25-16-NG

Key events and submissions in this proceeding include:

- June 28, 2024: Rhode Island Energy filed its most recent Long Range Plan (LRP), which provided the demand projection for the 2025 through 2028/29 heating seasons 1.
- May 12, 2025: The Energy Facility Siting Board (EFSB) issued a Decision and Order regarding the Narragansett Electric Company Aquidneck Island Gas Reliability Project (Old Mill Lane, Portsmouth, RI). This order included a requirement for analysis of demand-side alternatives as a condition for approving the company’s license application for the LNG storage and vaporization facility 1, 1.
- June 2, 2025: Pre-filed direct testimony (including analysis and findings on demand-side alternatives) was submitted by Daniel Aas on behalf of Rhode Island Energy in compliance with the EFSB’s decision and order 1, 1.

These are the primary dates and milestones explicitly referenced in the excerpts provided.

The primary stakeholders in this docket include:

- The Narragansett Electric Company d/b/a Rhode Island Energy (the utility company proposing and analyzing measures to address the Aquidneck Island gas capacity gap)
- The Rhode Island Public Utilities Commission (PUC, the regulatory body overseeing the docket)
- The Rhode Island Energy Facility Siting Board (EFSB, which ordered the demand side alternatives analysis as a condition of approving the LNG facility license)
- Environmental and community groups, including those representing environmental justice concerns, particularly in northwest Newport and west Middletown
- The Navy, as Rhode Island Energy’s largest customer on Aquidneck Island
- Rhode Island Division of Public Utilities and Carriers
- General public and ratepayers on Aquidneck Island and potentially statewide, who may bear costs or experience benefits/impacts

As for positions:

- Rhode Island Energy (and its consultants E3) concludes that, while there is technical potential for demand-side alternatives (efficiency, demand response, electrification) to close the gas capacity gap, these alternatives are not considered feasible in practice due to unprecedented required customer adoption rates and high net costs ($72 million to $125 million), and that the gap cannot be cost-effectively or reliably eliminated with these measures alone. Thus, the company supports the need for the LNG storage and vaporization facility at Old Mill Lane as necessary for system reliability 1, 1.
- The EFSB required a demand-side alternatives analysis but ultimately approved the LNG facility, indicating at least regulatory acceptance or support for the facility given the current reliability and feasibility challenges of alternatives 1.
- Environmental justice and equity concerns are raised about the distribution of costs and program benefits, with suggestions that additional incentives or compensation may be needed to address disparities, but no explicit position of support or opposition is stated for or against specific proposals in the excerpts 1.
- There is no explicit documentation in these excerpts of other stakeholders (such as advocacy groups, municipalities, or the Navy) directly supporting or opposing specific proposals.

In summary: Rhode Island Energy and, by extension, regulatory bodies appear to support the LNG facility as necessary for reliability, while acknowledging technical potential but practical infeasibility of alternatives. Other stakeholder positions (such as from advocacy groups or the Navy) are not clearly detailed in the provided excerpts. Equity concerns are acknowledged but not tied to a specific position on the proposals.

The docket identifies significant financial and timeline risks related to achieving sufficient demand reductions through demand-side alternatives (such as electrification, efficiency, and demand response) to address the Aquidneck Island gas capacity constraint.

Financial risks:
- Electrification and other demand-side measures carry high costs, especially in terms of upfront investments and incentives needed to drive customer adoption. Electrification, in particular, is described as expensive and may result in increased utility bills unless alternative cost allocation or rate mechanisms are implemented to manage bill impacts 1.
- Scenarios that rely heavily on electrification or prohibit new fossil fuel equipment are among the most expensive, especially under high customer uptake assumptions 1.
- The financial viability of portfolios is uncertain because avoided energy supply cost estimates (from sources like AESC) may not fully reflect recent policy changes or future market trends, leading to potentially higher costs than estimated 1, 1.

Timeline risks:
- Achieving the necessary scale and pace of customer adoption for electrification or other alternatives is described as "unprecedented via any set of policies, much less via utility incentive programs alone" 1.
- Even in high uptake scenarios, the capacity gap could not be closed until 2034 at the earliest. More moderate or realistic adoption rates would delay gap closure well past 2035, with some scenarios not closing the gap until 2048, 2040, or 2043, and the most conservative cases not until after 2050 1.
- The time required to achieve demand reductions is highly uncertain and depends on overcoming significant implementation barriers, including customer acceptance and market transformation 1, 1.

In summary, the main risks are that required demand reductions may not be achievable at reasonable cost or on the necessary timeline due to high financial barriers and unprecedented levels of customer participation needed for measures such as electrification 1, 1.

The docket identifies several areas of growth and key considerations related to each:

1. Electrification of Building Heating:
- Growth Area: Significant increase in the adoption of electric heating technologies, particularly cold-climate air source heat pumps, to replace gas-based heating and reduce peak gas demand on Aquidneck Island.
- Key Considerations:
- The pace and scale of customer adoption required for electrification to address the gas capacity gap by or before 2035 is described as "unprecedented" under any policy scenario, especially through utility programs alone. Even with high incentives, achieving necessary demand reductions by 2035 is unlikely in most scenarios 1, 1.
- While all 40 existing electric feeders on Aquidneck Island could accommodate peak loads from high levels of building electrification without immediate distribution system upgrades, localized upgrades may still be required if adoption is concentrated. Additionally, this analysis does not account for potential increases from full building or transportation electrification, and results may not generalize to the full service territory 1, 1.

2. Demand Response and Fuel Switching:
- Growth Area: Increased use of demand response programs, including installing or utilizing dual-fuel (gas and oil) heating systems in large commercial and industrial customers to shift demand away from peak periods.
- Key Considerations:
- In most scenarios, a significant share of demand reduction depends on substituting gas with other fossil fuels, such as heating oil, which can result in higher emissions compared to natural gas 1, 1.
- Emissions from increased fuel oil use are relatively small compared to the CO2 reductions from electrification and gas efficiency measures, but this strategy is less aligned with long-term decarbonization goals 1.

3. Gas Efficiency Measures:
- Growth Area: Deployment of efficient natural gas furnaces/boilers and building shell upgrades to reduce gas consumption.
- Key Considerations:
- Gas efficiency yields some emissions reductions and is cost-effective, but offers less annual gas displacement compared to electrification and does not eliminate reliance on fossil fuels 1.
- Efficiency measures are included in lower-cost portfolios, but cannot close the capacity gap alone 1.

Broader Considerations:
- Achieving sufficient demand reductions via any combination of these strategies within the next decade would require unprecedented customer participation and market transformation 1, 1.
- Emissions benefits are greatest with electrification, but the impact depends on the carbon intensity of the electric grid, which is expected to decline as Rhode Island targets 100% renewables by 2033. However, regional grid emissions may remain higher, affecting actual outcomes 1.
- Large-scale electrification would also require new firm electric generation capacity for reliability, especially for meeting winter peak heating demands, as renewables and storage may not fully suffice during periods of low renewable output 1.

In summary, growth is expected or targeted in electrification, demand response/fuel switching, and gas efficiency, but each faces significant feasibility, emissions, cost, and system impact considerations. The scale of required adoption is unprecedented and must be balanced with practicality, customer acceptance, policy alignment, and system readiness 1, 1.

This docket comprises an analysis conducted by E3 for the Narragansett Electric Company (Rhode Island Energy) in compliance with the Energy Facility Siting Board’s May 12, 2025, decision and order regarding the Old Mill Lane liquefied natural gas (LNG) vaporization facility in Portsmouth, RI. The analysis evaluates demand-side alternatives—specifically energy efficiency, demand response, and electrification—to address the capacity gap between natural gas supply and peak customer demand on Aquidneck Island.

Key elements of the docket include:

- E3 developed a supply curve-based model to assess individual and portfolio impacts of demand-side measures on gas demand reductions, emissions, and costs, using both societal and utility cost tests. Data sources included Rhode Island Energy’s customer data and public datasets such as the AESC 2024 report and technical analyses from the “Future of Gas” docket 1, 1.
- Measures evaluated focused primarily on space heating, which accounts for 93% of peak day residential gas demand. Three categories were modeled: high-efficiency gas devices, electrification (mainly cold climate air source heat pumps), and demand response via dual fuel boilers, each with different impacts on cost, GHG emissions, and feasibility 1.
- The analysis concluded that energy efficiency alone cannot close the capacity gap cost-effectively or reliably; electrification provides the largest, most durable peak demand reductions but faces high costs and uptake challenges. Demand response programs have persistence and emissions risks. Portfolios combining these measures are necessary, but all require unprecedented levels of customer adoption 1, 1.
- Equity impacts were considered, with environmental justice areas on Aquidneck Island potentially less likely to benefit from these portfolios without targeted incentives 1.
- The docket also compares this analysis to a 2020 National Grid study, noting differences in demand forecasts, electrification assumptions, and cost estimates 1.

The overall finding is that closing the gas supply gap on Aquidneck Island will likely require significant electrification, supported by efficiency and demand response, though all approaches face practical and financial barriers. The availability and scalability of renewable gases were not included in the scope of this analysis 1.