Integrating Gas Planning to Modernize Buildings

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Elaine Prause, Camille Kadoch, Megan Anderson, David Farnsworth, Richard Sedano, Richard Cowart and Nancy Seidman, RAP

Regulatory and utility involvement in building modernization is split into two parts in this toolkit: electrification regulatory provisions and gas regulatory provisions. This part focuses on regulatory actions to improve gas planning, gas and electric utility coordination, and planning for increased electrification that affects gas infrastructure decisions, including clean heat standards. The Electrification part of the toolkit focuses on electrification actions carried out by either electric or gas utilities.

Global energy systems are in a period of rapid transition,¹ causing policymakers, utilities and consumers to rethink how to meet heating, cooling, cooking and other residential, commercial and industrial energy needs. Individuals and businesses rely on energy services to thrive and survive, including monopoly services that are overseen by government. Consequently, decision-makers are trying to understand the diverse and dynamic forces that are causing changes in how we have historically utilized and regulated energy resources and how they might change these approaches based upon new information. Contemplating changes to legacy systems is always difficult, and the fossil gas² industry is no different in this regard. Some jurisdictions are considering limiting gas service distribution system expansion, given climate concerns. Others are seeking to support electrification to provide consumers options for their heating, cooling and cooking needs and to support new market entrants. And others are considering long-term cost impacts on customers and are seeking to diversify the portfolio of resources available to meet heating, cooking, cooling and other needs. By taking a risk-aware approach, policymakers can strengthen solutions to address these changing dynamics.

While the transition has broad implications on gas usage, several issues and trends are impacting gas distribution utilities that serve residential and commercial customers now. These include:

More efficient gas appliances and tighter building shells are lowering per-customer demand, changing the cost-effectiveness of typical gas delivery infrastructure.
Electric end-use equipment, such as heat pumps and induction cooktops, is declining in price, increasing in efficiency and improving in quality. Consequently, for end uses for which a choice exists, consumers are increasingly opting for electric rather than gas.
Some states are adopting increasingly stringent economywide greenhouse gas emissions policies and requiring significant reductions in the combustion of fossil gas.
Greater awareness of the safety and public health risks caused by gas, from extraction to its use in homes, is raising levels of consumer concern.³
Policy support is growing for alternative gases with potentially lower greenhouse gas impacts, such as renewable methanerenewable methane Biogas that has been upgraded for use in place of fossil natural gas. The principal constituents of the biogas are methane and carbon dioxide. Renewable natural gas projects capture and recover methane produced at a landfill or anaerobic digestion facility. (U.S. Environmental Protection Agency)./recovered methanerecovered methane Biomethane; also can refer to methane that would have leaked from the pipeline gas system if not for repairs. or green hydrogengreen hydrogen Hydrogen created using energy from a renewable source such as solar, wind or geothermal. (RMI).⁴
Aging gas utility distribution systems may cause utilities to seek approval for major investments at the same time that gas companies’ customer base is poised to shrink. These trends may lead to unsustainable rate increases on remaining customers, likely imposing high costs on those who can least afford it. Consequently, there will be new challenges to investment plans that would have been easily approved until now.
There are an increasing number of incentive programs for home electrification, offered through states and utilities but also through the federal Inflation Reduction Act.

In light of these factors, decision-makers in many jurisdictions are looking at options to mitigate risks to the public and utility customers and to advance policy goals. The options in this part of the toolkit are examples of actions states are taking on this issue, with a focus on three key areas:

Experience with other transitions indicates that early planning decreases costs, provides valuable certainty to businesses and enables a wider choice of options than actions taken later.

Enabling regulation in the public interest

The term “public interest” originates from the early 1900s, with New York and Wisconsin establishing the first state commissions with full regulatory powers over electric utilities in 1907.⁵ Since then, state regulation over the utility sector has evolved. By the 1950s, state legislation over public utility commissions was traditionally limited to five areas, and these generally remain the core functions of commissions today:

Controlling market entry and exit, including the granting of certificates of public convenience and necessity for new energy facilities and infrastructure.
Pricing, with the goal of setting “just and reasonable” rates to align consumer interests for reasonable rates with utility interests in seeking a reasonable rate of return on their investments.
Setting minimum standards for quality and safety of service, including the provision of continual service 24 hours a day.
Assuring nondiscriminatory service, which requires utilities to serve all customers who are able to pay in a service territory.
Preventing undue financial risk for utilities, which originally included barring utilities from financing nonutility investments.⁶

These five areas focus almost exclusively on economic and pricing concerns. Consequently, regulators have not uniformly considered the public interest or taken into account changing societal circumstances, including the climate emergency, or systemic racism and other forms of energy injustice.⁷

In 2022, a roundtable made up of stakeholders and five gas utilities recognized the barriers that gas companies face. The roundtable recommended that policymakers “consider updating the legal definition of the ‘public interest’ and the regulatory framework to align with climate and equity goals to incent and reward new utility business models and investments. In many cases, the definition of the public interest is unclear and may not adequately include climate, health, or equity goals, posing a barrier to utilities seeking to act in support of these policy goals.”⁸

Improving Planning Through Integration

Customers want reliable and fairly priced energy services. Decades of experience indicate that prescient planning on the part of regulators, utilities and stakeholders helps to deliver reliable energy service at a fair price. Early planning can enable consideration of a greater variety of options to allow for a reliable, efficient and equitable system that can be achieved at lower cost. By contrast, planning that happens in an emergency usually allows for fewer options and may only be able to respond to the need at hand, rather than improving the system overall. As a result, such planning often results in higher short- and long-term costs.

The decision-making tools and processes that underlie regulation of today’s gas distribution utilities have not been directly coordinated with other fuel system planning. As a result, energy regulators are unable to quantify a range of potential long-term risks and benefits so that consumers, utilities and regulators are able to identify optimal solutions. Specifically, energy regulators often do not have models of long-term planning assumptions — such as a decline in customer demand and the availability of alternate gas supply and delivery capabilities — for gas systems in the same way they do for electric systems. And the electric and gas planning assumptions are not integrated. The result is that it is more difficult for regulators to determine whether proposed utility investments are in the public interest, or if spreading those costs over fewer future customers will lead to unaffordable services when less costly options to meet people’s needs were possible.

To make confident regulatory decisions, regulators will need to ensure that many important questions facing our energy systems are answered within gas utility planning. These questions include the following:

How are gas utilities intending to meet short- and long-term system adequacy needs? How are impacts to the electric utility system from gas utility decisions being addressed in the public interest?

Different regions of the United States are facing existing or growing gas and electric system adequacy constraints during winter and summer peak use periods. In the East, shortages in interstate gas pipeline capacity are limiting gas utility growth. Projections for fuel switching from gas to electric are raising concerns about the cost to the electric system of handling very large increases in load. Are these valid concerns or can they be addressed with demand management or other solutions?

How are gas utilities considering potential reduction in the number of customers and overall usage?

Customer adoption of new efficient electric technologies is projected to cause a decline in gas use. As Figure 1 illustrates, air-source heat pump adoption is increasing nationwide.⁹ Some states are working to accelerate decarbonization of their energy use by supporting the growth of renewable energy, efficiency and reduction in fossil gas use.¹⁰

Figure 1. Share of U.S. households with primary electric heat pumps

Source: Strauss, Z. (2022, August 12). U.S. Policy Approaches to Support EU Energy Sector Diversification, citing U.S. Energy Information Administration

What actions or investments will utilities need to take to meet climate targets in the public interest?

Within the past two years many states have passed or begun considering legislation to reduce greenhouse gas emissions significantly by 2050. These new climate policies commonly set a trajectory of declining emissions limits for gas distribution and electric utilities, aligned with their larger state goals for emissions reductions by 2030 and 2050.¹¹

Utilities in these states may now be tasked with planning how they will comply with these future emissions limits. Even if the utilities are not legally obligated to achieve emissions reductions, regulators may consider the risk to customers of future policies and requirements as impetus to require better planning. In either case, questions related to planning for future emissions reductions are arising that need to be considered in today’s investment decisions.

These planning changes in a few states may be a harbinger of industry changes in investment, regardless of state policy decisions. Investment practices of the past may not be applicable in the future. A public interest balancing test that factors in emerging risks is likely to become part of prudent investment review. Planning and investment efforts that provide a clear path to dramatic emissions reductions are likely to cost less while building the business apparatus necessary to support the energy transition in a sustained way. For example, new alternatives may make it appropriate to reconsider certain use cases, such as:

Low population density portions of the gas system.
A concentration of multifamily buildings with central heating systems approaching the end of useful life, as in a housing authority project.
Recovery of the cost of investments through rates via a rider for safety- and age-related investments.

A shared vision for gas utility long-term planning

In a collaborative roundtable process, several gas utilities and other stakeholders developed recommendations for gas utility decarbonization. The roundtable called for policymakers to develop an inclusive, comprehensive and iterative long-term planning process at the state level over a time horizon that is adequate for long-term infrastructure planning while engaging with communities to identify specific priorities and needs, particularly for communities with high energy burdens.¹²

Regulatory reform suggestions from this group include:

A process for cost recovery of expenditures in line with state policy goals and clear evaluation criteria for alternatives to traditional infrastructure.
Potential consideration of performance-based regulation to support gas decarbonization.
Modified depreciation timelines for gas infrastructure.
Potential changes to gas utilities’ obligation to serve.
Gas rate redesign.
Securitizationsecuritization A refinancing mechanism involving the issuance of bonds to raise funds to refinance the remaining undepreciated value of existing utility assets, which could include power plants. The bonds are paid back through a surcharge on customer bills. Therefore, the utility can generally refinance the outstanding undepreciated value with 100% securitization financing instead of using its standard combination of debt and equity financing. (2020 North Carolina Energy Regulatory Process) and different accounting treatments for noncapital investments.
Geographic targeting of specific decarbonization and infrastructure solutions, while considering environmental justice and equity.

Gas Planning Policy Evolution

Electric utility planning has evolved markedly over the past decades as new technologies, increasingly complex policies and changing customer expectations have led to an expansion of analysis and projections. Gas utility planning, particularly distribution planning, has experienced a comparatively steady industry landscape. Consequently, gas utility planning in most states currently consists of planning for immediate delivery needs in the distribution system, adequacy of supply and anticipated infrastructure needs to ensure safety and meet load and system growth.

Current planning doesn’t enable regulators to forecast customer needs and identify the least-cost resources to fulfill policy requirements. Nor does it support consideration of risks and uncertainties; emissions limits and other state policies; the impacts of electrification; or assumptions about the future cost, availability and magnitude of alternative fuel options.¹³ Consequently, some states are relying on insights from the electric sector and requiring integrated resource planning (IRP) for gas utilities. In the IRP process, utilities use modeling to compare various portfolios of resource options to arrive at the investment plan with the least cost and risk. This is an important first step to add analytical rigor and a longer-term perspective to gas planning.

Gas system planning in isolation from the overall energy sector will, however, not produce the information and insight that government, regulated companies, customers and support businesses need to make prudent long-term investment decisions. Consequently, while states adopt, update and expand gas IRP practices, decision-makers will need to consider how to place future gas planning within the context of energy system transition to ensure that it evolves as a tool to inform state policy for future uncertainties.

New and more integrated gas planning processes will be increasingly important, particularly for states concerned about decarbonization and stranded assetsstranded assets Investments that are no longer used by ratepayers but for which utilities have not yet recovered the cost.. Several types of planning will be useful to address the changing role of gas:

Integrated distribution planning, which can help to ensure that changes on the distribution side are taken into account in system planning.
Integrated gas planning, which links decision-making across IRP and integrated distribution planning activities.
Combined energy planning, which creates consistency and coordination in planning across the gas and electric sectors.

Currently, most of these planning processes are nascent for gas systems, and no state has fully implemented combined energy planning. Figure 2 shows the increasing levels of integration within and between energy systems in the progression from existing planning practices to combined energy planning.

Figure 2. Energy planning continuum

Gas Integrated Resource Planning

Some states are considering updating gas utility planning processes. In more than half of U.S. states, regulated electric utilities have many years of experience with integrated resource planning. With the IRP process, they are using modeling tools to compare a variety of portfolios of resource options to arrive at the investment plan with the least cost and risk given a wide number of future uncertainties. Currently, IRP is not widely adopted for gas utility systems, but more states are exploring implementation of gas IRP or a similar planning process. Critically, whereas older integrated resource plans focused on business-as-usual assumptions for the use of electric and gas, new processes need to focus on integrated planning and assumptions for gas and electric based upon projections aligned with a jurisdiction’s public policy goals.

IRP is an established power sector planning process to develop a utility plan for meeting forecasted annual demand reliably through a combination of supply- and demand-side resources over a period of time (e.g., 20 years or through 2050). It can provide the necessary level of transparency, rigor and decision support analysis that regulators need to mitigate risks and uncertainties for customers, and it has a proven history of avoiding costly investment mistakes.¹⁴

Integrating equity in the resource planning process

According to the Partnership for Southern Equity, equity means creating the conditions that enable just and fair inclusion into a society in which all can participate, prosper and reach their full potential.¹⁵ By this definition, any planning process must enable just and fair inclusion. Many states are recognizing that existing processes may not be inclusive enough and are amending processes. (See Access to Decision-Making in this toolkit.) The resource planning process can provide an opportunity to enable just and fair inclusion and address equity concerns. By formally integrating the priorities of the communities it serves, a utility resource plan can be an avenue to address historic inequities in communities and mitigate energy burden. These are precisely the important points of view that local governments and other advocates can bring to IRP proceedings to achieve more equitable outcomes. Opportunities to integrate overburdened communitiesoverburdened communities “Minority, low-income, tribal, or indigenous populations or geographic locations in the United States that potentially experience disproportionate environmental harms and risks. This disproportionality can be as a result of greater vulnerability to environmental hazards, lack of opportunity for public participation, or other factors” (U.S. Environmental Protection Agency). Largely synonymous terms include “marginalized,” “front-line,” “underserved” and “environmental justice” communities. and address equity concerns are included throughout this part and the rest of the legislative toolkit, but it is underscored here to highlight that integrated planning processes are particularly important areas to incorporate equitable outcomes.

Fundamental steps of gas IRP include:

Forecasting a range of future loads and scenario designs (see step 4).
Identifying potential resource options to meet those future loads reliably and safely, including demand-side and alternative supply options and potential for beneficial electrificationbeneficial electrification Electrification that saves customers money, enables better grid management and reduces negative environmental impacts..
Determining the optimal mix or “preferred portfolio” of supply- and demand-side resources based on the goal of minimizing future gas system costs while considering risks and uncertainties and achievement of all policy mandates.
Using scenario analysis and stochastic¹⁶ analysis or sensitivities to test portfolio performance with uncertainties (e.g., start with business as usual compared with moderate policy motivations to accelerate load reduction and then more aggressive load reduction trajectories tied to 2030 or 2050 emissions reduction goals).
Receiving, responding to and incorporating public input throughout through open, transparent and iterative stakeholder processes that include stakeholders reflecting the needs of overburdened energy customers.
Creating and implementing the resource plan.

IRP provides a familiar framework within which policy, technology and forecasting uncertainties can be studied and explored, and resource portfolios can be tested to see how well they meet customer needs across a range of outcomes. Updating gas integrated resource plans that may exist from the 1990s, or implementing new gas IRP, will enable states to update critical planning processes.

Integrated Distribution Planning

IRP can provide regulatory transparency into long-term (greater than 10 year) planning decisions of major transmission and energy supply projects. Nearer-term (five to 10 years) and granular distribution planning from the utility to the customer site is often less transparent. As the energy system is becoming more integrated across both the gas and electricity sectors, and as demand response has a greater role in determining supply needs, insight into the distribution system is also now needed. Requiring utilities to provide more granular detail that illustrates and describes the current system and plans for additional infrastructure will allow regulators and stakeholders to understand the system more fully.

By seeing where there are system needs or opportunities — such as pipeline infrastructure upgrades, maintenance and expansion cost recovery requests — before those requests appear in rate cases, regulators and stakeholders can identify opportunities and solutions that reflect the more integrated and dynamic system that is needed. Implications of fuel switching through changes to load and customer numbers can be tested through scenarios. Other location-specific planning — including evaluation of nonpipeline alternatives for constrained system locations — can be tested and made more transparent to stakeholders.

Fuel switching, which simply means changing fuel sources to save money and reduce emissions, has been part of utility energy efficiency programs for decades. Currently, consumers usually make fuel-switching decisions based upon cost considerations. Policy can encourage fuel switching in the public interest through government incentives and tax credits for electrified end uses, like heat pumps, to increase system efficiency and decrease emissions. (See Funding and Finance in this toolkit.)

New York and Ontario, Canada, are starting to require more integrated distribution system planning, including robust IRP for gas utilities.¹⁷ However, many efforts still focus distribution system planning on electric utilities only.¹⁸

Integrated Gas Planning

Linking gas IRP with integrated distribution planning activities and aligning the time frames yields integrated gas planning, which helps decision-makers make better planning decisions. The modeling tools needed for IRP and integrated distribution planning analysis may need to remain separate to fulfill their objectives for utilities and regulators. Tight coordination of underlying assumptions between the two, however, essentially creates one planning framework for regulators to see the interconnected system view over the long term. Together, IRP and integrated distribution planning enable this broad approach to gas system planning.

This linkage is important to understand the impacts of factors affecting the gas system that fall between the 20-year horizon of IRP and the five-year horizon of integrated distribution planning. The potential for declining sales and the resulting impacts on system pressure and reliability need to be assessed beyond five years out to arrive at the optimal path to modify or prune the system at the least cost and risk. The resource options of beneficial electrification and blending hydrogen or alternative gases (e.g., renewable natural gasrenewable natural gas Biogas that has been upgraded for use in place of fossil natural gas. The principal constituents of the biogas are methane and carbon dioxide. Renewable natural gas projects capture and recover methane produced at a landfill or anaerobic digestion facility. (U.S. Environmental Protection Agency).) with fossil gas have different cost and operational impacts for the gas distribution system and for customers. To consider and test the performance of these resource options and their cost and operations impacts, they need to be considered within granular modeling techniques over five to 20-plus years, something that is not typically analyzed today. Both gas IRP and integrated distribution planning enable decision-making to intentionally consider equity implications¹⁹ and all potential resource options. Ontario, Canada, for example, adopted a 10-year planning horizon for the new gas IRP process.²⁰

Combined Energy Planning

Future uncertainties related to the gas distribution utility sector are interrelated with changes in the electric and other fuel sectors. As a result, it is increasingly important for decision-makers to develop a strategy for coordinating planning assumptions across energy suppliers (gas, electric, propane, oil, etc.). In doing so, decision-makers can both further augment gas utility-specific planning processes and create pathways for system planning. After all, the public and energy consumers want service from regulated companies and oversight that provides for safe, reliable and least-cost service irrespective of the company providing it. While integrated planning focuses on a single utility for utility investment planning purposes, combined energy planning encompasses consideration of all energy sources and utilities for a state or region. The two types of planning need to inform each other and be aligned and consistent.

Combined energy planning enables consideration of the impacts of new state climate legislation, winter peak adequacy limitations for gas and electric systems and consumer adoption of efficient fuel-switching technologies. Such scope is necessary for full consideration of a state’s energy future. Combined energy planning would help decision-makers plan energy systems in the public interest while maintaining safe, reliable delivery of essential services and meeting policy goals. A critical first step is for decision-makers to develop a coordination strategy for planning assumptions across energy suppliers (gas, electric, propane, oil, etc.) to inform specific planning processes. If current siloed planning for gas and electric systems is not changed, business-as-usual planning may lead to an inefficient, overbuilt energy system where customers are left to carry the high cost burden of poor planning.

If coordinated strategy and planning assumptions across energy suppliers is not possible, a good first step is combined energy planning between utilities with shared customers through coordination of consistent major planning assumptions and scenario designs that include efficient fuel switching.

Key issues that can be addressed and assessed in combined energy planning include the following.

Equity: Understanding the cost, health and safety impacts of utility system changes on low-income and overburdened communities is critically important to enable better decision-making. Building this knowledge base will include understanding health impacts of heating fuels and direct consideration of the health benefits from reducing emissions of greenhouse gases and other pollutants — both from a societal perspective related to outdoor air quality and from improved indoor air quality.

Resource options: Reviewing resource options is important to every proceeding, including assessing the of when resources that involve fuel switching of end uses can be included in the least-cost and least-risk resource portfolio.

Agency coordination: Today more agencies are involved in this important planning work, including environmental quality, transportation and housing departments in addition to utility commissions, so the coordination of roles and responsibilities is important.

Risk of stranded assets: Many states are considering how to manage the risk of stranded infrastructure investments. If the number of gas system customers declines, system costs will be spread over fewer customers, potentially leading to higher rates for those remaining (absent regulatory measures to avoid this outcome). At a certain amount of reduced use, assets may no longer be considered used and useful. This risk is driving the underlying need to use planning techniques to guide incremental gas utility service investments in the public interest. An element of timing is also critical in this stranded asset calculation. Some areas may see the need for added capacity for a few years, after which peak gas loads are expected to decline due to climate policies or market forces. In such cases, energy efficiency, some electrification, demand management or targeted use of gas downstream of a distribution constraint may be more cost-effective than building an asset that may become stranded within a few years.

Motivating change: Regulatory options beyond planning

More effective and comprehensive planning would help utilities coordinate assumptions and effectively put electrification measures on par with gas supply options within gas utility planning. There are a few additional paths decision-makers may employ:

Regulators (potentially with legislative direction) could use performance incentive mechanisms to reward gas utilities for encouraging and implementing electrification measures that are in the public interest. Legislative options in this part of the toolkit reflect variations on this approach with cost recovery versus incentives.
Regulations or legislation could specifically clarify or expand regulatory authority to oversee multifuel or utility planning that would enable regulators to direct cooperation between electric and gas utilities in overlapping service areas in methods consistent with the public interest.
Regulators, likely requiring legislative direction, could direct a gas utility to support conversion of its service to zero carbon (including conversion to electric end uses, a heat-pump-driven district heat service or other method) if such conversion passes its public interest test.

Limiting Ratepayer Risk From Gas Infrastructure Investments

Historically, replacement of existing gas infrastructure lines or extension of gas lines to new customers hasn’t received extensive regulatory review if it fits within existing utility-forecasted need. Some states are taking a closer look at these assumptions, however, and reconsidering business-as-usual practices in light of the risk of declining system use and cost considerations of nongas resources, such as energy efficiency and electrification.

In areas with existing gas service, the utility delivers supply through distribution main pipelines to distribution service lines, which connect to customer meters. Maintaining reliable service delivery depends upon infrastructure condition, line pressure and capacity, which are all interrelated with customer demand. Infrastructure investments for system safety and to meet load growth include capital projects to upgrade and expand pipelines. Replacement programs are typically presented to regulators for approval of the cost with supporting justification for the timing and need for the investment. The most common replacement projects involve aging infrastructure, including bare or unprotected steel pipe or specific types of plastic service and main lines with elevated risk of brittleness failures. Such projects can span more than 10 years. The utility may recover the cost of these upgrades through rate riders, and the projects may receive less regulatory attention than utility costs that are reviewed in a revenue requirement case.²¹ However, the utility justification for these investments to improve safety and reliability may need renewed regulatory review against their cost and risks. Newly replaced infrastructure can have a lifespan of 40 or more years.

Utility system infrastructure expansion plans align with forecasted need so that the system is ready to provide service in anticipation of new demands from new development. Costs for service line extensions from pipeline mains to newly constructed homes and businesses are typically funded partly but not fully by the customer receiving service. Utilities propose expansion of main pipelines, storage and other system infrastructure, such as compressor stations to enable increased deliveries while sustaining safe and reliable service pressure to all customers. Regulators review utility justification for these investments to expand the system and maintain high-quality service.

Rethinking the costs and system benefits of gas line extensions

Every jurisdiction has rules that dictate the circumstances under which gas mains can be extended to provide service to new customers. Historically, additional gas (and electric) service benefited all customers by decreasing system costs, so it was considered fair for costs to be shared between new and existing customers. Given changing circumstances, there are two related issues that regulators may want to require gas utilities to reflect in updated calculations: lower assumed gas usage due to efficient appliances and a shorter assumed gas asset lifetime.²²

Some states are taking steps to factor the risk of declining system use and cost considerations into infrastructure investment prudence reviews at the utility commission. During these reviews, regulators analyze utility infrastructure investment plans, as well as projections for use of the utility system, and determine whether the assumptions and risks are prudent for customers. Decision-makers’ risk tolerance on the behalf of customers may not be as high as the utility’s or its shareholders’ risk tolerance. To ascertain risks more clearly, decision-makers could require analysis using different potential levels of decline in gas use due to electrification and any greenhouse gas requirements to test utility assumptions and the potential range of customer impacts. In light of these projections, states may consider applying greater scrutiny in prudence reviews of infrastructure investment to reflect the increased level of uncertainty and risk in load forecasts.

Some states are also shortening the amortization period for new gas infrastructure, recognizing that current factors will affect what infrastructure is used and useful well within the 40-year asset life.

States are also considering cost implications of all resources, including energy efficiency, electrification and other measures on the customer’s premises. New housing developments, which would ordinarily be served through a new line extension, may be served more cost-effectively through nonpipeline solutions. It is often less expensive — especially when considering both direct costs and the health and social costs of fossil fuel emissions — to support electrification for the new homes instead of expanding the capacity of the natural gas distribution network.²³

Adopting Clean Heat Standards to Improve Performance

Some states are trying a different approach and implementing clean heat standards, which are credit-based performance standards. Compliance is demonstrated by submitting clean energy credits to the agency overseeing the program. Clean energy credits can be earned by entities subject to the standard, but also by others who develop clean energy resources.

A clean heat standard is similar in concept to a renewable portfolio standard, which motivates investment and competition (or markets) by requiring electricity providers to replace coal- and gas-fired generation with wind, solar and other clean electricity generation. A clean heat standard replaces fuel oil, propane, and fossil gas heat with clean heat resources. These clean resources can include weatherization improvements, energy efficiency improvements, heat pumps, clean district energy and other verified low-carbon options, potentially including renewable methane, clean hydrogenclean hydrogen Hydrogen produced with zero or near-zero emissions. (US Department of Energy), biodiesel, renewable diesel and advanced wood heat.²⁴ Under a clean heat standard, obligated parties are required to serve their customers with gradually increasing percentages of low- or zero-carbon heat so that sales of fossil fuels are replaced by increasing amounts of clean energy.

As a performance standard, the clean heat standard influences reductions in carbon emissions differently than other measures such as a carbon price or carbon cap. The standard requires measured additions to the clean heat side of the ledger, replacing fossil fuel heat with clean heat.²⁵ The standard acts as a tool to help covered entities transition to a less carbon-intensive business model that complies with state greenhouse gas requirements. Rather than capping emissions, it requires the addition of clean resources, encouraging heating providers to transition to lower-carbon heat provision.

In some sectors, such as the industrial sector, it will be more difficult to substitute low-emitting heat sources. Therefore, the design of the clean heat standard may not require reductions in all end uses to the same degree or at the same pace. A clean heat standard also allows for credit trading and potentially other compliance flexibilities. Importantly, the standard can work alongside many other policies to reduce thermal emissions.²⁶

Clean heat and fuels standards in various states

Jurisdictions are considering greenhouse gas emissions of heating fuels in different ways.²⁷

In 2021, the Colorado Legislature adopted a clean heat standard requiring distribution gas utilities to reduce emissions by 4% by 2025 and 22% by 2030, using a variety of clean heat resources. These resources include renewable natural gas, electrification, efficiency and green hydrogen.²⁸
New York legislation requires all fuel oil sold for heating in the state to contain at least 5% biodiesel by 2022 and 10% by 2025.²⁹
Oregon created a goal for renewable natural gas for its pipeline gas system. The law requires the Oregon utility commission to encourage delivery of this fuel, with a goal of delivering 30% renewable natural gas by 2050.³⁰
The California Energy Commission is required by state law to assess the potential to reduce emissions from buildings by at least 40% below 1990 levels by 2030.³¹ The commission’s report concludes that efficiency and renewable natural gas alone are unlikely to meet that goal and that heat switching, especially to electric heat pumps, will be required.³²

The following are key decision points in the design of a clean heat standard.³³

Covered Entities and Responsible State Agency

The type of heating fuels used in buildings varies markedly across the United States. As shown in Figure 3,³⁴ in New England a variety of fuels provide heat for buildings, including fuel oil, propane, kerosene and fossil gas. In the Midwest, fossil gas is the predominant heating fuel. In the West, requirements on electric and gas utilities will affect most of the home heating fuels. In other regions, more expansive approaches are necessary.

Figure 3. Household primary heating fuel in 2021, by census region

Data source: U.S. Census Bureau. (n.d.). DP04: Selected Housing Characteristics

A clean heat standard can be applied on a competitively neutral basis across all fossil heating fuels, including delivered fuels (fuel oil, propane, kerosene and coal) and gaseous fuels delivered by pipelines and distribution networks (known as natural gas, fossil gas or pipeline gas.) The standard would apply to all substantial fossil fuel sales from any of these sources.

The following parties could be obligated by a clean heat standard:

All regulated investor-owned gas utilities. Note that electric utilities may not be obligated parties but can create and sell credits.
Pipeline delivery companies and liquified gas companies.
Anyone delivering fuels at the wholesale level.
Fossil fuel heat providers who are not any of the above listed parties, including competitive gas suppliers.

Other entities that may be considered include:

Large commercial properties above a set threshold of fuel usage (to prevent individual homeowners from facing an obligation).
Municipalities or municipal gas companies as obligated parties, perhaps with municipal electric companies having the option of creating and selling credits.
Landlords with real estate above a set threshold of square footage.
Other options that could be raised through public input.
Electricity suppliers.

Oversight authority could be given to any agency responsible for energy regulation or environmental protection. The best choice will depend on the relevant statutory authority, expertise and agency experience³⁵ and on the existing relationship of the agency with the covered entities. Of course, as with many other programs, cooperation among state agencies will be key. But ultimately, it is a best practice in most cases to give the responsibility to a single agency for purposes of clarity and simplicity. Both Vermont and Colorado give responsibility to the public utility commission. Other states are considering other agencies.

Baselines and Targets

Since the principal goal of a clean heat standard is to deliver emissions reductions, clean heat credits should be measured in terms of carbon dioxide equivalents or CO₂e, which would give credit for the carbon emissions avoided by the addition of a variety of clean heat solutions. Using CO₂e also allows a variety of clean heat options, including weatherization, heat pumps and biofuels, to be compared to count toward the target.³⁶

The main advantage of the clean heat standard is that it focuses on the provision of clean solutions to drive down consumption of fossil fuels. A key goal of the standard is to stimulate suppliers of clean heat alternatives to deliver clean heat solutions to their customers. A credit-based system must, however, take care to measure the right accomplishments. For example, a clean heat standard that requires installation of X number of heat pumps or weatherization of Y square feet of building space could be based on good estimates of the greenhouse gas results but would be measuring inputs rather than outputs (greenhouse gas reductions). Consequently, rigorous evaluation and regular recalibration of credit values based on actual measured performance of the clean heat solutions is important.

Comparing apples to apples: Life cycle carbon emissions

Measurement of credits, particularly across fuel types and electrification measures, requires a common method of comparison to ensure that the correct benefits are accurately counted.³⁷ Life cycle emissions are therefore critical to accurate accounting. Clean heat standards can require the comparison of fossil fuels with biofuels and other measures, such as heat pump installation. The combustion of biofuels typically produces the same amount of carbon dioxide emissions at the burner tip as combustion of the fossil fuels they are displacing. The difference is that biofuels can provide other greenhouse gas emissions reduction benefits — either eliminating emissions of other greenhouse gases or removing carbon dioxide from the atmosphere before they are burned. Programs should avoid giving excess credits for emissions impacts that are merely exported to another jurisdiction. Thus, clean heat credits for biofuels need to be based on their net effect on greenhouse gas emissions, including indirect effects. To estimate that net effect, one must compare the life cycle emissions of the fossil fuel avoided with the life cycle emissions of the cleaner fuel being used. The same logic can apply to the replacement of fossil fuel heat by electric heat pumps, using appropriate average emissions rates for the electricity that will be used to power the electric appliance. This logic applies to all creditable actions but is most appropriate for measures based on fuel substitutions, such as biofuels, advanced wood heat and electricity-driven heat.

The size of the annual obligation for those covered by this program is a critical decision since it sets the pace and trajectory of the emissions reductions from a clean heat standard.

Ongoing and periodic program review will be necessary to consider potential regulatory amendments. For example, based on evidence and after public input, it could be desirable to increase the future level of obligation, if credits are meaningfully oversupplied, or reduce it, subject to strict conditions, in response to serious, unavoidable technical problems, supply constraints and adverse market conditions.

Methods of Compliance

To a certain extent, how the clean heat standard is carried out will depend on the covered entities. For instance, Colorado’s standard covers distribution gas utilities. Utilities develop plans with the required information to demonstrate compliance, and the utility commission approves, denies or modifies the plans. Vermont’s model covers utilities but also dealers in delivered fuels, entities not regulated by the Public Utility Commission. Entities covered by the Vermont standard could participate in a market for clean heat credits or bank excess credits to meet future obligations.

If desired for public policy reasons, a state could require that covered entities meet a certain portion of their obligation with a designated technology. Such carve-outs for certain technologies, however, may not be necessary. Because the requirements of a clean heat standard can be met in multiple ways, allowing customers choices among clean heat resources (and flexibility for compliance entities) can avoid “picking winners” and allow a market for clean resources to develop. This approach also allows certain resource solutions to earn credits in the near term and other solutions to be adopted over the longer term.³⁸

Strategies Ensuring Greater Equity

A clean heat standard is an opportunity to focus building heating upgrades on the buildings and residents who most need it. Strategies ensuring equitable distribution of the benefits of clean heat should be built into the program design from the beginning.³⁹ Studies reveal that low-income populations spend a disproportionately high fraction of their income on household energy, despite consuming less energy overall.⁴⁰ Furthermore, low-income households and environmental justice communities often have the worst-performing building stock. Focusing on this fraction of the housing stock will make the greatest proportional contribution to reduced energy burdens, improved health outcomes and transitional equity. Building shell improvements and heating conversions will be necessary to improve this fraction of the housing stock, and because the private resources of occupants are limited, public policies are needed to make it happen.⁴¹

Legislative Options

Electrification and policy trends are causing decision-makers to think about how to manage decreasing needs for gas and ensure a transition that benefits the public. Concerns about the climate and increased awareness of the health and safety risks of gas are accelerating the transition to other sources of energy in some states. Other states are concerned about stranded assets and requiring shorter periods of amortization for new and existing capital costs to be collected in customer rates. Still other states are asking fossil gas and electric utilities, traditionally on separate planning tracks, to integrate planning processes so that regulators have a more complete picture of the energy profile in their state. The following legislative options show the broad array of approaches states are taking to fossil gas and are focused in three primary areas:

Improving Gas Planning Through Integration

Given the changes happening in the energy sphere and the need to ensure that utilities are minimizing costs in the context of these changes, decision-makers are interested in asking for more information from gas and electric utilities and requiring integrated planning between gas and electric utilities. The following planning provisions provide options that would allow regulators to ask gas utilities to provide more information and to develop long-term plans that consider the impact of electrification on the gas utility.⁴²

Option 1: Gas Integrated Resource Plans

H.B. 1084⁴³ was introduced, but not passed, in Washington state in 2022. As introduced, the bill would require gas companies to submit an integrated resource plan, which would function similarly to the IRPs commonly required of electric utilities. The gas utility filings would provide helpful information to the utility commission on planning projections. Any language provided in brackets below are optional additions or clarifications that were not present in the original bill.

Option 1 Provision: Gas Integrated Resource Plans

(a) Initiation of IRP:⁴⁴

(1) Commission lead:

(A) Not later than [date] the [public utility commission] shall initiate a proceeding to investigate, develop and adopt a framework for gas integrated resource plans for utilities with more than [x] customers by [date].

(B) Nothing in this act shall be construed as limiting the [public utility commission]’s existing authority to adopt or modify utility regulations — including any current or proposed gas planning processes prior to the new gas integrated resource planning framework described in this act becoming effective.

(C) To carry out its responsibilities under this act, the [public utility commission] shall be allocated additional annual funds of [amount]. In performing its responsibilities under this act, the [public utility commission] may select and engage outside consultants with experience in utility regulation.

(2) Utility lead:

(A) Each gas company has the responsibility to meet system demand with the least-cost and least-risk mix of energy supply, including: gas, [demand-side efficiency,] renewable fuels, electrification and conservation. In furtherance of that responsibility, each gas company must develop an integrated resource plan.

(b) At a minimum, an integrated resource plan developed under this section must include:

(1) A range of forecasts of future gas demand in firm and interruptible markets for each customer class. These forecasts must examine the effect of economic forces on the consumption of gas and address changes in natural gas end uses, including the size of the customer base or throughput to that customer base as a result of the number, type and efficiency of natural gas end-use appliances;

(2) An assessment of commercially available conservation and energy efficiency options, including load management, as well as an assessment of currently employed and new policies and programs needed to obtain the conservation and energy efficiency improvements;

(3) An assessment of gas supplies, including fossil gas and all commercially available forms of renewable natural gas;

(4) An assessment of the impact of the electrification of the building sector on gas demand forecasts. [The assessment shall be based upon projections from an electric utility in the gas utilities territory.];

(5) [An assessment of distributed energy resources that may be installed by the utility or the utility’s customers, including, but not limited to, energy storage, electric vehicles and photovoltaics. Any such assessment must include the effect of distributed energy resources on the utility’s load and operations.];

(6) An assessment of opportunities for using company-owned or contracted storage;

(7) An assessment of pipeline transmission capability and reliability [that must include, but is not limited to:

(A) Transmission, distribution and gas service infrastructure, including the length and diameter of pipelines, pipeline material and pipeline pressure. This description should include the condition of existing pipelines, the age and condition of the pipes and the presence of Aldyl-A pipe;

(B) Leakage rates (number of leaks per mile);

(D) Interconnects, gate stations, compressor stations and any storage facilities;

(E) Areas of constraint on or congestion in the system; and

(F) Areas where maintenance or replacement of existing infrastructure may be needed and an explanation for why these areas need attention, such as safety considerations, aging or damaged pipes];

(8) A comparative evaluation of the cost of natural gas purchasing strategies, electrification, storage options, delivery resources and improvements in energy efficiency using a consistent method to calculate cost-effectiveness;

(9) The integration of the demand forecasts and resource evaluations into a long-range integrated resource plan for at least the next 10 years, describing the analyses used and the recommended mix of supply- and demand-side resources that is designated to meet current and future needs at the lowest reasonable cost considering risks and uncertainties to the utility and its customers;

(10) A short-term plan outlining the specific actions to be taken by the utility in implementing the long-range integrated resource plan during each of the three years following submission;

(11) A report on the utility’s progress toward implementing the recommendations contained in its previously filed plan; and

(12) An assessment of current conditions, including:

(A) The economic, public health and environmental conditions within the utility’s service territory. These conditions are not restricted to the effects of utility actions, and the analysis must include relevant information from publicly available sources, including the cumulative impact analysis; and

(B) The energy and nonenergy benefits and burdens associated with the utility’s infrastructure and programs, including benefits and burdens caused by utility actions outside the utility’s service territory.

(c) The commission must establish, by rule or order, the schedule for each gas company regulated by the commission to file an integrated resource plan at least every [three][x] years. The gas company must provide a work plan for informal commission review no later than 12 months prior to the due date of the integrated resource plan.

(1) The work plan must outline the content of the integrated resource plan to be developed by the gas company and the method for assessing potential resources.

(2) The work plan must include [at least four][commission-convened][utility-convened] public participation workshops on the integrated resource plan process, including participation opportunities for vulnerable populations and highly impacted communities, as well as the gas company’s plans to mitigate barriers to participation. [Two of the public participation workshops must be located in disproportionately impacted communities served by the utility. Participation must be open to the public and shall not be limited to parties represented by an attorney.]

(d) The commission must hear comment on an integrated resource plan developed under this section at a public hearing.

(e) The commission shall require data to be available throughout the process:

(1) To maximize transparency, the commission shall require a gas company regulated by the commission [to make data input files available in a native format and in an easily accessible format. The final integrated resource plan must be published either as part of an annual report or as a separate document available to the public. The report may be in an electronic form][to make the integrated resource plan and all related projections and models available on the utility’s website. If requests are made for a hard copy of the plan, projections and models, the utility shall comply within 30 days of receipt of request].

(2) Nothing in this subsection limits the protection of records containing commercial information under [cross-reference state statute on protected records].

(f) The commission must consider the information reported in the integrated resource plan when the commission evaluates the performance of the gas company in rate and other proceedings.

(g) This section [does][does not] apply to any gas company owned or operated by a city or town.

Options 2a and 2b: Joint Electric and Gas Planning

Joint utility planning allows for a coordination of underlying assumptions. Each utility or utility division (if a dual-fuel utility) would complete a transparent, individual IRP analysis to justify reasonable investments. These projected investments for electric and gas utilities would need to dovetail for shared customer energy needs and provide transparency about fuel-switching assumptions of each utility. This overlap enables the commission and other stakeholders to understand and evaluate coordinated investment planning to meet shared customer needs at the least cost and risk. Methods to implement joint planning include:

Requiring gas and electric utilities to merge data from both the gas and electric systems to develop one joint integrated resource and distribution system plan. A combined IRP will likely be easier to accomplish sooner with dual fuel utilities within a shared service territory.
Mandating that separate gas and electric utilities coordinate planning to arrive at one planning document. This outcome could be achieved through the use of an umbrella council, including stakeholders, that would develop the energy plan, informed by the gas and electric utilities.
Instructing separate gas and electric utilities to coordinate a joint filing or to file plans on a parallel timeline that cross-references information from the coupled plan.
Inserting a requirement in the planning process for utilities to engage and receive input from agencies with related planning processes during the stakeholder process, to coordinate planning meetings with stakeholders and the commission or to submit comments to the gas utility planning process that address overlap or concerns.

Utilities are frequently required by state legislation or regulation to undertake planning efforts that are then reviewed by state public utility commissions. Historically, most IRPs have focused on the electric sector only. A few states require gas IRPs, and no state requires joint gas and electric IRPs. Given the seismic changes in the energy sector, requiring gas utilities to articulate plans over a specified future horizon is prudent. Consequently, Options 2a and 2b show how a state could approach joint electric-gas planning. These options are based on H.B. 1084,⁴⁵ which was introduced, but not passed, in Washington state. H.B. 1084 focused exclusively on gas planning. Options 2a and 2b have been modified to include electric provisions.⁴⁶ These are provided as an example.

Option 2a Provision: Commission Investigation for Electric and Gas Planning

(a) By [date], the commission must open an investigation to evaluate pathways for electric and gas utilities to achieve their proportional share of greenhouse gas emissions reductions. The investigation should consider implications, findings and program adjustments, including, but not limited to:

(1) The impacts of increased electrification on the ability of electric utilities to deliver services to current natural gas customers reliably and affordably;

(2) The ability of electric utilities to procure and deliver electric power to reliably meet that load;

(3) The costs and benefits to residential and commercial customers, including environmental, health and economic benefits;

(4) Equity considerations and impacts to low-income customers and highly impacted communities;⁴⁷ and

(5) Potential regulatory policy changes to facilitate decarbonization of the services that gas companies provide while ensuring customer rates are fair, just, reasonable and sufficient.

(b) The investigation shall be completed by an independent expert hired by the commission, and shall include, but not be limited to:

(1) Considerations related to the continued safe operation of the electric and gas system, including assessment of current age and condition of gas system assets and pipes and cost of projected upgrades necessary to maintain existing service over the next [20 years][amortization period];

(2) Strategies to minimize costs and maximize benefits to customers, especially vulnerable populations and highly impacted communities, including targeted electrification and efficiency programs;

(3) [Positive and negative] health impacts of projected generation changes on the electric and gas system, including cost-benefit analysis of indoor and outdoor air quality impacts and avoidance of those impacts especially for low-income customers, vulnerable populations and highly impacted communities;

(4) Impacts of the changes in the electric and gas system on the infrastructure, supply needs and reliability of electric utilities;

(5) Impacts to customer classes, including residential, commercial, industrial, low-income and transportation customers;

(6) Regulatory changes to facilitate projected pathways;

(7) An economic assessment of strategies that allow gas companies to repurpose gas system infrastructure; and

(8) Any other information the commission requires.

(c) The commission shall [include][solicit input from] the following stakeholders in the investigation, including, but not limited to, [a representative from] the [state air agency], environmental groups, clean energy industry representatives, research organizations, consumer advocates, interested members of the public and disproportionately impacted communities, taking into account barriers to participation that may arise due to race, color, ethnicity, religion, income or education level.

(d) The commission may require utilities to undertake additional analysis as part of this investigation.

(e) The commission must report the results of the investigation under this section to the appropriate committees of the legislature by [date].

(f) Nothing in this section prevents the commission from considering updates to regulatory policies and practices to [facilitate a reduction in greenhouse gas emissions from gas companies][enact prudent regulatory decisions on current or future gas investments] before the completion of the investigation required under this section.

Option 2b Provision: Joint Electric and Gas Integrated Resource Planning

(a) Initiation of joint integrated resource planning:⁴⁸

(1) Commission lead:

(A) Not later than [date] the [public utility commission] shall initiate a proceeding to investigate, develop and adopt a framework for joint electric and gas integrated resource plan for utilities with more than [x] customers by [date].

(B) Nothing in this act shall be construed as limiting the [public utility commission]’s existing authority to adopt or modify utility regulations — including any current or proposed electric or gas planning processes prior to the new joint electric and gas integrated resource planning framework described in this act becoming effective.

(2) Utility lead:

(A) Each gas and electric utility or dual-fuel utility in the state has the responsibility to meet system demand with the least-cost and least-risk mix of energy supply, including: electrification, demand-side efficiency, distributed energy resources, natural gas, renewable fuels and delivery system investments [to ensure the utility provides energy to its customers that is clean, affordable, reliable and equitably distributed]. In furtherance of that responsibility, each [gas company][gas and electric company] must develop a [joint] integrated resource plan [with the electric or gas utility operating in their service territory].

(b) Requirements: At a minimum, an integrated resource plan developed under this section must include:

(1) For electric utilities:

(A) An assessment of a wide range of commercially available generating and nonconventional resources, including ancillary service technologies on a consistent and comparable basis;

(B) An assessment of methods, commercially available technologies or facilities for integrating renewable resources, including, but not limited to, battery storage and pumped storage, and addressing overgeneration events, if applicable to the utility’s resource portfolio. The assessment may address ancillary services;

(C) An assessment of currently employed and potential policies and programs needed to obtain all cost-effective conservation, energy efficiency and flexible load;

(D) An assessment of distributed energy, energy efficiency and electrification resources that may be installed by the utility or the utility’s customers, including, but not limited to, energy storage, flexible load, electric vehicles, energy-efficient and electrified end uses, distributed generation and community renewable energy. Any such assessment must include the effect of distributed energy resources on the utility’s load and operations;

(E) A comparative evaluation of the costs of various options for meeting any applicable greenhouse gas reduction goals, including all applicable supply- and demand-side options;

(F) An assessment of the impact of [the electrification of the building sector][electrification of end uses, including space and water heat, and transportation]; and

(G) An assessment of the potential for building and end-use energy efficiency improvements to reduce the electric system costs of supplying new electrification load.

(2) For gas utilities:

(A) An assessment of gas supplies and cost, including fossil gas and all commercially available forms of biomethanebiomethane Biogas that has been upgraded for use in place of fossil natural gas. The principal constituents of the biogas are methane and carbon dioxide. Renewable natural gas projects capture and recover methane produced at a landfill or anaerobic digestion facility. (U.S. Environmental Protection Agency). or renewable natural gas. Assessments of biomethane gas shall include identification of sources of biogas and the life cycle greenhouse gas emissions profile of the proposed biomethane compared with fossil gas. Utility assessments shall include clear and publicly accessible data. Costs shall include incremental capital and operating and maintenance costs for any infrastructure needed to safely deliver identified gas supplies;

(B) An assessment of the impact to the gas utility and to the electric utility of [the electrification of the building sector][electrification of end uses, including space and water heat, and transportation];

(D) An assessment of pipeline transmission capability and reliability [that must include, but is not limited to:

(i) Transmission, distribution and gas service infrastructure, including the length and diameter of pipelines, pipeline material and pipeline pressure. This description should include the condition of existing pipelines, the age and condition of the pipes and the presence of Aldyl-A pipe;

(ii) Leakage rates (number of leaks per mile);

(iii) Depreciation status;

(iv) Interconnects, gate stations, compressor stations and any storage facilities;

(v) Areas of constraint on or congestion in the system; and

(vi) Areas where maintenance or replacement of existing infrastructure may be needed and an explanation for why these areas need attention, such as safety considerations, aging or damaged pipes];

(E) A comparative evaluation of the cost of gas purchasing strategies, electrification, storage options, delivery resources and improvements in energy efficiency using a consistent method to calculate cost-effectiveness; and

(F) An assessment of least-cost strategies for meeting service territory energy needs, considering all viable resource options.

(3) For joint electric and gas planning:

(A) A range of forecasts of future electricity and gas demand for each customer class that examines the effect of economic forces and state goals on the consumption of electric and gas and that addresses changes in the number, type and efficiency of end uses;

(B) Coordinated sharing between electric and gas utilities of electrification resource cost and potential assumptions for shared customer groups, coordinated and shared customer growth assumptions and shared customer bill impact analysis;

(C) The integration of the demand forecasts and resource evaluations into a long-range integrated resource plan, for at least the next 10 years, describing the analyses used and the recommended mix of supply- and demand-side resources that is designated to meet current and future needs at the lowest reasonable cost to the utility and its ratepayers;

(D) A short-term plan outlining the specific actions to be taken by the utility in implementing the long-range integrated resource plan during each of the three years following submission;

(E) A report on the utility’s progress toward implementing the recommendations contained in its previously filed plan; and

(F) An assessment of current conditions, including:

(i) The economic, public health and environmental conditions within the utility’s service territory. These conditions are not restricted to the effects of utility actions, and the analysis must include relevant information from publicly available sources, including the cumulative impact analysis developed by the department of health; and

(ii) The energy and nonenergy benefits and burdens associated with the utility’s infrastructure and programs, including benefits and burdens caused by utility actions outside the utility’s service territory.

(c) The commission must establish, by rule or order, the schedule for each utility regulated by the commission to file an integrated resource plan at least every [three][x] years.

(d) No later than 12 months prior to the due date of the first integrated resource plan, the commission shall facilitate creation of a work plan that outlines the content of the integrated resource plan to be developed by each utility and the method for assessing potential resources.

(e) Both the work plan and each utility integrated resource plan shall include a stakeholder engagement process, which shall include:

(1) Opportunities for dialogue and written comments, facilitated in a way that encourages representation from diverse stakeholders and ensures equitable opportunities for participation;

(2) Stakeholders including but not limited to: gas and electric utilities, local publicly owned electric utilities, environmental groups, consumer advocates, clean energy and energy efficiency industry representatives, research organizations, organized labor representatives, public health advocates, local communities and interested members of the public; and

(3) Commission actions to ensure that the process facilitates and includes participation by a broad range of stakeholders. The commission shall ensure that any utility financial models and related assumptions are made technically accessible to participating stakeholders at a time that allows stakeholders to utilize the models as part of the process.

(f) To maximize transparency, the commission shall require a gas company regulated by the commission to make data input files available on the utility website in an easily accessible format. The final integrated resource plan must be published either as part of an annual report or as a separate document available to the public on the utility website. The report may be in an electronic form. If requests are made for paper copies, the utility shall mail requests within 30 days of receipt of request, free of charge.

(1) Nothing in this subsection limits the protection of records containing commercial information [statutory cross-reference].

(g) The commission must consider the information reported in the integrated resource plan when the commission evaluates the performance of the electric or gas company in rate and other proceedings.

(h) The commission must approve, reject or modify the public utility’s plan, consistent with the public interest. The commission shall make findings on the record.⁴⁹

Limiting Ratepayer Risk From Gas Infrastructure Investments

The following options are from states concerned about upgrading or extending gas infrastructure in the context of declining gas usage. The provisions range from an outright ban on new gas territory to conditions on expansion designed to protect customers from stranded assets, including prohibition of cross-subsidization and requirements to examine least-cost options prior to approval of line extensions.

Option 3: New Customers Pay Full Cost of Line Extension

The history of gas line extensions dates back over a century in some jurisdictions. In general, gas utilities are obligated to provide the opportunity for customers to be connected to the utility system at reasonable prices, terms and conditions. There are many variations across jurisdictions that calculate how much new customers contribute to the cost of new gas lines. Many jurisdictions have also historically offered subsidies, which typically originated when utilities were in a declining cost industry, in which the addition of more customers led to reductions in the utility’s costs and rates, thereby benefiting both old and new customers. Changing costs may cause jurisdictions to revisit this justification for line extension subsidies.

Option 3, inspired by Washington H.B. 1084,⁵⁰ precludes cross-subsidization of line extensions for residential and commercial customers. It requires the new customers to cover the full cost of extending the new line rather than allowing the cost (or part of the cost) of the new service to be allocated among all gas customers. This reallocation of costs has the effect of more appropriately reflecting system cost to new users but still allows new line extensions. Note that it does not apply to new customers on an existing gas line but only to new line extensions for a new development or service area.

California has enacted a similar policy through a decision of the Public Utilities Commission to eliminate gas line extension allowances.⁵¹ In reaching the decision, the commission noted that “subsidizing natural gas line extensions is a vestige of the past. With California now seeking to phase out natural gas usage to decarbonize the building sector, it no longer makes sense for ratepayers to subsidize new natural gas infrastructure. This policy change will save ratepayers money, reduce [greenhouse gas] emissions, and improve indoor air quality as we reduce natural gas combustion in people’s homes and businesses.”⁵² The decision creates an application process for the commission to consider exceptional projects that may be deserving of continued natural gas extension subsidies. Eligible projects for an exception must demonstrate reduction in greenhouse gas emissions, be consistent with California’s climate goals and lack feasible alternatives to natural gas use, such as electrification.⁵³

Option 3 Provision: New Customers Pay Full Cost of Line Extension

(a) Beginning [date], each gas company tariff for line extensions for residential and commercial gas service must recover the full cost of the extension from the customer requesting service.

Options 4a and 4b: Limitation on New Gas Service

Legislation in Washington state is the basis of Options 4a⁵⁴ and 4b,⁵⁵ which preclude expansion of gas companies outside their existing service area, regardless of service class. Variations on this provision could be to limit expansion of new gas outside the service area for residential and commercial classes but not industrial, which may have fewer generation options that work for industrial needs.⁵⁶ The effect of this provision is to preclude expansion of new gas lines outside the service area, without affecting existing customers or gas service. Jurisdictions may choose to preclude new extensions completely or enable exceptions listed in Option 4b. For states concerned about rapid climate change considerations, this option would have longer-term carbon impacts rather than shorter term.

Option 4a Provision: Limitation on New Gas Service

(a) A gas company may not offer new service to any customer located outside the area it is authorized to provide service in as of [date].

Option 4b Provision: Limitation on New Gas Service With Exceptions

(a) A gas company may not offer new service to any customer located outside the area it is authorized to provide service in as of [date], unless the [public utility commission] finds that this extension of service:

(1) Is consistent with the gas company’s [relevant planning document such as integrated resource plan, clean heat standard, etc.];

(2) Does not result in a net increase in greenhouse gas emissions over the expected useful life of the gas service to be installed in the expanded area; and

(3) [Has been demonstrated by the utility to be a least-cost solution over the life of the expected extension using a societal discount rate and including the capital cost of infrastructure. The least-cost solution shall include comparison of extending the gas line inclusive of capital infrastructure costs with efficient electric heat⁵⁷ and any other comparisons the commission deems appropriate.]

(b) Gas companies are no longer required to provide gas to people and corporations who apply for gas service.

Option 5: Accelerated Depreciation for Gas Investments

Option 5 focuses on the depreciation period for new gas infrastructure. In general, depreciation periods for gas infrastructure or other investments should match the anticipated lifetime over which the assets will be used and useful. Tying the depreciation period to the projected useful life of the asset reduces the risk of stranded costsstranded costs Unrecovered utility costs for assets that ratepayers no longer use. and provides an appropriate estimate of the rate impacts required to recover costs from ratepayers. Longer depreciation periods reduce near-term rate impacts by stretching out the cost recovery, so an investment with a longer depreciation period may appear more palatable to gas customers. However, a shorter amortization period may provide less risk of stranded assets, particularly in states with greenhouse gas emissions reduction targets or in areas where electrified end uses are likely to result in reduced reliance on gas infrastructure.⁵⁸ In these states, the amortization period may be reduced to no more than 20 years to reduce the risk of stranded costs. These steps will also mitigate against potentially substantial adverse impacts on those customers left on the gas system as it shrinks, who are likely to be disproportionately low-income customers.

Option 5 Provision: Accelerated Depreciation for Gas Investments

(a) Beginning [date], each gas company amortization schedule for new residential or commercial natural gas capital investment, or retrofits that result in reconsideration of an amortization schedule, shall [not extend beyond 2040][be limited to 10 years]⁵⁹[be limited to the planned used and useful life of the capital investment not to [exceed 10 years][extend beyond 2040]].

Adopting Clean Heat Standards to Increase Performance

A clean heat standard is a new approach to decarbonizing heating fuels.⁶⁰ As of the date of publication of this toolkit, Colorado was the only state to enact such a standard statewide. Legislation introduced in Vermont in 2022, which did not become law, is highlighted here to illustrate alternative approaches to implementation. Many other states are actively considering a clean heat standard, which is a performance standard for delivered fossil fuels that is designed to motivate delivery companies to improve the climate performance of the product. The manner of improvement, whether fuel mixing or substitution or through fuel switching, is up to the regulated entity. As a result, implementation is likely to look different from place to place, but any clean heat standard would lead to lower greenhouse gas emissions from delivered fuels and frequently will also decrease costs long term.

Providing options for engaging fossil fuel companies

A clean heat standard can provide a policy framework to work with and transition business operations for fossil fuel delivery companies.⁶¹

Vermont Gas Systems sells, leases, installs and services heat pump water heaters for customers.
The Energy Co-op of Vermont originally sold fuel oil and kerosene but shifted to clean energy services, which now account for 40% of sales.

Options based on excerpts of the Vermont⁶² and Colorado legislation⁶³ are included below on key decision points to illustrate different approaches. The decision points include determining the covered entities and how the standard applies to them; establishing targets and baselines; and addressing how the standard will be used to focus on equity concerns.

Options for Covered Entities

As noted, the types of heating fuel available in a jurisdiction will have significant implications for the type of heat standard implemented. In Colorado, most heating fuel is supplied by natural gas distribution companies. In Vermont, by contrast, 60% of heating fuels are from petroleum products such as bottled, tank or LP gas; fuel oil; and kerosene. Consequently, the Colorado legislation focuses on regulated utilities, namely gas distribution utilities, and does not cover other heating fuels. Vermont’s bill, by virtue of the great percentage of heating fuels provided by companies other than utilities, applies more broadly to all heating fuel suppliers in the state.

Vermont

(a) Annual registration

(1) Each entity that sells heating fuel into or in [state] shall register annually with the [public utility commission] by an annual deadline established by the commission. The form and information required in the registration shall be determined by the commission and shall include all data necessary to establish annual requirements under this chapter. The commission shall use the information provided in the registration to determine whether the entity shall be considered an obligated party and the amount of its annual requirement.

(2) At a minimum, the commission shall require registration information to include the legal name, “doing business as” name if applicable, municipality, state, type of heating fuel sold and volume of sales of heating fuels into or in the state for final sale or consumption in [state] in the calendar year immediately preceding the calendar year in which the entity is registering with the commission.

(3) Each year, and not later than 30 days following the annual registration deadline established by the commission, the commission shall share complete registration information of obligated parties with the [state agencies in charge of natural resources and energy] for purposes of conducting the [state] greenhouse gas emissions inventory and forecast.

(4) The commission shall maintain, and update annually, a list of registered entities on its website that contains the required registration information, except that the public list shall not include heating fuel volumes reported.

(5) For any entity not registered, the first registration form shall be due 30 days after the first sale of heating fuel to a location in [state].

(6) Clean heat requirements shall transfer to entities that acquire an obligated party.

Colorado

(a) The [legislature] hereby declares that:

(1) The [legislature’s] intent in enacting this section is to implement a performance standard that will allow [state] gas utilities to use available tools, including energy efficiency, biomethane, hydrogen, recovered methane, beneficial electrification of customer end uses, cost-effective leak reductions on the utility’s distribution system as determined by the commission that exceeds state and federal requirements and other measures to achieve [greenhouse gas emissions reductions], cost-effectiveness and equity.

Options for Targets and Baselines

Setting targets and documenting baselines are important steps to show progress under a clean heat standard and are a common part of existing energy efficiency and renewable energy standards. Key considerations include the unit of measurement and the ambition of the target.

Measurement

Both Vermont and Colorado measure compliance in terms of carbon dioxide equivalent (CO₂e). Reporting metrics using CO₂e would give credit for the carbon dioxide emissions avoided by the addition of a variety of clean heat solutions. Using CO₂e also allows a variety of clean heat options — including weatherization, heat pumps and approved clean fuels — to be compared on a quantitative basis.⁶⁴

Because the clean heat standard would award credits for actions taken in the form of CO₂e avoided, it will be critical to establish standards to quantify the performance of different types of clean heat measures over time. This type of problem has been addressed in other performance-based systems, including energy efficiency programs and low-carbon fuel standards.

Energy efficiency programs have well-established protocols for quantifying the energy, capacity and environmental benefits of different types of efficiency measures, such as light bulbs, weatherization and appliance replacements. So-called deemed savings rates are based on field measurements and are updated over time. A clean heat standard would require a similar manual and a process to create it and update it over time.⁶⁵

Annual Obligation

The size of the annual obligation for those covered by this program is a critical decision since it sets the pace and trajectory of the emissions reductions from a clean heat standard. The Vermont legislative example requires the utility commission to set the target, which is required to be sufficient to meet the state’s greenhouse gas reduction goals. The Colorado legislation sets the amount of reductions by statute and requires separate accounting for carbon and methane reductions. Both statutes provide advance publication of the standards so that obligated entities may plan.

Ongoing and periodic program review will be necessary to ensure the achievement of program goals and to consider potential regulatory amendments. For example, on evidence and after public hearings, it could be desirable to increase the future obligation if credits are meaningfully oversupplied or to reduce it, subject to strict conditions, in response to serious, unavoidable technical problems, supply constraints and adverse market conditions.

Vermont

Clean heat standard compliance

(a) Required amounts

(1) The [public utility commission] shall establish the number of clean heat credits that each obligated party is required to retire each calendar year. The size of the annual requirement shall be set at a pace sufficient for [state’s] thermal sector to achieve life cycle carbon dioxide equivalent (CO2e) emissions reductions consistent with the requirements of [cross-reference state statute establishing carbon reduction goals] expressed as life cycle greenhouse gas emissions.

(2) Annual requirements shall be expressed as a percent of each obligated party’s contribution to the thermal sector’s life cycle CO2e emissions in the previous year with the annual percentages being the same for all parties. To ensure understanding among obligated parties, the commission shall, in a timely manner, publicly provide a description of the annual requirements in plain terms.

(3) The commission may adjust the annual requirements for good cause after notice and opportunity for public process. Good cause may include a shortage of clean heat credits or undue adverse financial impacts on particular customers or demographic segments. Any downward adjustment shall be allowed for only a short, temporary period.

(4) To support the ability of the obligated parties to plan for the future, the commission shall establish annual clean heat credit requirements for 10 years with the required amounts being updated so 10 years’ worth of requirements are always available. Every three years, the commission shall extend the requirements three years, assess emissions reductions achieved in the thermal sector, and, if necessary, revise the pace of clean heat credit requirements for future years to ensure that the thermal sector portion of the emission reduction requirements of [cross-reference state statute establishing carbon reduction goals].

Colorado

Clean heat targets

(a) The purpose of a clean heat plan is to achieve clean heat targets by reducing carbon dioxide and methane emissions from gas distribution utilities.

(b) A clean heat plan under this section must demonstrate that the gas distribution utility submitting the clean heat plan will achieve a reduction of carbon dioxide and methane emissions from the distribution and end-use combustion of gas.

(c) A gas distribution utility shall demonstrate compliance with this section by filing and obtaining commission approval of clean heat plans that meet clean heat targets calculated as follows: consistent with [relevant subsection] and as compared to a [date] baseline, a [4%][x%] reduction in greenhouse gas emissions in [year], of which not more than 1% can be from recovered methane; and a [x%] reduction in greenhouse gas emissions in [year], of which not more than [x%] can be from recovered methane.

(d) In calculating the baseline and projected emissions covered under a clean heat plan, a gas distribution utility must include the following:

(1) Methane leaked from the transportation and delivery of gas from the gas distribution and service pipelines from the city gate to customer end use;

(2) Carbon dioxide emissions resulting from the combustion of gas by residential, commercial, and industrial customers not otherwise subject to federal greenhouse gas emission reporting and excluding all transport customers; and

(3) Emissions of methane resulting from leakage from delivery of gas to other local distribution companies.

(e) All emissions are metric tons of carbon dioxide equivalent as reported to the federal Environmental Protection Agency pursuant to 40 CFR 98, either subpart W (methane) or subpart NN (carbon dioxide), or successor reporting requirements; except that the division shall use the AR-4 100-year global warming potential or any greater successor value determined by the federal Environmental Protection Agency.

(f) In calculating its clean heat target, a utility must show its baseline carbon dioxide emissions and methane emissions separately and must show that the total emissions reductions are projected to achieve the clean heat target. The final calculation demonstrating that the plan meets the clean heat target must be presented on a carbon dioxide equivalent basis.

(g) It is the policy of [state] to reduce the state’s greenhouse gas emissions, and therefore to count toward a gas distribution utility’s compliance with the emissions reduction goals, recovered methane under a clean heat plan must be represented by a recovered methane credit, issued subject to an approved recovered methane protocol, and delivered:

(1) To or within [state] through a dedicated pipeline; or

(2) Through a common carrier pipeline if the source of the recovered methane injects the recovered methane into a common carrier pipeline that physically flows within [state] or toward the end user in [state] for which the recovered methane was produced.

(h) To count toward a gas distribution utility’s compliance with the clean heat targets, the utility must quantify the actual methane reductions achieved by any leak repairs and the commission must find that the leak reductions are cost-effective. The commission may require the utility to evaluate nonpipelined alternatives.

Options for Methods of Compliance

Which entities are covered by the clean heat standard may also affect the method of compliance. In Colorado, the gas distribution utilities are required to receive commission approval for their clean heat plans, so the legislation articulates decision points for the commission on the clean heat plans. In Vermont, the Public Utility Commission would be charged with creating a tradeable clean heat credit, because many of the covered entities are not regulated in the same manner as utilities.

Vermont

Tradeable clean heat credits

(a) By rule or order, the [public utility commission] shall establish or adopt a system of tradeable clean heat credits that may be earned by reducing greenhouse gas emissions through the delivery of clean heat measures. While credit denominations may be in simple terms for public understanding and ease of use, the underlying value shall be based on units of carbon dioxide equivalent (CO2e). The system shall provide a process for the recognition, approval and monitoring of the clean heat credits. The [relevant state agency] shall perform the verification of clean heat credit claims and submit results of the verification and evaluation to the commission annually.

(b) Clean heat credits shall be based on the life cycle CO2e emissions reductions that result from the delivery of eligible clean heat measures to end-use customer locations into or in [state]. For clean heat measures that are installed, the value of the clean heat credits in each year shall be the life cycle CO2e emissions of the heating fuel avoided by the installation of the measure, minus the life cycle CO2e emissions of the energy that is used instead. Eligible clean heat measures delivered to or installed in [state] shall include:

(1) Thermal energy efficiency improvements and weatherization;

(2) The supply of sustainably sourced biofuels;

(3) Renewable natural gas;

(4) Green hydrogen;

(5) Cold-climate heat pumps and efficient electric appliances providing thermal end uses;

(6) Advanced wood heating; and

(7) Renewable energy-based district heating services.⁶⁶

(c) For pipeline renewable natural gas and other renewably generated natural gas substitutes to be eligible, an obligated party shall purchase renewable natural gas and its associated renewable attributes and demonstrate that it has secured a contractual pathway for the physical delivery of the gas from the point of injection into the pipeline to the obligated party’s delivery system.

(d) To promote certainty for obligated parties and clean heat providers, the commission shall, by rule or order, establish a schedule of life cycle emission rates for heating fuels and eligible clean heat measures. The schedule shall be based on transparent and accurate emissions accounting adapting the Argonne National Laboratory GREET Model, Intergovernmental Panel on Climate Change modeling or an alternative of comparable analytical rigor to achieve the thermal sector greenhouse gas emissions reductions necessary to meet the sector’s share of the requirements of [cross-reference state greenhouse gas target statute] to accurately account for emissions from biogenic and geologic sources and to deter substantial unintended harmful consequences. The schedule may be amended based upon changes in technology or evidence on emissions, but clean heat credits previously awarded shall not be adjusted retroactively.

(e) Clean heat credits shall be time-stamped for the year in which the clean heat measure is delivered as well as each subsequent year during which the measure produces emissions reductions. Only clean heat credits with the current year time stamp, and credits banked from previous years, shall be eligible to satisfy the current year obligation.

(f) Clean heat credits can be earned only in proportion to the deemed or measured thermal sector greenhouse gas emissions reductions achieved by a clean heat measure delivered in [state]. Other emissions offsets, wherever located, shall not be eligible measures.

Acquisition and retirement of credits

(a) All eligible clean heat measures that are delivered in [state] shall be eligible for clean heat credits and may be retired and count toward an obligated party’s emissions reduction obligations, regardless of who creates or delivers them and regardless of whether their creation or delivery was required by other state policies and programs. This includes individual initiatives, emissions reductions resulting from the state’s energy efficiency programs, the low-income weatherization program and the [renewable energy standard].

(b) The commission shall determine whether the total value of a clean heat credit for an installed measure shall be claimed in the year it is installed or whether the annual value of that credit shall be applied each year of the measure’s life.

(c) The commission shall determine whether to require a certain portion of clean heat credits be acquired each year from weatherization projects in order to further the state’s building efficiency goals. The commission shall recommend legislative changes, if needed, to accomplish this.

Registration system

(a) The commission shall create a registration system to lower administrative barriers to individuals and businesses seeking to register qualified actions eligible to earn clean heat credits and to facilitate the transfer of credits to obligated parties. The commission may hire a third-party consultant to evaluate, develop, implement, maintain and support a database or other means for tracking clean heat credits and compliance with the annual requirements of obligated parties.

(b) The system shall require entities to submit the following information to receive the credit: the location of the clean heat measure, whether the customer or tenant has a low or moderate income, the type of property where the clean heat measure was installed or sold, the type of clean heat measure and any other information as required by the commission.

Colorado

Submission of clean heat plans

(a) No later than [date], gas distribution utilities in [state][gas utilities with [number] customers] shall file with the commission an application for approval of a clean heat plan that demonstrates that the gas distribution utility will achieve the clean heat target established [in this bill][cross-reference state legislation]. [All other gas distribution utilities shall file applications for approval of clean heat plans no later than [date], that demonstrate, for each such gas distribution utility, it will achieve the clean heat target established [in this bill][cross-reference state legislation]].

(b) After complying with [cross-reference subsection], each gas distribution utility shall, as directed by the commission but not less often than every [number] years, file an additional clean heat plan that covers, at minimum, [number] years after the date of the filing.

(1) Demonstrate that the gas distribution utility will meet the applicable clean heat targets specified in this section for the applicable plan period; and

(2) Set forth portfolios that the gas distribution utility will use to demonstrate alternative compliance approaches for reducing carbon dioxide and methane emissions to meet the clean heat target in the applicable plan period, including its preferred option. The utility shall present:

(A) A portfolio of resources that uses clean heat resources to the maximum practicable extent, that complies with the cost cap, that may include leak reductions approved by the commission and that may or may not meet the clean heat target in the applicable plan period but that demonstrates reductions in methane emissions;

(B) A portfolio that meets the clean heat targets in the applicable plan period using only clean heat resources but that need not meet the cost cap;

(D) Other portfolios as directed by the commission;

(3) Quantify annual projected greenhouse gas emissions reductions during the applicable plan period resulting from each portfolio;

(4) Propose program budgets to meet the emissions reduction targets;

(5) Prioritize investments that ensure that disproportionately impacted communities or customers who meet requirements for income-qualified programs benefit from the investments made to implement the clean heat plan;

(6) Project annual greenhouse gas emissions reductions that would result if each proposed portfolio were extended through [year];

(7) Forecast carbon dioxide and methane emissions reductions that are consistent with the recovered methane protocol rules adopted by the [relevant state agency][cross-reference state statute];

(8) Quantify additional air quality, environmental and health benefits of the plan in addition to the greenhouse gas emissions reductions;

(9) Include a forecast of potential new customers and system growth or expansion of the gas system for the applicable plan period, including projected greenhouse gas emissions related to that growth;

(10) Describe the effects of the actions and investments in the clean heat plan on the safety, reliability and resilience of the gas distribution utility’s gas service;

(11) Quantify the cost of implementing the preferred portfolio of clean heat resources used to meet the clean heat targets through the clean heat plan, net of the avoided cost of any new delivery infrastructure avoided through implementing the plan;

(12) Identify potential changes to depreciation schedules or other actions to align the gas distribution utility’s cost recovery with statewide policy goals, including reducing carbon dioxide and methane emissions, minimizing costs and minimizing risks to customers;

(13) Explain the gas distribution utility’s analysis of the costs and benefits of an array of compliance alternatives, including the social cost of carbon and the social cost of methane in the cost-benefit calculations;

(14) Describe the monitoring and verification methodology to be used in annual reporting; and

(15) Include any other information required by the commission.

(d) To demonstrate compliance with the applicable clean heat target in a clean heat plan, a gas distribution utility must utilize clean heat resources to the maximum extent practicable and count greenhouse gas emissions reductions resulting from its use of those resources. For compliance with the [year] target, a utility shall not propose and the commission shall not approve recovered methane resources achieving more than [x%] of the target of [x%].

(1) Notwithstanding any other provision of this section, and unless the commission finds that a clean heat plan is not cost-effective in meeting the following targets of the emissions reductions required in a clean heat plan that a gas distribution utility must achieve, reductions from recovered methane projects may be in the following maximum amounts:

(A) [X%] of the total reduction for the period [year-year]; and

(B) An amount specified by the commission by rule for clean heat plans covering years after [year] if the commission determines that the requirements further investment in [state] communities, reduce greenhouse gas emissions, are cost-effective and are in the public interest.

(e) A clean heat plan may be filed as part of a demand-side management plan or any other plan as determined by the commission.

(f) A gas distribution utility may include proposals to make investments in green or blue hydrogenblue hydrogen Hydrogen produced from natural gas with carbon capture and storage. (MIT NEWS) projects that will reduce greenhouse gas emissions. If a gas distribution utility proposes to make an investment pursuant to this subsection, it must also include a proposal for competitive solicitation.

(g) The commission shall consult with the [environment or air agency] to estimate reductions of emissions of greenhouse gases and other air pollutants under the portfolios.

(1) The [environment or air agency] may participate as a party in any proceeding before the commission in which a gas distribution utility is seeking approval of a clean heat plan the gas distribution utility developed pursuant to this section.

(h) A gas distribution utility’s first clean heat plan must use a planning period that extends through [year]. The second clean heat plan must use a planning period that extends through [year]. Subsequent clean heat plans must use a planning period as determined by the commission

Commission rules

(a) No later than [date], the commission shall undertake a rule-making proceeding to update electric and gas demand-side management rules consistent with the clean heat targets established in this section. In the rule-making, the commission shall remove any prohibition on customer incentives to help customers replace gas appliances with highly efficient electric alternatives. As part of this rule-making process, the commission shall convene at least four workshops or public meetings to solicit input on the contents and evaluation of gas distribution utilities’ clean heat plans, two of which must be located in disproportionately impacted communities served by the utility that is required to submit a clean heat plan. Participation must be open to the public and shall not be limited to parties represented by an attorney.

(b) The commission shall adopt rules necessary for gas distribution utilities to implement clean heat plans by [date].

Options for Ensuring Greater Equity

Many states are taking steps to address historic inequities. According to a recent paper from Lawrence Berkeley National Laboratory, purposeful legislative and regulatory actions are needed to reverse the undeniable inequities that are baked into existing systems.⁶⁷

“Equity is a ‘proactive’ approach to differences in opportunities and burdens,” according to Chandra Farley, CEO of ReSolve.⁶⁸ A key step to ensuring greater equity is to enable meaningful participation in policy discussions by communities currently affected by energy policies, including clean energy, as well as civil rights and environmental justice groups.⁶⁹ The following provisions show the Vermont and Colorado approaches to improving access to utility commission proceedings and policy creation but also methods to address historic inequities by focusing on distribution of clean heat measures. For more on the important topic of equity, see Access to Decision-Making in this toolkit.

Vermont

Purpose: To meet the greenhouse gas emissions reductions required by the [relevant state statute], [state] needs to transition away from its current carbon-intensive building heating practices to lower-carbon alternatives. It also needs to do this equitably, recognizing economic effects on energy users, especially energy-burdened users; on the workforce currently providing these services; and on the overall economy.

(a) Equitable distribution of clean heat measures

(1) The clean heat standard shall be designed and implemented to enhance social equity by minimizing adverse impacts to low-income and moderate-income customers and those households with the highest energy burdens. The design shall ensure all customers have an equitable opportunity to participate in, and benefit from, clean heat measures regardless of heating fuel used, income level, geographic location or homeownership status.

(2) A substantial portion of clean heat credits retired by each obligated party shall be sourced from clean heat measures delivered to low-income and moderate-income customers. The portion of each obligated party’s required amount needed to satisfy the annual clean heat standard requirement shall be at least [16%][x%] from low-income customers and [16%][x%] from moderate income customers.⁷⁰ The definitions of low-income customer and moderate-income customer shall be set by the commission in consultation with the [clean heat standard equity advisory group] and in alignment with other existing definitions.

(3) The commission may consider frontloading the credit requirements for low-income and moderate-income customers so that the greatest proportion of clean heat measures reach low-income and moderate-income [state] residents in the earlier years.

(4) To best serve low-income and moderate-income customers, the commission shall have authority to change these portions and the criteria used to define low-income and moderate-income customers for good cause, after notice and opportunity for public process.

(5) In determining whether to exceed the minimum percentages of clean heat measures that must be delivered to low-income and moderate-income customers, the commission shall take into account participation in other government-sponsored low-income and moderate-income weatherization programs.

(6) A clean heat measure delivered to a customer qualifying for a government-sponsored, low-income energy subsidy shall qualify for clean heat credits required by paragraph (2) of this subsection.

Clean heat standard equity advisory group

(a) The commission shall establish the [clean heat standard equity advisory group] to assist the commission in developing and implementing the clean heat standard in a manner that ensures an equitable share of clean heat measures are delivered to low-income and moderate-income [state] residents and that low-income and moderate-income [state] residents who are not early participants in clean heat measures are not negatively impacted in their ability to afford heating fuel. Its duties shall include:

(1) Providing feedback to the commission on strategies for engaging low-income and moderate-income [state] residents in the public process around development of the clean heat standard;

(2) Supporting the commission in assessing whether customers are equitably served by clean heat measures and how to increase equity in this area;

(3) Identifying actions needed to provide better service to, and mitigate the fuel price impacts on, low-income and moderate-income customers;

(4) Recommending any additional programs, incentives or funding needed to support low-income and moderate-income customers and organizations that provide social services to [state] residents in affording heating fuel and other heating expenses; and

(5) Providing feedback to the commission on the impact of the clean heat standard on the everyday experience of low-income and moderate income [state] residents.

(b) The [clean heat standard equity advisory group] shall consist of up to 10 members appointed by the commission and at a minimum shall include at least one representative from each of the following groups:

(1) [Public utility commission];

(2) [Relevant state department for children and families];

(3) Community action agencies;

(4) [Any state third-party efficiency provider or office];

(5) Individuals with socioeconomically, racially and geographically diverse backgrounds; renters and rental property owners; and

(6) A member of the [organized fuel dealer association]. Members who are not otherwise compensated by their employer shall be entitled to per diem compensation and reimbursement for expenses under [relevant state statute].

Colorado

The following provisions in the Colorado legislation focus on equity issues.

(a) Purpose

(1) [State] is focused on a transition to [a decarbonized][an equitable][an] economy that recognizes the historic injustices that impact lower-income [state] residents and Black, Indigenous and other people of color who have borne a disproportionate share of environmental risks and costs while also enjoying fewer environmental benefits.

(2) The commission must maximize [greenhouse gas emissions reductions and] benefits to customers, with particular attention to residential customers who participate in income-qualified programs, while managing costs and risks to customers, including stranded-asset cost risks, and in a manner that supports family-sustaining jobs.

(b) Clean heat plan requirements on utilities

(1) Prioritize investments that ensure that disproportionately impacted communities or customers who meet requirements for income-qualified programs benefit from the investments made to implement the clean heat plan.

(1) As part of this rule-making process, the commission shall convene at least four workshops or public meetings to solicit input on the contents and evaluation of gas distribution utilities’ clean heat plans, two of which must be located in disproportionately impacted communities served by the utility that is required to submit a clean heat plan. Participation must be open to the public and shall not be limited to parties represented by an attorney.

(d) Commission approval of a clean heat plan is conditioned on:

(1) Whether investments in a clean heat plan prioritize serving customers participating in income-qualified programs and communities historically impacted by air pollution and other energy-related pollution.

(e) Reporting

(1) Each gas distribution utility shall submit to the commission an annual report that shows the amount of money that it has spent under each program in the clean heat plan, the amount spent on income-qualified programs or programs that serve communities historically impacted by air pollution and other energy-related pollution, a calculation of emissions reduced or avoided pursuant to its approved clean heat plan, and any other information required by the commission.

Additional Resources

Hill, M., Veilleux, N., & Strauss, Z. (2022, April 22). Trends in Residential Heat Pump Adoption in the United States. Atlas Buildings Hub. https://atlasbuildingshub.com/2022/04/22/trends-in-residential-heat-pump-adoption-in-the-united-states/

National Association of Regulatory Utility Commissioners. (2022). Comprehensive Electricity Planning Library. https://www.naruc.org/taskforce/comprehensive-electricity-planning-library/

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Endnotes

Anderson, M., LeBel, M., & Dupuy, M. (2021). Under pressure: Gas utility regulation for a time of transition. Regulatory Assistance Project. https://www.raponline.org/knowledge-center/under-pressure-gas-utility-regulation-for-a-time-of-transition/
Fossil gas is also known as natural gas or gas.
See, for example, Michanowicz, D. R., Dayalu, A., Nordgaard, C. L., Buonocore, J. J., Fairchild, M. W., Ackley, R., Schiff, J. E., Liu, A., Phillips, N. G., Schulman, A., Magavi, Z., & Spengler, J. D. (2022, June 28). Home is where the pipeline ends: Characterization of volatile organic compounds present in natural gas at the point of the residential end user. Environmental Science & Technology 56 (14): 10258–10268. https://doi.org/10.1021/acs.est.1c08298; and U.S. Energy Information Administration. (2022, November 7). Natural gas explained. https://www.eia.gov/energyexplained/natural-gas/natural-gas-and-the-environment.php
At this time, green hydrogen and renewable or recovered methane face significant economic, infrastructure and logistical hurdles. They also do not necessarily address key environmental, health and safety concerns, though they may be well suited to some hard-to-electrify sectors. For more information on advancements in this area see U.S. Department of Energy. (n.d.). Hydrogen program. https://www.hydrogen.energy.gov/
Farley, C., Howat, J., Bosco, J., Thakar, N., Wise, J., & Su, J. (2021). Advancing equity in utility regulation. Lawrence Berkeley National Laboratory. https://emp.lbl.gov/publications/advancing-equity-utility-regulation
Farley et al., 2021.
Farley et al., 2021.
The utilities were Exelon, National Grid, Pacific Gas & Electric Company, Southern Company Gas and Xcel Energy. RMI and National Grid. (2022). Collaborating for gas utility decarbonization. https://www.raponline.org/knowledge-center/collaborating-for-gas-utility-decarbonization/
Strauss, Z. (2022, August 12). U.S. policy approaches to support EU energy sector diversification. Atlas Buildings Hub. https://atlasbuildingshub.com/2022/08/12/u-s-policy-approaches-to-support-eu-energy-sector-diversification/, citing U.S. Energy Information Administration
American Council for an Energy-Efficient Economy. (2020, April). State policies and rules to enable beneficial electrification in buildings through fuel switching. https://www.aceee.org/sites/default/files/pdfs/fuel_switching_policy_brief_4-29-20.pdf
California, Colorado, Washington, Oregon, Massachusetts, New York and Vermont.
RMI & National Grid, 2022.
Prause, E. (2022). Modernizing gas utility planning: New approaches for new challenges. Regulatory Assistance Project. https://www.raponline.org/knowledge-center/modernizing-gas-utility-planning-new-approaches-new-challenges/
For example, in the 1970s, nuclear plants throughout the United States were planned based on overestimated load growth projections and underestimated new plant costs. By the next decade, the cost to ratepayers was estimated at $10 billion for projects that were eventually abandoned. U.S. Energy Information Administration. (1983). Nuclear plant cancellations: Causes, costs, and consequences. OSTI.gov. https://www.osti.gov/biblio/6211281/
Partnership for Southern Equity. (n.d.). Our methodology. https://psequity.org/about/#:~:text=(eq%C2%B7ui%C2%B7ty),and%20reach%20their%20full%20potential
“A stochastic process is any process describing the evolution in time of a random phenomenon.” Baudoin, F. (2010). Stochastic processes. International Encyclopedia of Education (3rd ed.), pp. 451-452. https://www.sciencedirect.com/science/article/pii/B9780080448947013695?via%3Dihub. Stochastic analysis is used in energy modeling to provide a range of possibilities with a lot of variables. For instance, finite amounts of storage, temperature and weather variability can affect utility projections on the amount of resources needed during a particular time frame.
Ontario, Canada, has developed an integrated resource planning framework for gas utilities that “evaluates and compares demand-side and supply-side alternatives to pipeline infrastructure in meeting natural gas system needs, and identifies and implements the alternative (or combination of alternatives) that is in the best interest” of the utility and its customers. Ontario Energy Board. (n.d.). Natural gas integrated resource planning (IRP). https://www.oeb.ca/consultations-and-projects/policy-initiatives-and-consultations/natural-gas-integrated-resource. New York recently adopted gas planning procedures meant to “modernize planning so that local gas distribution companies’ long-term plans are subjected to transparent review and ensure they conform to state policies while . . . providing safe and adequate service.” New York Public Service Commission. (2022, May 12). PSC begins groundbreaking planning process to reduce greenhouse gas emissions from the state’s natural gas delivery system [Press release]. https://dps.ny.gov/system/files/documents/2022/10/psc-begins-groundbreaking-planning-process-to-reduce-greenhouse-gas-emissions-from-the-states-natural-gas-delivery-system.pdf
See, for example, Mid-Atlantic Distributed Resources Initiative & Regulatory Assistance Project (Eds.). (2019). Integrated distribution planning for electric utilities: Guidance for public utility commissions. https://www.madrionline.org/wp-content/uploads/2019/10/MADRI_IDP_Final.pdf.
Duncan, J., Eagles, J., Farnsworth, D., Shenot, J., & Shipley, J. (2021). Participating in power: How to read and respond to integrated resource plans. Regulatory Assistance Project and Institute for Market Transformation. https://www.raponline.org/knowledge-center/participating-in-power-how-to-read-and-respond-to-integrated-resource-plans/
Ontario Energy Board, n.d.
Rate riders or adjustment clauses are used to change utility rates between general rate cases to account for changes in specific costs or changes in sales. These rate changes typically require little scrutiny by the regulator because the adjustments are governed by formulas and rules that were themselves fully evaluated.
Regulators will also need to determine how to allocate costs for the gas system in this changing environment and who should bear those costs.
Dupuy, M. (2021, November 1). It’s time to consider the (non-pipeline) alternatives. Regulatory Assistance Project. https://www.raponline.org/blog/its-time-to-consider-the-non-pipeline-alternatives/
Cowart, R., Seidman, N., & LeBel, M. (2022). A clean heat standard for Massachusetts. Regulatory Assistance Project. https://www.raponline.org/knowledge-center/clean-heat-standard-massachusetts/; and Cowart, R., & Neme, C. (2021). The clean heat standard. Regulatory Assistance Project and Energy Action Network. https://www.raponline.org/knowledge-center/the-clean-heat-standard/
Cowart et al., 2022.
Cowart et al., 2022.
Cowart & Neme, 2021.
An Act Concerning the Adoption of Programs by Gas Utilities to Reduce Greenhouse Gas Emission, S.B. 21-264, (Colo. 2021) (enacted). https://leg.Colorado.gov/sites/default/files/2021a_264_signed.pdf
Relates to Bioheating Fuel Requirements and Bioheating Fuel Tax Credits, A.B. A7290, 2021-2022 Leg. Sess. (N.Y. 2021) (enacted). https://www.nysenate.gov/legislation/bills/2021/A7290
Relating to Renewable Natural Gas, S.B. 98, 80th Leg. Assemb., 2019 Reg. Sess. (Ore. 2019) (enacted). https://olis.oregonlegislature.gov/liz/2019R1/Downloads/MeasureDocument/SB98/A-Engrossed
An Act to Add Section 25403 to the Public Resources Code, ch. 2 373, A.B. 3232, (Calif. 2018) (enacted). https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=201720180AB3232
Kenney, M., Janusch, N., Neumann, I., & Jaske, M. (2021). California building decarbonization assessment. California Energy Commission. https://www.energy.ca.gov/publications/2021/california-building-decarbonization-assessment
What follows is a high-level extraction of the information in Cowart et al., 2022. See also Cowart & Neme, 2021.
U.S. Census Bureau. (n.d.). DP04: Selected housing characteristics [Chart]. https://data.census.gov/table?q=Selected+housing&g=0200000US1,2,3,4&tid=ACSDP1Y2021.DP04&moe=false
Cowart et al., 2022.
Cowart et al., 2022.
The information in this text box is drawn from Cowart et al., 2022.
Cowart et al., 2022.
There is, on the surface, tension in program design between dedicating efficiency and heat-switching resources to consumers with the highest energy burdens versus maximizing early pollution reductions by focusing on the “quickest reductions from anywhere.” RAP recognizes that a just transition requires both justice and an effective transition, so multiple objectives must be served. We think it is equitable and ultimately cost-effective to provide clean heat solutions to the most energy-burdened households disproportionately earlier in the process than would be the case if the distribution of benefits were left to market forces alone. See Cowart et al., 2022.
Office of Energy Efficiency & Renewable Energy. (2018). Low-income household energy burden varies among states — efficiency can help in all of them. U.S. Department of Energy. https://www.energy.gov/sites/prod/files/2019/01/f58/WIP-Energy-Burden_final.pdf
Designating a certain percentage of the program spending to focus on low-income populations in a clean heat standard may be appropriate; however, equity concerns should not stop with a specific focus on populations to serve but also be considered holistically throughout the clean heat standard design.
For more background on the gas system operation and regulation, see the Appendix to Anderson et al., 2021.
An Act Relating to Reducing State Wide Greenhouse Gas Emissions by Achieving Greater Decarbonization of Residential and Commercial Buildings, H.B. 1084, 2021 Reg. Sess. (Wash. 2021). https://lawfilesext.leg.wa.gov/biennium/2021-22/Pdf/Bills/House%20Bills/1084-S.pdf
Legislation can either require the utility commission to open a proceeding to develop a gas IRP or require a utility to file a gas IRP. A commission-led proceeding may enable commission regulatory expertise and inclusion of stakeholders. Where this option is not feasible, a utility-led filing requirement may require explicit stakeholder input and enable the commission to adopt, modify or reject a utility proposal.
An Act Relating to Reducing State Wide Greenhouse Gas Emissions, H.B. 1084.
Integrated Resource Planning, WAC 480-90-238 (Wash.). https://apps.leg.wa.gov/wac/default.aspx?cite=480-90-238; An Act Relating to Reducing State Wide Greenhouse Gas Emissions, H.B. 1084; and Content of an Integrated Resource Plan, WAC 480-100-620 (Wash. 2021). https://app.leg.wa.gov/WAC/default.aspx?cite=480-100-620&pdf=true
Equity considerations, which could be included with more detail in a definition, could include whether assistance exists to help low-income customers transition to electrification and the availability of efficiency upgrades to decrease energy burden and facilitate an energy transition.
Legislation can either require the utility commission to open a proceeding to develop a joint electric and gas integrated resource plan or require a utility to file such a joint plan. A commission-led proceeding may enable commission regulatory expertise and inclusion of stakeholders. Where this option is not feasible, a utility-led filing requirement may require explicit stakeholder input and enable the commission to adopt, modify or reject a utility proposal.
This language enables the commission to modify the utility-filed plan rather than just accepting or rejecting the plan. This allows the commission to utilize regulatory expertise to make adjustments that enhance the public interest. Requiring findings to be made on the record provide insight into the commission’s decision-making process and can provide guidance in the event of any judicial review.
An Act Relating to Reducing State Wide Greenhouse Gas Emissions, H.B. 1084.
Phase III Decision Eliminating Gas Line Extension Allowances (2022), 22-09-026, Cal. P.U.C., Ruling No. 19-01-011 (2019). https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M496/K987/496987290.PDF
California Public Utilities Commission. (2022, September 15). CPUC decision makes California first state in country to eliminate natural gas subsidies [Press release]. https://www.cpuc.ca.gov/news-and-updates/all-news/cpuc-decision-makes-ca-first-state-in-country-to-eliminate-natural-gas-subsidies
California Public Utilities Commission, 2022.
An Act Relating to Reducing State Wide Greenhouse Gas Emissions, H.B. 1084.
Modifying the Regulation of Gas Companies to Achieve Reductions in Greenhouse Gas Emissions, H.B. 1766/S.B. 5668, 2022 Reg. Sess. (Wash. 2022). https://app.leg.wa.gov/billsummary?billnumber=1766&year=2022
Any expansion for industrial companies may also consider whether green hydrogen options are available and, if so, what the plans are to integrate green hydrogen.
For more information on the efficiencies of different types of electric heat see U.S. Department of Energy. (n.d.). Electric resistance heating. https://www.energy.gov/energysaver/electric-resistance-heating
Hill, D., & Neme, C. (2021, February 26). Rhode Island’s investments in gas infrastructure: A review of critical issues. Energy Futures Group. Exhibit DGH-3 attached to direct testimony of David G. Hill in New Hampshire Public Utilities Commission Docket No. DG 21-008. https://www.puc.nh.gov/Regulatory/Docketbk/2021/21-008/TRANSCRIPTS-OFFICIAL%20EXHIBITS-CLERKS%20REPORT/21-008_2021-10-06_EXH-9.PDF
The amortization limitations could be informed by any state legislation setting greenhouse gas reduction timelines or building electrification deadlines. More generally, the timeline should be considered in light of the expected useful life of gas infrastructure and anticipated electrification schedules in a particular area. Many states are also concerned about stranded assets and the burden carried by low- and moderate-income customers. States with older gas infrastructure may also need to consider requests for new infrastructure upgrades in the context of expected benefits from infrastructure upgrades. See, for example, Sargent, M. R., Floerchinger, C., McKain, K., Budney, J., Gottlieb, E. W., Hutyra, L. R., Rudek, J., & Wofsy, S. C. (2021, December 22). Majority of US urban natural gas emissions unaccounted for in inventories. Proceedings of the National Academy of Sciences. https://www.pnas.org/doi/10.1073/pnas.2105804118
Cowart et al., 2022.
Cosgrove, E. (2022, April 28). Policy tracker: Can a clean heat standard transition the fossil fuel industry? Northeast Energy Efficiency Partnerships. https://neep.org/blog/policy-tracker-can-clean-heat-standard-transition-fossil-fuel-industry
An Act Relating to the Clean Heat Standard, H. 715 (Vt. 2022). https://legislature.vermont.gov/Documents/2022/Docs/BILLS/H-0715/H-0715%20As%20Passed%20by%20Both%20House%20and%20Senate%20Official.pdf
Clean Heat Standard, S.B. 21-264, (Colo. 2021) (enacted). https://leg.Colorado.gov/sites/default/files/2021a_264_signed.pdf
For a more in-depth discussion of credit measurement, see Cowart et al., 2022.
Life cycle CO₂e analysis would also be required if renewable fuels or biofuels were included in a clean heat standard. There are scientifically determined values assessing the life cycle emissions of different types of fuel, differentiated by feedstock, location and other variables. Systems like the GREET and Global Trade Analysis Project (GTAP) models used by the California Air Resources Board and the U.S. Environmental Protection Agency could help to assign life cycle emissions values for any fuels deemed creditable under a clean heat standard.
See the discussion of life cycle emissions calculations in Cowart et al., 2022.
Farley et al., 2021.
Trabish, H. K. (2022, February 21). Utility regulators eye new tools to ensure equity efforts don’t impinge on other policy goals. Utility Dive. https://www.utilitydive.com/news/utility-regulators-eye-new-tools-to-ensure-equity-efforts-dont-impinge-on/618384/
Trabish, 2022.
The 16% value is higher than the portion of current fossil fuel sales going to low- and moderate-income customers because it represents the percentage of total clean heat credits that can be earned from residential, commercial or industrial customer projects. In other words, 16% might be less than proportional as a percentage of residential customer clean heat credits but is more than proportional relative to all sector fossil fuel sales.