agencies to increase certainty, reduce unnecessary delays, avoid cancellations, and lower development costs. A [wide variety of state-level permitting reform strategies](https://state-permitting-power-tool.rmi.org/) exist to address different challenges and meet state needs. These reforms generally fall into three categories: fix, streamline, and deregulate. - *Fix* strategies clarify requirements and close gaps in existing processes by, for example, updating siting criteria or aligning agency standards. - *Streamline* strategies improve efficiency by, for example, improving staff capacity at the lead permitting agency, strengthening interagency coordination, or creating consolidated review processes. - *Deregulate* strategies remove or limit certain permitting requirements, where appropriate, to reduce administrative burden. A variety of state-level reforms exemplify the varied approaches to permitting modernization. For example, in 2024, Colorado passed [Senate Bill 212](https://leg.colorado.gov/bills/sb24-212) to improve the siting and permitting process for large-scale clean energy infrastructure, accelerating project development and supporting a more affordable electricity system. The bill enacts targeted reforms that strengthen state support for local governments and require state agencies to provide technical assistance, develop a model land use code, and support local and tribal review of project applications. State-level permitting is one component of the broader, complex project development process. It is closely linked with local permitting, federal permitting, and grid interconnection processes, some of which may have a more significant influence on project timelines and viability depending on the context and location. As a result, reforms at the state level alone are unlikely to drive significant bill savings. However, when coordinated with reforms across these other processes, state-level permitting changes can contribute to greater, system-wide impacts. Each of these related processes has its own distinct technical and policy challenges and is not addressed directly in this brief. ### Real-World Examples In 2025, over 90 [permitting reform bills](https://www.aeltracker.org/) were introduced across 24 states, and an additional 20 [permitting reform bills](https://www.aeltracker.org/) were enacted across 14 states.[^1] ^[1]: Source: aeltracker.org using a filter for “Permitting,” “Permit,” “Introduced,” and “Enacted” bills in 2025. The tracker identified 23 enacted bills and 115 introduced bills; manual review then excluded 3 of the 23 enacted and 23 of the 115 introduced bills that were not directly related to energy generation or transmission. **Colorado** In 2024, Colorado passed [Senate Bill 212](https://leg.colorado.gov/bills/sb24-212) to improve the siting and permitting process for large-scale renewable energy infrastructure by strengthening state support for local governments. The law requires state agencies to provide technical assistance to local and tribal governments in developing land use codes and reviewing project applications, and it creates and distributes model ordinances that support the development of renewable energy and transmission projects. **Illinois** In 2025, Illinois passed the [Clean and Reliable Grid Affordability Act](https://legiscan.com/IL/text/SB0025/2025), an omnibus energy bill that included changes to existing siting and permitting processes to reduce uncertainty and delays. The law establishes a more uniform, statewide framework while preserving a role for local governments, requiring that any local siting processes occur first but that those processes adhere to state standards and cannot be made more restrictive. A key feature is an [expedited dispute resolution process](https://www.afslaw.com/perspectives/energy-cleantech-counsel/illinois-new-state-level-wind-solar-and-energy-storage-siting) that empowers the Illinois Commerce Commission to override local government denials and issue certificates for projects if it determines that a denial of an application was not appropriate. The law also includes provisions that prevent unnecessary delays such as timelines for public hearings and decisions, limits on permitting fees and certain local requirements, and an expedited process for dismissing frivolous legal challenges. All of these reforms aim to balance state regulation, local government control, and improved consistency and predictability in the project development process. **New York** Originally established in 2020 under the Accelerated Renewable Energy Growth and Community Benefit Act, the [New York Office of Renewable Energy Siting and Electric Transmission (ORES)](https://dps.ny.gov/ores-overview) was reauthorized in 2024 through the Renewable Action Project Interconnection and Deployment (RAPID) Act. ORES serves as a "one-stop shop" to streamline permitting for renewable energy projects 25 megawatts or larger and transmission projects over 10 miles in length. The RAPID Act also establishes clear timelines, including a 60-day period to determine application completeness and a requirement for a final siting decision within one year of a complete application (or six months for projects on priority locations like brownfields, former commercial sites, former industrial sites, former power plant locations, and abandoned or underutilized sites). **Texas** In 2023, Texas passed [House Bill 5066](https://capitol.texas.gov/tlodocs/88R/billtext/html/HB05066H.htm), directing the Public Utility Commission of Texas (PUCT) and Electric Reliability Council of Texas to plan system-wide transmission solutions and to address rapid electricity load growth, particularly in the technology industry. The law requires the PUCT to approve or deny transmission applications no later than 180 days after the application is filed, accelerating the permitting process. The law also requires regulators to consider anticipated and future electricity demand, including load that has not yet been interconnected, when evaluating the need for new transmission projects. **Virginia** In 2024, Virginia passed [House Bill 650](https://legiscan.com/VA/bill/HB650/2024), requiring that key local permits for solar and energy storage projects remain valid for at least three years. The law also protects projects from later changes to local plans or policies while the permit remains valid, limiting delays and making it easier for projects to secure financing that could be jeopardized by shifting policies. In parallel, Virginia's two most recent governors (one Republican and one Democrat) have [advanced landmark reforms in permitting transparency](https://www.policyinnovation.org/insights/permitting-modernization-in-virginia), initially without legislation. These efforts include the Virginia Permit Transparency platform, which is used by ten state agencies to manage over 200 types of permits, enabling process improvements that have demonstrably reduced permitting timelines and associated costs (e.g., a 65% reduction in processing times for the state Department of Environmental Quality). ### Legislative Design Considerations Legislative approaches will differ state-to-state but can include the following actions and parameters in advancing permitting reform: **Support for local governments:** If local permitting challenges are the main cause of project delays and cancellations, as is often the case, states can provide targeted resources to counties and other local government entities where capacity, staffing, and technical knowledge are often limiting factors. These additional resources can improve permitting efficiency and accelerate timelines. **Standardized requirements:** Developing standardized permitting pathways for common project types (e.g., permit-by-rule or general permits) can reduce administrative burdens and review timelines for both agencies and developers. **Process clarity:** Requiring agencies to clearly define application requirements and review steps up-front can lower compliance costs and reduce long timelines stemming from back-and-forth during the review process. **Regulatory certainty:** Setting parameters to prevent new legislation or regulatory requirements from affecting existing permits can increase regulatory certainty and avoid the delays and costs associated with re-permitting. This can be achieved, for example, by establishing a defined permit validity period. **Energy zones:** States can work with communities and/or other state agencies, such as wildlife and agriculture, to identify zones where energy development is preferred or more appropriate, which can provide greater clarity to developers, agencies, and residents early in the permitting process. Zone designation may be paired with streamlined permitting pathways. **Community benefits:** States can consider policies that provide benefits to communities that host infrastructure, which may improve local support and reduce conflict. **Clear timelines and deadlines:** Establishing enforceable timelines and deadlines for permit review and decisions can reduce prolonged delays and uncertainty. Including automatic approvals or penalties when agencies fail to act within a certain timeframe can further incentivize timely decisions. However, poorly designed timelines can create unintended consequences, such as incentivizing permit denials over approvals, imposing arbitrary deadlines that do not reflect project complexity, or straining under-resourced agencies. To mitigate these risks, timelines can be paired with adequate funding and staffing for responsible agencies, flexibility for complex projects, and clear standards that balance timeliness and high-quality decision-making. **Centralized, coordinated, or backstop authority:** Consolidating or coordinating permitting authority across agencies can reduce fragmentation and streamline the approval process. Legislatures can also support stronger alignment across agencies involved in permitting decisions (e.g., energy-focused and wildlife-focused agencies) to reduce conflicting requirements. Backstop authority, as established in Michigan's [Public Act 233](https://www.legislature.mi.gov/documents/2023-2024/publicact/htm/2023-PA-0233.htm), can provide a viable pathway for generation projects when local regulations or opposition would otherwise limit development. Policymakers can balance state and local control by establishing clear thresholds for state intervention and preserving meaningful local input. ### Further Reading - [State Permitting Power Tool](https://state-permitting-power-tool.rmi.org/) — RMI (2026) - [Building Faster](https://building-faster.rmi.org/) — RMI (2025) - [No Time to Read 36 Resources on State Permitting Reform? We Built an Easy-to-Use Tool That Will Do It for You.](https://rmi.org/no-time-to-read-36-resources-on-state-permitting-reform-we-built-an-easy-to-use-tool-that-will-do-it-for-you/) — RMI (2026) - [Gap Analysis of Permitting Reforms in California, Illinois, New York, and Washington](https://gridstrategiesllc.com/wp-content/uploads/GS_Gap-Analysis-Permitting-Reforms-Report.pdf) — Grid Strategies LLC (2026) - [Renewable Energy Siting Policy Field Guide](https://sitingsolutions.com/wp-content/uploads/2025/12/Renewable-Energy-Siting-Policy-Field-Guide.pdf) — Siting Solutions Project (2025) --- ## Public Advocate URL: https://affordability-toolkit.rmi.org/policies/public-advocate PDF: https://affordability-toolkit.rmi.org/pdfs/public-advocate.pdf Public advocates represent the interests of consumers in utility regulatory proceedings, ensuring customer voices are heard in decisions affecting utility rates, service quality, and energy affordability. - **Themes:** cost control, cost distribution, customer agency - **Safeguard:** No - **Impact time horizon:** short — Rate cases take place in particular regions every few years, and rate cases often happen [concurrently around the United States](https://www.spglobal.com/market-intelligence/en/news-insights/research/us-energy-utilities-seek-almost-24b-in-pending-rate-cases) every year. - **Potential cost savings:** variable — While cost savings will vary based on policy design and implementation, a [2013 study](https://link.springer.com/article/10.1007/s11127-013-0145-z) found that rate structures in select states where consumer advocates intervened between 1990 and 2007 resulted in a reduction of $42 per year, or 3.6%, in average annual residential electricity bills. Notably, this study is limited to lower rates for residential customers and reduced return on equity, though other benefits may go unmonetized. - **Target cost drivers:** Aging grid infrastructure, Fuel price volatility, Extreme weather/wildfires, Misaligned utility incentives, Load growth ### Context and Background Independent utility consumer advocate offices are state-level entities that represent the interests of consumers in utility regulatory proceedings. Though their remit varies across states, they always represent residential customers and are sometimes charged with representing all ratepayers or specific types of ratepayers (e.g., small business or rural customers). Unlike other intervenors in regulatory proceedings, most state consumer advocate offices have a statutory right to intervene and have legal standing in all cases before their state's public utilities commission (PUC). Consumer advocate offices sometimes also play a role in legislative processes. These offices are intended to help ensure customer voices are heard in decisions affecting utility rates, service quality, and energy affordability. While the vast majority of states have advocate offices either [embedded in their attorney general's office or as standalone agencies](https://www.cityenergyproject.org/wp-content/uploads/2022/01/FINAL_NCEP_Consumer_Advocates_Mini_Guide.pdf), others may lack formal representation for utility customers. Establishing, funding, and strengthening these offices can help balance the influence of utilities in regulatory processes and improve affordability outcomes. ### Real-World Examples [Over 40 states and the District of Columbia](https://www.cityenergyproject.org/wp-content/uploads/2022/01/FINAL_NCEP_Consumer_Advocates_Mini_Guide.pdf) have consumer advocate offices, with some states having multiple consumer advocates. The [majority of utility consumer advocates](https://www.all4energy.org/wp-content/uploads/2024/06/consumer-advocates-by-state.pdf) are members of the [National Association of State Utility Consumer Advocates](https://www.nasuca.org/about-us/). In states without these offices, consumer advocacy may be handled by other agencies or left to nonprofit organizations. **Ohio — Office of the Ohio Consumers’ Counsel** The [Office of the Ohio Consumers’ Counsel](https://www.occ.ohio.gov/about-occ) (OCC) is an independent Ohio state agency, created by the Ohio legislature in 1976, that represents residential utility customers in issues related to investor-owned utilities before the Public Utilities Commission of Ohio (PUCO), the Supreme Court of Ohio, federal regulatory agencies, appellate courts, and the Ohio General Assembly. OCC leadership is selected by the office’s [nine-member governing board](https://www.occ.ohio.gov/governing-board), each of whom is appointed by the Ohio Attorney General. Unlike other state agencies, OCC’s operating budget [comes from a fee](https://www.occ.ohio.gov/factsheet/fact-sheet-about-office-ohio-consumers-counsel) on the gross interstate earnings of utilities regulated by the PUCO, and OCC estimates it has saved consumers $29 for every dollar spent. **Wisconsin — Wisconsin Citizens Utility Board** The Wisconsin Citizens Utility Board (CUB) was originally [created by the state legislature in 1979](https://cubwi.org/about-us/) before reorganizing into a private nonprofit organization in response to a federal Supreme Court ruling. While CUB receives funding from a variety of groups, [including small businesses](https://cubwi.org/cub-small-business-members-and-sponsors/), a [2021 act](https://docs.legis.wisconsin.gov/2021/related/acts/24) allowed the Public Service Commission to authorize CUB to receive up to $900,000 in annual funding from investor-owned utilities. **Georgia — Georgia Office of the Consumers' Utility Counsel (Proposed)** Members of the Georgia legislature [introduced legislation](https://www.legis.ga.gov/legislation/69896) in recent sessions to reestablish an Office of the Consumers' Utility Counsel that state senators [have said was removed due to 2008 budget cuts](https://www.gpb.org/news/2024/03/21/georgia-house-takes-bill-revive-consumers-utility-counsel). Though it did not pass, legislation introduced in the 2025-2026 legislative session would see the director of the office appointed by the governor and entitled to appear before authorities including the Georgia Public Service Commission and federal or state administrative agencies. ### Legislative Design Considerations While legislation establishing or strengthening public advocate offices will vary state-to-state, it can include the following: **Administration:** Ensuring the office is structurally and financially independent from utilities and regulators will help consumer advocate offices pursue issues that are in the best interests of consumers. **Scope of services:** Clearly defining the office's authority to intervene in rate cases, participate in regulatory proceedings, and advocate in legislative processes helps remove ambiguity or confusion about the office's ability to intervene in utility customer affordability issues. **Source of funding:** Establishing a stable funding mechanism, such as a small surcharge on utility bills or a dedicated state budget line item, will help with continuity in the office's ability to provide services. **Customer outreach and support:** Requiring the office to prioritize affordability and equity, particularly for low-income and historically underserved communities, helps ensure the office's electricity affordability priorities are centered around groups most affected by rate changes. ### Further Reading - [Public Utilities Commissions and Consumer Advocates: Protecting the Public Interest,](https://www.cityenergyproject.org/wp-content/uploads/2022/01/FINAL_NCEP_Consumer_Advocates_Mini_Guide.pdf) — National Council on Electricity Policy (2021) - [The Increasingly Complex Role of the Utility Consumer Advocate,](https://www.eba-net.org/wp-content/uploads/2023/02/5.-Katz-SchneiderFinal1-21.pdf) — The Energy Bar Association (2020) --- ## Return on Equity Reform URL: https://affordability-toolkit.rmi.org/policies/return-on-equity-reform PDF: https://affordability-toolkit.rmi.org/pdfs/return-on-equity-reform.pdf Return-on-equity (ROE) reform strategies aim to modernize the process for establishing allowed utility ROEs, ensuring ROEs are in line with sound financial principles and that utilities do not receive excess returns on their capital investments. - **Themes:** cost control - **Safeguard:** No - **Impact time horizon:** medium — ROE is set in rate cases which take [12-18 months to complete](https://www.utilitydive.com/news/accelerating-utility-rate-case-filings-generative-ai-artificial-intelligence-genai/730551/). After that, customers will experience immediate bill savings from the reduction in ROE, but the longer-term cost savings coming from reduced capex bias will take longer to materialize. - **Potential cost savings:** variable — Cost savings will vary with policy design and implementation, and utility ROEs vary from state to state. [Researchers](https://haas.berkeley.edu/wp-content/uploads/WP329.pdf) estimate that higher than necessary ROEs have lead to excess costs of $2.5-$8.8B per year in the United States over the last 30 years, while [other estimates](https://utilitytransitionhub.rmi.org/energy-poverty-policy-simulator/) are lower. - **Target cost drivers:** Misaligned utility incentives, Aging grid infrastructure, Load growth ### Context and Background About [63% of electricity customers](https://www.eia.gov/electricity/sales_revenue_price/xls/table_10.xlsx) in the United States are served by investor-owned utilities whose rates are regulated by public utility commissions (PUCs), and the regulator-established return on equity (ROE) has a direct impact on a utility’s rate of return (ROR), or profit. In simple terms, ROE is the allowed rate of profit on capital investments made by utilities and accounts for about [15-20% of customer bills.](https://rmi.org/rebalancing-return-on-equity-to-accelerate-an-affordable-clean-energy-future/) The equation below shows the role of ROE in determining a utility’s rate of return. ![](/images/coc-equation.svg) The terms in blue can be directly calculated and are not a challenge for regulators, while the term in red can only be estimated. The [objective of regulators](https://pubs.naruc.org/pub.cfm?id=CAD801A0-155D-0A36-316A-B9E8C935EE4D) is to set the ROE equal to a utility’s [cost of equity (COE)](https://rmi.org/rebalancing-return-on-equity-to-accelerate-an-affordable-clean-energy-future/), the rate of return on utility stocks required by investors, but the COE can only be estimated using financial models. However, the [evidence](https://haas.berkeley.edu/wp-content/uploads/WP329.pdf) suggests that authorized ROEs have been consistently higher than COE over the last 30 years. This leads to unnecessary costs for customers and perpetuates “[capex bias](https://rmi.org/insight/a-strategic-framework-for-utility-cost-control/)”, the incentive for a utility to prioritize capital investments above other solutions (even if they are more cost-effective). Excess ROEs have cost customers an estimated [$5.9 billion per year](https://haas.berkeley.edu/wp-content/uploads/WP329.pdf) over the past 30 years. State legislatures can drive ROE reform in several ways such as setting requirements for the financial models used to estimate COE, providing more support for regulators to understand financial methodology, establishing statutory limits or guidelines for ROE, or linking ROE to state policy objectives using performance incentive mechanisms (PIMs). ### Real-World Examples While it's unclear how many states have considered or enacted ROE reforms, at least [six states](https://www.lexisnexis.com/community/insights/legal/capitol-journal/b/state-net/posts/lawmakers-aim-to-cut-utility-returns) introduced ROE reform-related legislation in 2025. **Kansas — Kansas Implementation** Kansas considered [legislation](https://kslegislature.gov/li/b2025_26/measures/documents/hb2032_00_0000.pdf) (H.B. 2032) to directly link allowed ROEs to rate increases, allowing regulators to increase/decrease a utility's ROE by 0.5% depending on whether rates increase by less than 1% each year. **New York — New York Implementation** New York considered [legislation](https://www.nysenate.gov/legislation/bills/2025/S1896) (S.B. S1896), which would have established a common financing methodology by which regulators established the allowed ROE for all regulated utilities. **Florida — Florida Implementation** Florida considered [legislation](https://www.flsenate.gov/Session/Bill/2025/354) (C.S./S.B. 354) which would require the Public Service Commission to keep allowed ROEs close to the risk-free rate of return and submit annual reports to the governor and legislature on ROEs. ### Legislative Design Considerations Legislatures can consider several options to reform the process for establishing utility ROEs: **Financial model requirements:** Requiring the use of the capital asset pricing model or discounted cash flow model to determine ROE is in line with existing best practice. [Two other common models](https://www.economicliberties.us/our-work/rate-of-return/), the expected earnings analysis model and the risk premium model, have been prohibited by FERC for not adhering to sound financial logic; however, utilities frequently employ these models in state proceedings to receive high ROEs. Legislation could also direct regulators to more heavily scrutinize [key model assumptions](https://rmi.org/rebalancing-return-on-equity-to-accelerate-an-affordable-clean-energy-future/) like interest rates and growth rates which can lead to inflated ROEs. Lastly, legislation which prohibits benchmarking ROEs to utility peer groups can help break the cycle of awarding excessively high ROEs. **Rate of return (ROR) = Cost of capital (COC):** Codifying the ROR = COC standard adopted by the [Supreme Court in 1944](https://supreme.justia.com/cases/federal/us/320/591/) would ensure that utilities earn a fair rate of return without imposing excess costs on customers. [Evidence](https://haas.berkeley.edu/wp-content/uploads/WP329.pdf) shows that utility ROEs have been consistently higher than actual utility COEs over the past 30 years, indicating that the allowed ROR for utilities has been much higher than utilities' true COC. **Regulatory framework:** Enabling the use of performance-based regulation (PBR) tools like revenue decoupling, earnings sharing mechanisms, and PIMs can better align utility ROEs with state policy goals and mitigate the impact of excessively high ROEs on customers. However, the interplay between these tools is complex so legislatures can consider if regulators need additional support to study and implement these reforms. **PUC support:** Providing greater financial training for regulators can help them interpret utility ROE proposals and critique model assumptions and limitations appropriately. [Research](https://papers.ssrn.com/sol3/papers.cfm?abstract_id=2994314) has shown that regulators with more financial training have set ROEs more aligned with standard financial principles than their counterparts, so providing more training to commissioners and staff could lead to ROEs which are closer to utilities' true COE. ### Further Reading - [Rebalancing 'Return on Equity' to Accelerate an Affordable Clean Energy Future](https://rmi.org/rebalancing-return-on-equity-to-accelerate-an-affordable-clean-energy-future/) — RMI (2025) - [Cost of Capital and Capital Markets Primer for Utility Regulators](https://pubs.naruc.org/pub.cfm?id=CAD801A0-155D-0A36-316A-B9E8C935EE4D) — National Association of Regulatory Utility Commissioners (2019) - [Demystifying Utility Rate of Return](https://www.nasuca.org/wp-content/uploads/2023/12/NASUCA-ROR-Ellis-AMA-231205.pdf) — Mark Ellis (2023) - [ROE Model Analysis in the Current Financial Environment](https://www.nasuca.org/resources/webinars/roe-model-analysis-in-the-current-financial-environment-march-9-2023/) — Rothschild Financial Consulting (2023) --- ## Tariffs For Large Load Customers URL: https://affordability-toolkit.rmi.org/policies/tariffs-for-large-load-customers PDF: https://affordability-toolkit.rmi.org/pdfs/tariffs-for-large-load-customers.pdf Large load tariffs include both state-regulated retail tariffs, which set terms and rates for large electric customers like data centers, and FERC-regulated tariffs, which decide how transmission costs are shared. Together, they influence how grid costs and risks are distributed among ratepayers. - **Themes:** cost control, cost distribution - **Safeguard:** No - **Impact time horizon:** medium — State-level legislative changes to tariff structures typically take several years to translate into measurable cost impacts (including time to enact legislation). After a law is enacted, utilities must propose new tariffs, PUCs must review and determine whether to approve the tariffs, and large-load customers then negotiate service agreements. The approvals can take less than one year, while implementation often takes one to three years. The most significant cost savings or avoided costs emerge over time, as grid investments are planned and paid for based on the new tariff structure. - **Potential cost savings:** high — Well-designed large load tariffs can lead to major savings over time. These tariffs can set the terms and conditions necessary to ensure that large customers pay their cost of service and are not subsidized by other rate classes. They can also help to reduce the risk of overbuilding resources for speculative loads and promote technology improvements for more efficient operation and utilization of the grid. - **Target cost drivers:** Load growth, Aging grid infrastructure, Misaligned utility incentives ### Context and Background A tariff is a legally binding set of rates (electricity prices) and service rules that govern how customers take power from the grid. For large load customers — such as manufacturers, data centers, and other high-energy industrial or commercial facilities — tariffs determine how much they pay and the conditions for how they connect to the system. These terms in turn influence broader cost allocation outcomes across customer classes. Tariffs are increasingly structured to include safeguards, such as exit fees or minimum demand commitments, that reduce the likelihood of other customers bearing stranded costs when anticipated large load customers fail to fully materialize or leave early. There are two main types of tariffs. State-regulated retail tariffs address the utility's sale of electricity to end-use customers. The state's public utility commission (PUC) has jurisdiction over them. At the federal level, the Federal Energy Regulatory Commission (FERC) regulates interstate transmission service and wholesale power markets. FERC-regulated tariffs, such as Open Access Transmission Tariffs (OATTs), determine how transmission and wholesale electricity costs are shared among transmission customers such as utilities. Both state and FERC tariffs influence how grid costs and risks are distributed, and in turn, shape electricity affordability. State legislation can enable, constrain, or direct large load retail tariff terms, influencing how grid costs and risks are shared. Well-designed state policies can promote affordability by ensuring that the costs of serving large new loads are borne fairly, including by using large load tariffs. Because retail electricity rates are subject to state jurisdiction, legislatures can direct utilities to create a separate customer class for especially large loads, design retail electricity rates so costs are borne by those benefiting the most from system upgrades, and embed protections against stranded costs and cross-subsidies (i.e., when one group of customers pays for costs caused by another). Legislatures can choose from several approaches to ensure fair cost allocation and ratepayer protection. Creating a separate customer class for large loads can better account for costs to serve specific customer types, reduce regulatory burden associated with reviewing individual contracts, and create opportunities for broader stakeholder engagement in establishing utility best practices. ### Real-World Examples As of October 2025, at least seven US states — Minnesota, Virginia, Utah, Oregon ([HB 3546, 2025](https://olis.oregonlegislature.gov/liz/2025R1/Measures/Overview/HB3546)), Missouri ([SB 4, 2025](https://www.senate.mo.gov/25info/BTS_Web/Bill.aspx?BillID=66&SessionType=R)), Texas ([SB 6, 2025](https://capitol.texas.gov/tlodocs/89R/billtext/html/SB00006S.htm)), and Kansas ([SB 98, 2025](https://kslegislature.gov/li/b2025_26/measures/sb98/)) — have enacted statutes that address how large electricity users are classified, served, or charged. **Minnesota** Minnesota's [HF 16](https://www.revisor.mn.gov/bills/94/2025/1/HF/16/versions/0/) (2025) directs the PUC to establish a "very large customer" class in retail tariffs and to assign all attributable costs of serving that class to those customers. The statute does not set a MW threshold; the PUC will define "very large" in its tariff proceeding. Through the establishment of this new customer class, the law requires the PUC to protect other rate classes from stranded costs. The legislation also ties the state's data center tax exemptions to compliance with energy efficiency standards — linking economic development via very large customer growth to prudent grid planning. **Utah** Utah's [SB 132](https://le.utah.gov/Session/2025/bills/enrolled/SB0132.pdf) (2025) establishes a framework for "large-scale electric service" that includes a large load flexible tariff. The law establishes a threshold that applies to loads which will ramp up to ≥ 100 MW within five years. It also allows load to contract with alternative generation providers if the utility cannot provide timely service to large load customers. The law also ensures that large load incremental costs are excluded from general rates to mitigate the potential for cross-subsidization. **Virginia** In 2025, Virginia enacted two complementary measures addressing large load customers. [HB2084 (Ch. 395)](https://law.lis.virginia.gov/uncodifiedactssub/2025/session1/chapter395/) directs the State Corporation Commission (SCC) to review whether current customer classifications remain reasonable by July 1, 2027. This bill gives the SCC more discretion to consider and establish separate rate classes and potential cost shifting to other customers. [HB 2644 (Ch. 499)](https://lis.blob.core.windows.net/files/1076859.PDF) allows electric cooperatives to establish for-profit affiliates to sell power on an unregulated basis to customers exceeding 90 MW. This creates an alternative service path for large loads with the intention of insulating smaller cooperative members from related costs. ### Legislative Design Considerations Legislation on large load tariffs can include the elements listed below. These actions describe what a legislature can establish in statute — either directly or by directing and empowering the PUC to act through tariff proceedings, planning processes, and related orders. **Customer Eligibility:** Legislation can define or direct the PUC to define large load customer classes based on factors such as the size (MW) of the contracted load and the capacity factor of the load. This gives PUCs firmer ground to review and approve tariffs that address energy users who have a large footprint on the grid. These factors are viewed as less discriminatory than classifying customers based on their use, making PUC decisions less vulnerable to legal challenges. **Cost Allocation and Protections:** Legislation can require the PUC to review existing cost allocation methodologies to ensure they fairly assign costs across and within customer classes and protect ratepayers from future risk. Large load tariffs developed under this direction could include [ratepayer protections](https://rmi.org/large-energy-users-want-power-heres-how-to-protect-other-ratepayers-from-the-costs/) such as minimum term commitments (e.g., 10 years), minimum demand or energy commitments, capacity-reservation charges, and collateral or exit fees. These are all tools that reduce the risk other customers bear if large loads don't materialize. **Cost Control and Operational Flexibility:** Legislation can direct or enable the PUC to evaluate integrating measures into tariffs that curb system costs and incentivize efficient operations: - Enable [demand flexibility](https://rmi.org/fast-flexible-solutions-for-data-centers/) (e.g., through use of on-site generation, off-site demand flexibility such as through a virtual power plant, or by shifting computing demands) and staged load ramps to shape/shift load and reduce costly peaks. - Coordinate with transmission planners to evaluate alternative transmission technologies (including grid-enhancing technologies and advanced conductors) as eligible non-wires solutions that create headroom for new loads and help avoid or defer traditional infrastructure. **Integration with Load Forecasting:** Legislation can require or encourage the PUC to incorporate certain large load tariff terms and conditions, such as collateral requirements or exit fees, into [grid planning and forecasting](https://rmi.org/insight/get-a-load-of-this/). Incorporating these terms may help deter speculative load interconnection requests, inform how likely it is that the large load will materialize, and reduce uncertainty in load forecasts. ### Further Reading - [Database of Emerging Large-Load Tariffs (DELTa)](https://sepapower.org/large-load-tariffs-database/) — Smart Electric Power Alliance (2025) - [Large Load Tariff Design Principles](https://rmi.org/insight/large-load-tariff-principles/) — RMI and Advanced Energy United (2025) - [Electricity Rate Designs for Large Loads: Evolving Practices and Opportunities](https://www.energy.gov/policy/articles/electricity-rate-designs-large-loads-evolving-practices-and-opportunities?utm_source=chatgpt.com) — Lawrence Berkeley National Laboratory (2025) - [Large Energy Users Want Power. Here's How to Protect Other Ratepayers from the Costs.](https://rmi.org/large-energy-users-want-power-heres-how-to-protect-other-ratepayers-from-the-costs/) — RMI (2025) - [State Policy Toolkits for Data Center Regulation](https://climate-xchange.org/resources-for-regulating-data-centers/electricity-affordability-and-reliability-impacts/) — Climate XChange (2026) - [New Ways to Power Data Centers and Other Large Energy Users](https://rmi.org/resources/new-ways-to-power-data-centers-and-other-large-energy-users/) — RMI (2026) --- ## Advanced Transmission Technologies URL: https://affordability-toolkit.rmi.org/policies/advanced-transmission-technologies PDF: https://affordability-toolkit.rmi.org/pdfs/advanced-transmission-technologies.pdf Advanced transmission technologies enhance grid performance - at a lower cost than building new high-voltage lines - while using existing rights of way. - **Themes:** cost control - **Safeguard:** No - **Impact time horizon:** short — Most advanced transmission technologies can be deployed in the [short term](https://rmi.org/getting-alternative-transmission-technologies-to-scale/) though some may take longer. For example, topology optimization software or dynamic line rating approaches may be deployed in a year or less. - **Potential cost savings:** high — Cost savings will depend on the policies and technologies employed, but many studies have shown ATTs to be cost-effective. One estimate found that a $100 million investment in ATTs in the PJM region would yield about [$1 billion in annual production cost savings](https://rmi.org/insight/analyzing-gets-as-a-tool-for-increasing-interconnection-throughput-from-pjms-queue/), another found that grid-enhancing technologies could deliver [$5 billion in yearly energy production cost savings](https://www.brattle.com/insights-events/publications/grid-enhancing-technologies-shown-to-double-regional-renewable-energy-capacity-according-to-study-by-brattle-consultants/) nationally with a 6-month payback period, and one estimated high-performance conductors could save [$180 billion](https://haas.berkeley.edu/wp-content/uploads/WP343.pdf) in electricity system costs nationally by 2050. - **Target cost drivers:** Aging grid infrastructure, Load growth, Misaligned utility incentives ### Context and Background An affordable transition to a modernized electricity system requires not just more transmission infrastructure but better transmission infrastructure. Today's grid planning and deployment processes focus mostly on the former — building new high-voltage transmission lines - and often overlook technologies like dynamic line ratings, high-performance conductors, topology optimization, and power flow control that can enhance grid performance at a lower cost while using existing rights of way.[^1] These solutions, known collectively as "advanced transmission technologies" (ATTs), are key to quickly and affordably deploying additional resources and unlocking transmission capacity. But they face regulatory hurdles, institutional barriers, and upfront capital costs that slow their adoption. State policy can accelerate the adoption of these technologies by, for example, requiring their evaluation in planning processes. A total of fifteen states across the political and geographic spectrum have now enacted policies to accelerate the deployment of advanced transmission technologies with the goal of meeting new demand affordably. ^[1]: Alternative transmission technologies refer collectively to grid-enhancing technologies (GETs) and advanced conductors. ### Real-World Examples **Indiana — Indiana Implementation** Indiana's [Senate Bill 422](https://legiscan.com/IN/text/SB0422/id/3179428) establishes requirements for utilities to evaluate grid-enhancing technologies (GETs) as part of their integrated resource plans (IRPs) starting in 2026. **Ohio — Ohio Implementation** Ohio's [House Bill 15](https://www.legislature.ohio.gov/legislation/136/hb15) requires that utilities evaluate advanced transmission technologies when applying for a Certificate of Public Necessity to expand or build new transmission infrastructure, study their use to reduce grid congestion, and submit implementation plans for cost-effective ATT solutions. It also directs the utility commission to assess statewide opportunities for ATT deployment. **Utah — Utah Implementation** Utah's [House Bill 212](https://le.utah.gov/~2025/bills/static/HB0212.html), signed into law in 2025, requires utilities that propose additions to or expansions of the transmission system to analyze opportunities to use GETs within IRP filings, rate cases, and other proceedings. ### Further Reading - [How State Regulators Can Utilize the Latest Legislative Trend to Make Electricity More Affordable and Reliable](https://rmi.org/how-state-regulators-can-utilize-the-latest-legislative-trend-to-make-electricity-more-affordable-and-reliable/) — RMI (2025) - [Getting Alternative Transmission Technologies to Scale](https://rmi.org/getting-alternative-transmission-technologies-to-scale/) — RMI (2025) - [State Legislative Momentum Builds for Grid Enhancing Technologies in 2025](https://watt-transmission.org/state-policy-momentum-builds-for-grid-enhancing-technologies-in-2025) — Working for Advanced Transmission Technologies (WATT) Coalition (2025) - [A Roadmap for Advanced Transmission Technology Adoption](https://ceepr.mit.edu/wp-content/uploads/2024/09/MIT-CEEPR-RC-2024-06.pdf) — Massachusetts Institute of Technology (MIT) Center for Energy (2024) - [Grid-Enhancing Technologies: A Case Study on Ratepayer Impact](https://www.energy.gov/sites/default/files/2022-04/Grid%20Enhancing%20Technologies%20-%20A%20Case%20Study%20on%20Ratepayer%20Impact%20-%20February%202022%20CLEAN%20as%20of%20032322.pdf) — United States Department of Energy (2022) - [Advanced Transmission Technologies](https://www.energy.gov/sites/prod/files/2021/02/f82/Advanced%20Transmission%20Technologies%20Report%20-%20final%20as%20of%2012.3%20-%20FOR%20PUBLIC.pdf) — United States Department of Energy (2020) - [Enabling ATTs and GETs](https://www.climatepolicydashboard.org/policies/electricity/transmission-atts-gets) — Climate Xchange (2024) - [Unlocking Power: A Playbook on Grid Enhancing Technologies for State and Regional Regulators and Policymakers](https://acore.org/resources/unlocking-power-a-playbook-on-grid-enhancing-technologies-for-state-and-regional-regulators-and-policymakers/) — American Council on Renewable Energy (2024) - [Advanced Transmission Technologies](https://quanta-technology.com/report/report-on-advanced-transmission-technologies/) — Quanta Technology (2025) - [STATES - WATT Coalition](https://watt-transmission.org/resource-library/states/) — Working for Advanced Transmission Technologies (WATT) Coalition (2025) --- ## Better Alignment Between Electric And Gas Planning URL: https://affordability-toolkit.rmi.org/policies/better-alignment-between-electric-and-gas-planning PDF: https://affordability-toolkit.rmi.org/pdfs/better-alignment-between-electric-and-gas-planning.pdf Better alignment between electric and gas planning optimizes investments and reduces duplicative infrastructure, lowering costs for utilities and customers. - **Themes:** cost control - **Safeguard:** No - **Impact time horizon:** medium — Policy and regulatory changes can be implemented within a few years, with cost impacts realized as new investments are approved and executed. - **Potential cost savings:** variable — While cost savings will vary based on policy design and implementation, avoiding redundant infrastructure and optimizing investments across both systems can yield [substantial long-term savings](https://eta.lbl.gov/publications/opportunities-integrating-electric) for utilities and customers, as well as more fairness in cost allocation across fuels and customers. - **Target cost drivers:** Misaligned utility incentives, Aging grid infrastructure ### Context and Background [Electric and gas utilities have traditionally planned their systems separately](https://eta-publications.lbl.gov/sites/default/files/2024-12/opportunity_integrate_electric_gas_planning_20241223_final.pdf), leading to higher costs and missed savings, but [aligning their planning](https://rmi.org/insight/a-strategic-framework-for-utility-cost-control) helps optimize investments, reduce duplication, and support an affordable transition to a more modern energy system through demand-side and distributed resources, along with targeted electrification. Alignment also enables better targeted customer programs, like efficiency measures, varied electrification measures, and targeted distributed energy resource (DER) deployment that avoid costs associated with unnecessary capacity expansions of gas or electric systems, coupled with changing demand patterns. Alignment can take the form of or be benefited by initiating new or refining existing gas planning processes, coordination between electric and gas planning assumptions and results, and integration of state policy goals into planning processes. ### Real-World Examples **Massachusetts** In December 2023, the Massachusetts Department of Public Utilities (DPU) issued an order setting a new regulatory framework for the future of gas distribution. It requires local gas distribution companies to file Climate Compliance Plans and [coordinate with electric utilities on targeted electrification and decarbonization strategies](https://www.ethree.com/massachusetts-dpu-order-20-80-future-of-gas-proceeding-e3-decarbonization-pathways/), and to [consider non-gas alternatives](https://www.mass.gov/news/department-of-public-utilities-issues-order-20-80) to gas expansion projects. Massachusetts General Laws Chapter 25 authorizes the DPU to undertake a [variety of activities](https://malegislature.gov/Laws/GeneralLaws/PartI/TitleII/Chapter25), including issuing orders. **Minnesota** In October 2024, the Minnesota Public Utilities Commission (PUC) approved a [new gas utility integrated resource planning framework](https://www.edockets.state.mn.us/documents/%7B10C8D392-0000-CD32-9AA3-0C989AB58883%7D/download) that requires the state's three largest gas utilities to conduct long-term planning with stakeholder input and commission oversight. Under [Minnesota state statute](https://www.revisor.mn.gov/statutes/cite/216B/full), the PUC is authorized to undertake a variety of activities, including approving such frameworks. **Washington** The Washington Utilities and Transportation Commission is required by state law to adopt [rules for consolidated planning](https://www.utc.wa.gov/casedocket/2024/240281/docsets) by large combination electric and natural gas utilities. The Commission must also establish a cost-effectiveness test for emissions reduction measures taken by these utilities to comply with Washington's energy and climate policies. ### Further Reading - [Opportunities for Integrating Electric and Gas Planning,](https://www.raponline.org/knowledge-center/opportunities-integrating-electric-gas-planning/) — Regulatory Assistance Project (2025) - [A Strategic Framework for Utility Cost Control,](https://rmi.org/insight/a-strategic-framework-for-utility-cost-control/) — RMI (2025) --- ## Consideration Of Stranding Risk URL: https://affordability-toolkit.rmi.org/policies/consideration-of-stranding-risk PDF: https://affordability-toolkit.rmi.org/pdfs/consideration-of-stranding-risk.pdf Modernizing the processes used to consider the asset-stranding risk of utility-proposed generation resources can help guard against unnecessary utility investment recovered by ratepayers. - **Themes:** cost control - **Safeguard:** No - **Impact time horizon:** long — Consideration of stranding risk occurs in the utility planning process and can be evaluated by regulators in rate cases or integrated resource planning (IRP) proceedings. [Most IRP filing frequencies](https://www.energy.gov/sites/default/files/2024-12/best_practices_irp_nov_2024_final_optimized.pdf) range from 1-5 years. Impacts may not be felt for another 10+ years. - **Potential cost savings:** medium — While cost savings will vary from state to state, improved planning processes and evaluating the true potential costs of resources with more realistic asset lifetimes against less expensive alternatives can help avoid these types of stranded costs. In [Wisconsin](https://rmi.org/avoiding-the-stranded-asset-mistakes-of-the-past-a-case-study-in-wisconsin/), a utility invested in equipment to extend the life of a coal plant instead of investing in new resources. The coal plant ultimately retired early anyway because it was too costly to operate, costing ratepayers $680 million over 17 years. - **Target cost drivers:** Aging grid infrastructure, Misaligned utility incentives, Load growth ### Context and Background Regulators can utilize realistic assumptions and planning methodologies when considering the [asset-stranding risk](https://rmi.org/insight/a-strategic-framework-for-utility-cost-control/) of utility-proposed generation resources to mitigate negative cost impacts for customers. In the electricity sector context, a stranded asset is typically a power plant that becomes uneconomic or needs to be retired in accordance with state or federal policy requirements before its costs have been fully recovered by ratepayers. Regulators review the stranding risk of utility-proposed power plants to determine the value it is likely to provide ratepayers, however, unrealistic assumptions about the expected useful life of the power plant or failing to account for market disruptions like the cost trajectories of other technologies can lead to an inaccurate assessment of a power plant's stranding risk. There are a [few common results](https://www.sierraclub.org/sites/default/files/sierra-club-harnessing-financial-tools-electric-sector.pdf) in these cases: customers pay for an uneconomic power plant to continue operating, customers pay for a plant no longer operating, or regulators require utilities to absorb the unrecovered costs from the power plant. In all these cases, failure to proactively consider stranding risk results in unnecessary costs for customers or utilities. Legislatures can direct regulators to enhance their processes for considering the stranding risk of new power plants by requiring the use of expected asset lifetimes in analyses (rather than the typical 40-50 year timelines), requiring utilities to conduct different scenario analyses to estimate the assets value under different circumstances, requiring utilities to revalue assets which may provide more value in early years and less value in later years, or requiring a lower return on equity (ROE) for power plants with higher stranding risk than the utility's standard ROE. By using appropriate assumptions and methods for considering stranding risk, regulators can better understand the overall cost impact of different energy sources on ratepayers. ### Real-World Examples These state examples illustrate how states have put the policy into practice, highlighting different design approaches. **Minnesota** Minnesota's statute ([216B.243](https://www.revisor.mn.gov/statutes/cite/216b.243)) requires utilities to evaluate the risks associated with environmental costs and regulation of fossil power plants over their lifetime and whether electricity demand could be met using demand response, distributed generation, or other measures when submitting a certificate of need for a new power plant. **Colorado** Colorado passed [legislation](https://www.leg.colorado.gov/bills/sb23-291) (S.B. 23-291), which requires utilities to use a discount rate that does not exceed the long-term rate of inflation when evaluating the net present value of carbon-based fuel costs. This helps [mitigate stranding risk](https://ilsr.org/articles/colorado-bill-utility-accountability-ler194/) by ensuring fossil fuel resources are fairly valued compared to alternatives. ### Further Reading - [Stranded Fossil Fuel Infrastructure: How Big Is the Stranded Asset Problem, and What Should We Do About It?](https://www.brattle.com/wp-content/uploads/2021/08/Stranded-Fossil-Fuel-Infrastructure-How-Big-is-the-Stranded-Asset-Problem-and-What-Should-We-Do-About-It.pdf) — Brattle Group (2021) - [A Strategic Framework for Utility Cost Control](https://rmi.org/insight/a-strategic-framework-for-utility-cost-control/) — RMI (2025) - [Avoiding the Stranded Asset Mistakes of the Past: A Case Study in Wisconsin](https://rmi.org/avoiding-the-stranded-asset-mistakes-of-the-past-a-case-study-in-wisconsin/) — RMI (2025) --- ## Improved Planning Processes URL: https://affordability-toolkit.rmi.org/policies/improved-planning-processes PDF: https://affordability-toolkit.rmi.org/pdfs/improved-planning-processes.pdf Improved planning processes can reduce system costs and lower customer bills by avoiding unnecessary infrastructure investments and identifying cost-effective and reliable solutions. - **Themes:** cost control - **Safeguard:** No - **Impact time horizon:** medium — Planning reforms typically take effect over one or more planning cycles, with impacts realized as new investments are approved and implemented. - **Potential cost savings:** medium — While cost savings will vary based on policy design and implementation, improved planning processes can [reduce system costs and customer bills](https://watt-transmission.org/wp-content/uploads/2021/02/Brattle__Unlocking-the-Queue-with-Grid-Enhancing-Technologies__Final-Report_Public-Version.pdf90.pdf) by avoiding overbuilt infrastructure and [selecting lower-cost energy or demand-side solutions](https://rmi.org/clean-energy-portfolios/). - **Target cost drivers:** Load growth, Aging grid infrastructure, Misaligned utility incentives ### Context and Background For vertically integrated utilities, adopting high-quality, integrated planning processes that span generation planning, distribution system planning, and transmission planning will help ensure that [cost-effective and customer-centric resources are considered](https://www.esig.energy/wp-content/uploads/2025/06/v2-ESIG-IP-Guidebook-report-2025.pdf) when utilities plan for future investments. Even for "wires-only" utilities, updating and coordinating distribution and transmission planning processes, [especially to integrate distributed energy resources (DERs)](https://www.esig.energy/wp-content/uploads/2022/01/ESIG-DER-Integration-Wholesale-Markets-2022.pdf), can [drive down costs and improve system reliability](https://rmi.org/wp-content/uploads/2018/12/rmi-non-wires-solutions-playbook-report-2018.pdf). Traditional planning often silos different planning processes and [favors utility-owned, capital-intensive infrastructure while overlooking lower-cost alternatives like DERs](https://rmi.org/wp-content/uploads/dlm_uploads/2024/07/PBR_Deck_final.pdf). Modern planning requires utilities to evaluate a broader set of solutions, including demand-side solutions like virtual power plants (VPPs) and demand-side management programs, [advanced transmission technologies](https://rmi.org/getting-alternative-transmission-technologies-to-scale/) (ATTs) [like grid-enhancing technologies](https://rmi.org/press-release/rmi-study-reveals-large-opportunity-for-clean-energy-and-customer-savings-in-pjm-by-deploying-gets/) (GETs) and advanced conductors, community solar, and [utility-scale electricity generation](https://rmi.org/clean-energy-portfolios/). State legislatures and public utilities commissions (PUCs) can enable least-cost, least-risk planning outcomes by [modernizing requirements for integrated resource plans (IRPs)](https://www.ncsl.org/energy/integrated-resource-planning-a-primer-for-state-legislators), [distribution system plans](https://emp.lbl.gov/projects/integrated-distribution-system-planning) (DSPs), and [transmission planning](https://rmi.org/insight/mind-the-regulatory-gap/) practices - in addition to engaging in formal proceedings and providing critical input via other channels. Improvements to planning include: - Defining requirements for transmission and distribution plans in addition to resource planning, including establishing methods for coordinating across planning processes - Ensuring plans evaluate emerging and non-traditional resources as options for providing critical grid services in resource planning - Identifying key policy objectives for resource planning, such as reducing long-term transition risks - Increasing the transparency of planning with clearly defined opportunities for stakeholder engagement. These improvements reduce system costs, avoid unnecessary infrastructure, and accelerate the transition to a more affordable and resilient grid. ### Real-World Examples **Michigan** In 2023, the Michigan state legislature passed a [comprehensive bill](https://www.legislature.mi.gov/documents/2023-2024/publicact/htm/2023-PA-0231.htm) updating utility regulation that includes detailed updates to resource planning requirements. Among other things, the bill enables stakeholders to define key assumptions in planning and ensure the utility evaluates plans in alignment with state priorities. Additionally, [statute](https://www.legislature.mi.gov/Laws/MCL?objectName=mcl-460-6t) requires the commission to review planning regulation and revise the rules every 5 years. **Minnesota** In 2022, the Minnesota PUC via order Docket No. E002/M-21-694 [updated their integrated distribution planning requirements](https://www.edockets.state.mn.us/documents/%7B30E7F284-0000-C433-8FFA-298183EBEB26%7D/download?contentSequence=0&rowIndex=17), established in 2018, to include transmission planning. [Minnesota state statute](https://www.revisor.mn.gov/statutes/cite/216B.2422) directs utilities to periodically file resource plans with the commission and empowers the commission to approve, reject, or modify those plans. **Oregon** In 2024, the Oregon PUC adopted revised DSP guidelines through [Docket No. UM 2005](https://edocs.puc.state.or.us/efdocs/HAU/um2005hau332756033.pdf), building on [guidelines from 2020](https://apps.puc.state.or.us/orders/2020ords/20-485.pdf). The new guidelines help utilities understand what should be included in their DSPs to align plans with state goals, tie investment planning to rate recovery, and better coordinate their DSPs with other planning processes, including IRPs and Clean Energy Plans (CEPs), which are [required by Oregon law](https://olis.oregonlegislature.gov/liz/2021R1/Measures/Overview/HB2021). ### Further Reading - [Integrated Distribution System Planning](https://emp.lbl.gov/projects/integrated-distribution-system-planning) — Berkeley Lab - [50 Ways to Improve Planning for Electricity Resources of the Future,](https://emp.lbl.gov/news/50-ways-improve-planning-electricity-resources-future) — Berkeley Lab (2024) - [Reimagining Resource Planning](https://rmi.org/insight/reimagining-resource-planning/) — RMI (2023) --- ## Managed Gas Transition URL: https://affordability-toolkit.rmi.org/policies/managed-gas-transition PDF: https://affordability-toolkit.rmi.org/pdfs/managed-gas-transition.pdf A managed gas transition avoids stranded asset risks and ensures costs are kept fair and stable for customers as more households adopt electric equipment and appliances. - **Themes:** cost control, cost distribution - **Safeguard:** No - **Impact time horizon:** long — Most changes in the size of the gas system, utility business models, and ratepayer protection programs are likely to play out over five years to a few decades after policy passage. Short- and medium-term impacts, such as the modification or elimination of line extension allowances, identification of targeted electrification zones, or development of customer incentives, may also occur. - **Potential cost savings:** high — [One study](https://www.ethree.com/wp-content/uploads/2024/06/Gas-Decommissioning-Fact-Sheet-2024-06-18.pdf) showed that strategic retirement of portions of the gas system in California could avoid as much as $20 billion in pipeline replacement costs by 2045 with impacts limited to only 3% of current gas customers. The savings would amount to roughly $32,000 per household-likely enough to cover the upfront expenses of electrification. Overall, cost savings from managed gas transition policies will depend substantially on policy structure and design. - **Target cost drivers:** Aging grid infrastructure, Misaligned utility incentives, Fuel price volatility ### Context and Background As adoption of electric appliances like heat pumps accelerates, gas usage may decline over time, raising the risk that customers will begin leaving the gas system. If this transition unfolds in an unmanaged way, with some but not all customers on a given segment of the gas system electrifying, utilities will be forced to recover the costs of maintaining that part of the gas system from a shrinking customer base. This dynamic risks triggering a reinforcing cycle of rising rates and further departures, disproportionately burdening low-income customers who would have the most difficulty electrifying. In parallel, the gas utility business model, centered on expanding and maintaining gas delivery infrastructure, is not well designed to manage a major transition of reducing demand and customer counts. Even if current customer counts remain stable in the near term, this potential shift represents a structural risk to be managed proactively by utilities and regulators. A coordinated, phased, and managed transition of gas infrastructure is necessary to avoid stranded asset risks and ensure fairness in a modernizing energy system. ### Real-World Examples A number of states (Washington, Oregon, California, Nevada, Colorado, Minnesota, Illinois, New York, Massachusetts, Rhode Island, New Jersey, Maryland) and the District of Columbia [have opened gas planning or "future of gas" proceedings](https://rmi.org/wp-content/uploads/2023/09/gas_policy_memo_september-2023.pdf) in recent years. Outcomes and goals vary, but several states have established long-term gas planning requirements or have taken action on policy issues such as line extension allowances as a result. **Colorado — Colorado Implementation** Colorado's [Senate Bill 23-291](https://leg.colorado.gov/bills/sb23-291) eliminated incentives for connecting new buildings to the gas system, known as gas line extension allowances. Ending the use of these subsidies reduced the expansion of gas rate base and the long-term risk of stranded asset costs. Colorado also has established requirements for gas infrastructure planning and "clean heat" plans. **Maryland — Maryland Implementation** Maryland's [Senate Bill 0937](https://mgaleg.maryland.gov/mgawebsite/Legislation/Details/sb0937?ys=2025RS) requires gas utilities to formally evaluate alternatives to traditional capital investments like pipe replacement, and to better prioritize the investments they do make, in order to limit unnecessary spending on the gas system. The Maryland Public Service Commission is also considering long-term gas planning and line extension allowance policy in [docket number 9707](https://opc.maryland.gov/Consumer-Learning/Future-of-Gas/The-PSC-FOG-Docket). **Minnesota — Minnesota Implementation** Minnesota's [Natural Gas Innovation Act](https://mn.gov/puc/activities/economic-analysis/ngia/) directs major gas utilities to file resource plans that explore strategies for gas resources aligned with the state's 2050 net-zero goal, including electrification and thermal networks. It also establishes a "future of gas" docket to analyze long-term challenges and opportunities. Minnesota also established a gas integrated resource planning requirement in 2024. **Oregon — Oregon Implementation** Oregon launched its future of gas proceeding to evaluate a long-term strategy for its natural gas system, including targeted electrification. Statutory precursors included [House Bill 3152](https://olis.oregonlegislature.gov/liz/2023R1/Measures/Overview/HB3152), which permitted the commission to institute proceedings that align with state emissions targets and mitigate stranded asset risks. ### Further Reading - [Overextended: It's Time to Rethink Subsidized Gas Line Extensions](https://rmi.org/insight/its-time-to-rethink-subsidized-gas-line-extensions/) — RMI (2021) - [Non-Pipeline Alternatives](https://rmi.org/insight/non-pipeline-alternatives/) — RMI (2024) - [The case for natural gas transition planning](https://rmi.org/wp-content/uploads/2023/09/gas_policy_memo_september-2023.pdf) — RMI (2023) - [Building Decarbonization Roadmap](https://usclimatealliance.org/wp-content/uploads/2023/04/USClimateAlliance_Guide_BuildingDecarbonizationRoadmap_2021.pdf) — United States Climate Alliance (2021) --- ## Revenue Decoupling URL: https://affordability-toolkit.rmi.org/policies/revenue-decoupling PDF: https://affordability-toolkit.rmi.org/pdfs/revenue-decoupling.pdf Revenue decoupling policies remove the link between a utility's revenue and the amount of electricity that it sells to make the utility more agnostic toward energy-saving measures. - **Themes:** cost control - **Safeguard:** No - **Impact time horizon:** variable — Removing the incentive to sell more electricity leads to utilities being less averse to pursuing cost-efficiency approaches like energy efficiency, distributed energy, and energy storage because these no longer reduce revenue. However, if implemented without mechanisms that incentivize utility focus on these programs, the presence of revenue decoupling on its own is unlikely to override other utility incentives that render these approaches less attractive solutions to utilities. The timeline of impacts is therefore likely to depend on the design of complementary mechanisms. - **Potential cost savings:** variable — Revenue decoupling can unlock transformative energy efficiency programs and can contribute to avoiding build out of unnecessary new power plants when paired with complementary mechanisms that mitigate capex bias. However, the design of decoupling mechanisms is complex — cost savings will vary based on design, and if structured poorly, they can even result in unintended and counterproductive outcomes. - **Target cost drivers:** Misaligned utility incentives ### Context and Background Revenue decoupling policies remove the link between a utility's revenue and the amount of electricity that it sells to make the utility agnostic to investment in conservation measures and technologies that reduce electricity demand. Instead of earning more money from the more electricity it sells, a predetermined revenue sufficient to cover the utility's fixed costs is approved by regulators. At a regular interval, this authorized revenue is compared to actual revenue, and rates are adjusted to refund excess or recover the difference. This structure guarantees utility revenues, thereby rendering the utility less antagonistic toward third-party services and programs that are designed to reduce electricity sales volume. ### Real-World Examples These state examples illustrate how states have put the policy into practice, highlighting different design approaches. **Idaho — Idaho Implementation** Idaho's revenue decoupling mechanism, implemented for Idaho Power, aims to remove the utility's disincentive to promote efficiency by stabilizing revenues independent of electricity sales. The program includes an annual true-up process with resulting surcharges or credits applied to customers' bills via a monthly rider. The decoupling mechanism began as a commission-approved pilot resulting from a settlement agreement and was subsequently made permanent as an ongoing regulatory mechanism rather than specific statewide legislation. **Minnesota — Minnesota Implementation** Minnesota's decoupling framework began with [Minnesota Statutes Section 216B.2412](https://www.revisor.mn.gov/statutes/cite/216B.2412), enacted in 2007 by the state legislature, which authorized the commission to consider and approve pilot decoupling programs and report findings. Permanent decoupling programs came later through regulatory approval. Xcel Energy (electricity) and CenterPoint Energy (gas) currently operate revenue decoupling programs. Both programs include annual true-ups. ### Further Reading - [The Nuts and Bolts of Performance-Based Regulation: Tools to Build a More Affordable, Reliable, and Equitable Grid](https://rmi.org/wp-content/uploads/dlm_uploads/2024/07/PBR_Deck_final.pdf) — RMI (2024) - [How to Restructure Utility Incentives](https://rmi.org/insight/how-to-restructure-utility-incentives-four-pillars-of-comprehensive-performance-based-regulation/) — RMI (2024) --- ## Time-Varying Rates URL: https://affordability-toolkit.rmi.org/policies/time-varying-rates PDF: https://affordability-toolkit.rmi.org/pdfs/time-varying-rates.pdf Time-varying rates provide an incentive for customers to shift their electricity consumption throughout the day from peak to off-peak periods, which can lead to lower electricity bills. - **Themes:** cost control, customer agency - **Safeguard:** No - **Impact time horizon:** medium — [Full deployment](https://www.publicpower.org/system/files/documents/Moving-Ahead-Time-of-Use-Rates.pdf) of time-varying rates requires regulatory proceedings and is often preceded by pilot programs and customer education. - **Potential cost savings:** low — While potential cost savings will vary based on the specific time-varying rate structure and state context, the [overall bill savings](https://www.publicpower.org/system/files/documents/Moving-Ahead-Time-of-Use-Rates.pdf) for customers enrolled in time-varying rates range from 0%-5%. [Bill savings](https://www.sciencedirect.com/science/article/abs/pii/S1040619017302750) are dependent on the rate design, particularly the difference between on- and off-peak prices, the availability of enabling technology, and the success of educational efforts for customers. - **Target cost drivers:** Load growth, Aging grid infrastructure, Misaligned utility incentives, Extreme weather/wildfires, Fuel price volatility ### Context and Background Under a traditional electricity rate structure, customers pay the same amount no matter when electricity is consumed. This provides no incentive for customers to shift their electricity consumption throughout the day from peak hours when the cost to provide electricity is high to periods when the grid is less strained and the cost to provide electricity is lower. [Time-varying rates](https://rmi.org/insight/a-strategic-framework-for-utility-cost-control/) are an alternative to this traditional rate structure, where utilities charge customers a different amount based on the hour, day, and/or season when the electricity is used. As a result, customers have an incentive to shift their electricity consumption from peak to off-peak periods, lowering their own electricity bills and potentially reducing systemwide costs if utilities can defer capital investment that would otherwise have been needed to meet peak demand. Time-varying rates can be structured in several different ways, including establishing seasonal rates in advance or dynamically varying pricing through critical-peak pricing or real-time pricing. Ultimately, the impact of time-varying rates can be maximized when customers have technology like smart thermostats, battery storage, and advanced metering, which allow them to easily respond to varying prices and alter their electricity consumption. The deployment of [electric vehicles](https://www.brattle.com/wp-content/uploads/2023/07/Time-Varying-Rates-are-Moving-from-the-Periphery-to-the-Mainstream-of-Electricity-Pricing-for-Residential-Customers-in-the-United-States.pdf) presents another opportunity to expand the impact of time-varying rates on affordability, as customers and utilities can benefit substantially by charging during off-peak periods. ### Real-World Examples These state examples illustrate how states have put the policy into practice, highlighting different design approaches. **Michigan — Michigan Implementation** [Michigan](https://www.michigan.gov/mpsc/commission/workgroups/mi-power-grid/time-based-pricing) established default or opt-out time-varying rates for [DTE Energy](https://www.dteenergy.com/us/en/residential/service-request/pricing/rate-options/residential-pricing-options.html) and [Consumers Energy](https://www.consumersenergy.com/residential/account-and-billing/rates/electric-rates-and-programs/rate-plan-options/smart-hours). The time-varying rate structures include time-of-use, seasonal, and critical-peak pricing. **Missouri — Missouri Implementation** [Missouri](https://www.missouribusinessalert.com/industries/energy/missouri-utility-companies-are-moving-to-time-of-use-rates-here-s-why/article_3bd0d7fe-79cc-11ee-ae84-b7c1de2caecd.html) requires its investor-owned utilities to offer default or opt-out time-varying rates. **Maryland — Maryland Implementation** In Maryland, [Baltimore Gas and Electric](https://blog.advancedenergyunited.org/behavioral-demand-response-gives-baltimore-gas-and-electric-a-business-reason-to-reduce-peak-usage) operates a default or opt-out peak time rebate program where customers do not pay a higher price for electricity during peak periods but instead receive a bill credit for reducing their electricity consumption during these times. **Oklahoma — Oklahoma Gas & Electric Implementation** [Oklahoma Gas & Electric](https://www.oge.com/wps/portal/ord/residential/pricing-options/smart-hours/!ut/p/z1/lZDNDoIwEISfhSfo0NaKxxqQVk1KjRTsxXAiJIoejM9vryD-sLdNvtnZGeJJTXzfPLu2eXS3vrmE_eTFmapUqG0Ok5gDh13HjG5SxYyOSTUEjJMZLOPJstgfAQjiZ-lzu1sEPTLpOGcA-0-PDyMx0_8d8N_PV8SPLJxMQwIhjF4VFDIeAxMVDYGJDn59cb-WZVmj020UvQDYS5Sq/dz/d5/L2dBISEvZ0FBIS9nQSEh/) uses opt-in time-of-use and variable-peak pricing rates, which originated from a [Department of Energy Smart Grid Investment Grant](https://eta-publications.lbl.gov/sites/default/files/sein_rate_design_trends_report_final_doe_approved.pdf) the utility was awarded in 2010. ### Further Reading - [A Strategic Framework for Utility Cost Control](https://rmi.org/insight/a-strategic-framework-for-utility-cost-control/) — RMI (2025) - [Moving Ahead with Time of Use Rates](https://www.publicpower.org/resource/moving-ahead-with-time-use-rates) — American Public Power Association (n.d.) - [Time-Varying Rates are moving from the periphery to the mainstream of electricity pricing for residential customers in the United States](https://www.brattle.com/wp-content/uploads/2023/07/Time-Varying-Rates-TVRs-Are-Moving-from-the-Periphery-to-the-Mainstream-of-Electricity-Pricing-for-Residential-Customers-in-the-United-States.pdf) — Brattle Group (2023) - [A Review of Alternative Rate Designs](https://rmi.org/insight/review-alternative-rate-designs/) — RMI (2016) - [The use of price-based demand response as a resource in electricity system planning](https://emp.lbl.gov/publications/use-price-based-demand-response) — Lawrence Berkeley National Laboratory (2023) ---